Our June 2022 Clean Energy and Sustainability Group Newsletter included a status report on the Application of Public Service Company of Colorado for approval of its 2021 electric resource plan (“ERP”) and clean energy plan (“CEP”) in proceeding No. 21A-0141E (the “Application”). At the time of the writing of that status report, the Colorado Public Utilities Commission (the “Commission”) had held its first deliberations meeting, on March 14, 2022, to consider the Application. Additionally, an Updated Non-Unanimous Partial Settlement Agreement had been filed on April 26, 2022 (the “Updated Settlement”), and an evidentiary hearing held on May 17, 2022 on the Updated Settlement.
Since that time, the Commission worked through the issues in the Application in deliberations held on June 10, 2022, June 15, 2022, and June 22, 2022 resulting in a written Phase I Decision issued on August 3, 2022 (the “Phase I Decision”).
Requests for rehearing, reargument, or reconsideration (“RRR”) have been filed as to certain parts of the Phase I Decision by Public Service, Trial Staff, the Colorado Independent Energy Association, and Interwest Energy Alliance. Once the Commission reaches its decisions on the RRR requests, the Phase I Decision, as modified by any decision on RRR, will be the final decision of the Commission. The final decision can be appealed to district court (§ 40-6-115, C.R.S.) but, unless the final decision is stayed, Phase II of the proceeding will begin. The Phase II process is as follows:
- Public Service will make any modifications required by the Commission’s Final Decision and get set up to conduct an all source competitive solicitation to fill the resource need approved in the Commission’s Phase I Decision. Then Public Service will issue a request for proposals.
- Bidders will have 90 days within which to submit their bids in accordance with the detailed instructions in the RFP bid package. Submittals include competitive bids by independent power producers (“IPPs”) and utility-owned proposals.
- Public Service will then have 120 days to review and evaluate the bids and submit to the Commission a report (the “120-Day Report”) presenting an evaluation of the proposed resources, based on the criteria established in the Phase I Decision regarding modeling inputs and assumptions to be used in developing optimized resource portfolios and the sensitivities that “re-price” optimized portfolios using alternative values for selected inputs and assumptions.
- The Independent Evaluator (“IE”) files its own report within 30 days after the filing of the 120-Day Report. The IE Report contains an analysis of whether the utility conducted a fair bid solicitation and bid evaluation process.
- Within 45 days of the filing of the 120-Day Report, the parties in the resource plan proceeding may file comments on the utility’s report and the IE report.
- Within 60 days after the filing of the 120-Day Report, Public Service may file comments responding to the IE’s report and the parties comments.
- Within 90 days after the filing of the 120-Day Report, the Commission shall issue a written decision approving, conditioning, modifying, or rejecting the utility’s preferred cost-effective resource plan, which decision shall establish the final cost-effective resource plan.
- Public Service is then required to pursuant the final cost-effective resource plan either with a due diligence review and negotiation of purchase power agreements (PPAs) for IPP bids or with applications for certificates of public convenience and necessity (CPCNs) for utility-owned bids.
Modeling results in the Phase I proceeding, based upon generic resources, indicated the following resource acquisitions through 2030:
- The Updated Settlement proposed that the resource needs in 2029 and 2030 would not be filled through the Phase II competitive solicitation. Instead, generic resources would be used for 2029 and 2030 in the modeling of the Phase II bids. The 2029 and 2030 resource needs would be filled through the Pueblo Just Transition Plan competitive solicitation (an interim ERP to be filed in 2024).
But Phase I modeling results do not predetermine the Phase II final cost-effective resource plan. The final resource plan will be based upon the proposals received in the competitive solicitation and, therefore, the types and sizes of resources acquired, and the cost and timing of those acquisitions will differ from the Phase I results that were based upon the modeling of generic resources.
The Phase I Decision is 186 pages long and resolves numerous issues including some very technical modeling issues. The following is a high-level summary of the main provisions of the Phase I Decision pertaining to specific types of facilities (coal, wind, solar, storage, and gas) and certain other major provisions of the Phase I Decision. Some of the decisions summarized below are subject to change in the Final Decision on the RRR requests.
Key ERP and CEP Proposals
As required by statute, 40-2-125.5(4), C.R.S., Public Service’s application included a clean energy plan to reduce the Company’s carbon dioxide emissions by a target of 80 percent by 2030 as compared to 2005 levels. The Application and the Phase I Decision distinguish between ERP resources and CEP resources. ERP resources are those resources needed to address the Company’s resource needs through 2030. CEP resources are those activities designed to achieve the 2030 carbon dioxide emissions reduction requirement of 80%.
The Phase I Decision approved the following proposals for early retirement of coal plants as part of the electric resource plan:
- Early retirement of Craig in 2028
Early retirement of Hayden 1 in 2028
Early retirement of Hayden 2 in 2027
The Phase I decision approved the following activities as part of the clean energy plan:
- Conversion of the Pawnee generating station from coal to natural gas no later than January 1, 2026
- Early retirement of the Comanche Unit 3 coal plant no later than January 1, 2031 (with operations ratcheting down starting on January 1, 2025)
The Phase I Decision found that the coal action plan for Comanche Unit 3 not only helped achieve the clean energy target of 80 percent emissions reductions by 2030, but also makes progress towards the 2050 goal of 100 percent clean energy.
The Phase I Decision notes that several of the statutory findings required to approve a CEP cannot be made until Phase II. For example, the Commission must wait until Phase II to know the actions and investments required to fill the additional resource need for the CEP, the projected cost to implement the CEP, and the cost and rate impact of the 50% utility ownership target. But, the Commission states that the Phase I Decision provides the framework in which bids will be evaluated and selected, sets the Phase II assumptions regarding the treatment of the Public Service remaining coal-fired power plants, and ensures that the 120-Day Report contains the information required to make the statutory findings necessary to approve a CEP. The Commission does not anticipate another fully litigated hearing in Phase II. Instead, the Commission will address the necessary statutory findings in its Phase II decision after the typical Phase II process.
Timing of Resource Acquisitions
The Phase I Decision approved an Updated Settlement term providing that Public Service will allow bids with in-service dates as early as 2023, provided the bids are viable and the applicable construction timelines are reasonable.
Pueblo Just Transition Plan
The Comanche Unit 3 is located in Pueblo County, Colorado. It is the newest coal plant on the Public Service system and was expected to be in service until 2070. The early retirement of the Comanche Unit 3 has both job and tax impacts on the Pueblo community. The Updated Settlement included the following Pueblo Just Transition Plan:
- While the upcoming Phase II solicitation will be for the resource acquisition period of 2021 through 2030, Public Service will not accept bids for or acquire any resources with in-service dates after December 31, 2028. Instead, the Company will use generic resources in 2029 and 2039 in its modeling for purpose of the final approved plan in Phase II. All 2029 and 2030 resource needs identified will be filled through the Pueblo Just Transition Plan solicitation which will use a resource acquisition period of 2029 through the end of 2031.
- Public Service will continue to make payments to Pueblo County annually from 2031 through 2040 (and allocated by the treasurer’s office accordingly) in the amount of the projected lost property tax revenues for those years, unless offset by property tax revenues from generation or transmission infrastructure sited at Comanche Station or within Pueblo County.
- A separate Comanche 3 Just Transition Plan is to be filed with the Commission no later than June 1, 2024. Through its Just Transition Plan filing for Comanche 3, the Company will conduct a standalone Just Transition Plan competitive solicitation for the replacement of the energy and capacity associated with Comanche 3. This process will occur on a standalone basis in an effort to ensure the Pueblo community and benefits to the community are the focus of the replacement portfolio, simultaneously seeking just transition benefits and the procurement of innovative technologies to help the Company progress toward a carbon- free future.
- Public Service will own, at a minimum, $690 million in capital investment or 500 MW of accredited capacity, whichever is triggered first, for resources necessary to replace the accredited capacity of Comanche 3, provided that a showing of resource need is made in the first phase of the Comanche 3 Just Transition Plan filing and any final approved plan in the second phase must be deemed a cost-effective resource plan consistent with Rule 3601 and Rule 3617 after a full consideration of the just transition and emissions reduction benefits of the plan.
- The Just Transition Plan solicitation will also utilize a utility ownership target of 50 percent for energy and capacity acquired that is in excess of the $690 million investment or 500 MW accredited capacity minimum, and provided that the final approved resource plan is cost- effective as set forth above.
The Phase I Decision approved the Pueblo Just Transitions Plan.
Best Value Employment Metrics.
The Updated Settlement included a multistep process for Phase II bid evaluation to ensure Best Value Employment Metrics (“BVEM”) as required by Colorado law. Bidders are required to include quantitative information with their bids concerning all BVEM requirements or, if the contracts for the project which is bid are not yet completed, the Bidders shall include the standards the Bidders include in their requests for proposals to be issued to subcontractors related to BVEM metrics, or if any of the quantitative information cannot be provided, bidders shall explain why as part of their bid package. A bid that incorporates a Project Labor Agreement will automatically be considered to meet threshold BVEM standards. Public Service will conduct an initial screen of BEM and disqualify bids that do not provide sufficient BVEM. Public Service will retain a labor economist to assist in scoring bids for BVEM. As part of its 120-day Report, the Company will provide a cumulative BVEM score for each portfolio presented. The Phase I Decision approved these terms.
Social Cost of Carbon to be Considered in Phase II Modeling
After Public Service filed its Application, the Colorado General Assembly adopted a statute requiring utilities to consider the social cost of carbon when determining the cost, benefit, or net present value in electric resource plans. § 40-3.2-106, C.R.S. In Decision No. C21-0246, the Commission stated that the 120-Day Report in Phase II will require (1) the utility to apply the cost of carbon dioxide emissions to the existing and new resources, (2) the presentation of net present value of revenue requirements that include the cost of carbon dioxide, and (3) the calculation of the net present value of the total cost of the carbon emissions. The Phase I Decision approved the Updated Settlement proposal to tie the social cost of carbon value and discount rate to the levels established by the Interagency Working Group Technical Support Document.
Energy and Capacity Rates for Solar + Storage Proposals
For solar + storage proposals (i.e., “hybrid resources”) submitted in Phase II, the Company proposed to offer an energy-only rate. Intervenors argued that there should be both an energy payment for the solar resource and a capacity payment for the storage resource. Public Service argued that an energy payment for the solar resources and a separate capacity payment for the storage resource would create finance lease and imputed debt issues which have a negative financial impact on the Company.
The Phase I Decision acknowledges that the finance lease and imputed debt issues articulated by Public Service are a real concern that needs to be considered but that energy-only payments for storage will significantly increase bid pricing and customer costs. To address these competing concerns, the Phase I Decision directed Public Service to follow the approach taken in New Mexico that allows solar + storage projects to be bid under two separate PPAs (one for the solar energy portion and the other for the storage portion). For the storage component, the bidder can bid either on an energy or capacity basis. If capacity is bid, however, the lease term is limited to 18 years to keep the lease terms under the 75% threshold for creating a capital lease (assuming a 25-year useful life).
The 18-year PPA term limitation for hybrid solar + storage projects is the subject of pending requests for RRR.
Standalone Battery Storage Bids.
Public Service asserted in its Application that PPAs for stand-alone battery storage could potentially be categorized as finance leases, and credit rating agencies view finance lease obligations in a more punitive manner, negatively impacting debt-to-capitalization ratios and putting stress on the Company’s credit Rate. To address this concern, the Model PPA for standalone storage states that Public Service is unwilling to be subject to the accounting treatment that results from the classification of a PPA as a finance lease and, therefore, requires that the PPA payments not exceed 90% of the value of the asset and limit the PPA term so as not to exceed 75% of the useful life of the asset (the “90/75 limitation”). The Phase I Decision prohibits the 90/75 limitation for standalone storage while, at the same time, acknowledging the Company’s concerns are legitimate and should not be ignored. The Decision states that the Commission has other tools at its disposal to holistically address the Company’s financial health.
This provision of the Phase I Decision is the subject of Public Service’s pending request for RRR.
Bids Proposing Interconnection at the Points of Delivery of Existing Generating Units Prior to Scheduled Retirement
The Phase I Decision directs Public Service to revise its RFP documents so that third-party bids can be proposed for interconnection to the same point of delivery as existing generation units prior to their scheduled retirement, subject to operating restrictions, special protection, or remedial action schemes to avoid potential overloads. These operating restrictions might increase the times in which the new project is curtailed and the Phase I Decision states that the generator will not be eligible for curtailment credits until the existing coal facility is retired and the new facility can alter its transmission service to firm. The Phase I Decision expressly states that this ruling in no way interferes with the property, land, water rights, and other broader private assets associated with Company-owned generation units and the decision is for purposes of evaluating bids in Phase II and does not resolve or opine on whether the Company’s Open Access Transmission Tariff (“OATT”) prohibits IPPs from using the existing transmission facilities for replacement generation.
These provisions of the Phase I Decision are included in Public Service’s request for RRR. Public Service explains the provisions of its OATT in detail, explains how it is reading the Commission’s Phase I directives (i.e., not to require the Company to violate the restrictions on generator replacement contained in the OATT nor other requirements of the OATT), and states that it is providing the information in the form of a RRR request to allow the Commission to determine if any modification to the Phase I Decision is necessary.
Not All Bids Advanced to Modeling
The Phase I Decision approves the Company’s plan to forward all Public Service bids to the modeling process. In contrast, IPP bids go through a screening process and not all are advanced to computer modeling.
Settlement Parties to be Reconvened to Make Changes to the Model PPAs to Reflect Changes in Tax Credits
The Phase I Decision approves the Updated Settlement provision that in the event of an extension or change in eligibility of the Federal Production Tax Credit/Investment Tax Credit program, the Settling Parties will be re-convened to attempt to make conforming changes to the model PPAs unanimously and take any other actions made necessary by the change in law. If unanimity cannot be achieved, the Company will bring such matters to the Commission for Resolution. The Inflation Reduction Act has triggered this provision of the Updated Settlement.
Modified Wind Committed Energy Requirements Approved
The Company’s Application proposed changes to the model PPA that establish committed energy requirements in which PPA wind projects would be penalized if they failed to deliver a certain percentage of energy. Public Service explained that the modifications were made to ensure that bidders can deliver on the representations they make in their bids and because it is becoming increasingly important that the energy promised from IPPs is the energy that will be delivered. The Updated Settlement modified the committed energy requirements for wind PPAs so that wind developers bear less weather risk. The Phase I Decision approved these modified provisions.
Use of Wind and Solar Integration Costs and Storage Credits to Be Discontinued
Public Service filed a Wind and Solar Integration Cost Study with its Application to evaluate three components of integration costs: 1) impacts on electric system regulation; 2) impacts on electric system operation given uncertainty in wind and solar forecast generation versus actual generation; and 3) impacts on the Company’s gas supply/storage system. Historically, integration costs have been used as an adder to the cost of wind and solar bids and as a credit to storage bids. Several parties objected to the continued used of integration costs. The Phase I Decision acknowledges that integration costs are real but concluded that continued use is discriminatory because there is no information in the record regarding integration costs associated with other resources such as thermal resources. Additionally, the Commission agreed with one party’s position that Public Service’s imminent participation in a EIM (energy imbalance market) would likely substantially reduce integration costs. (Public Service will be joining the Southwest Power Pool’s energy imbalance market and expects to do so in April 2023.) The Phase I Decision directs Public Service to discontinue the application of integration costs.
Phase I Decisions Concerning Gas-Fired Electric Generation
Currently, the primary technology to back up wind and solar resources is natural-gas fired generation. The Phase I Decision approves the Updated Settlement proposal that Public Service re-bid any existing gas units that are scheduled for retirement in the resource acquisition period so long as the retirement is not required pursuant to the Colorado State Implementation Plan and the unit can reasonably be expected to perform in a manner that balances the Company’s system. The Phase I Decision also approved the following provisions from the Company’s Application regarding gas units bid into the Phase II solicitation but with the modifications noted below:
- Bidders of new gas units will be encouraged to submit bids with an option for the unit to burn a minimum of 30% hydrogen. This is a clean energy plan proposal to make progress toward the 2050 target of 100% clean energy. In the Phase I Decision, the Commission added that bidders are encouraged, on a voluntary basis, to also report the maximum hydrogen mixing capability of their units in order to provide information regarding where the market is at and whether it provides a pathway to achieve the state’s 100% clean energy target by 2050.
- The Company must be able to remotely start simple cycle facilities at all hours.
- Any new, repowered, or rebid generating units within a plant must be able to start simultaneously.
- A unit must be able to start on either natural gas or fuel oil at the Company’s election and switch between fuel oil and gas without interruption.
- Simple-cycle generators must be capable of starting within ten minutes (fast start capability).
- Bids must include a plan to have fuel and any ancillary product on site necessary to permit the facility to run continuously for a minimum number of hours at maximum load on alternative fuel, or have firm gas transportation contracts that could serve as a substitute for the requirement to have an alternative such as fuel oil on-site. In its Application, Public Service proposed that the minimum run time be 72 hours but at hearing, Public Service testified that this 72-hour period reasonably could be extended to four or five days given what happened during Winter Storm Uri. In the Phase I Decision the Commission concluded that the must run capability on alternative fuel should be at least five days.
The Phase I Decision requires Public Service to be flexible as to the application of these requirements to existing gas units that are re-bid into the upcoming competitive solicitation. The Decision states that, “the Company should use good judgment when it evaluates the rebid of existing gas units to enable the continued use of these units over the construction of new units wherever possible.” The preference for existing gas units over new gas units is to reduce the risk of stranded costs for new units in the event alternative technologies, such as utility scale storage, are developed in the future that can replace gas-fired electric generation as the primary backup resource for wind and solar resources.
The Phase I Decision approves a provision in the Updated Settlement that Public Service would include in its Phase II modeling a “No New Natural Gas Build Portfolio.” The modeling would evaluate only existing rebid Public Service facilities and proposals for extension of third-party PPAs. The Commission acknowledged the language in the Updated Settlement that this portfolio may be infeasible or fail the Company’s reliability check. In such event, the Phase I Decision requires the Company to report this in its 120-Report.
Social Cost of Methane
Several parties argued in the Phase I proceeding that the Phase II modeling should evaluate the social cost of methane. A new statute, 40-3.2-106(1), C.R.S., adopted after Public Service filed its Application, requires the Commission to consider the social cost of carbon dioxide emissions and the social cost of methane. In the Phase I Decision, the Commission concluded that it had the authority to consider the social cost of methane under its broad “public interest” authority to consider reductions in carbon dioxide and other emissions even without application of the new statute.
The Commission directed Public Service to create a social cost of methane sensitivity for the Phase II preferred portfolio that shows the net present value of the revenue requirement (NPVRR) of the social cost of methane. The Company was directed to use the EPA emissions factors to calculate downstream methane emissions (for the combustion of fossil fuels). For the upstream emissions that occur during the production, processing, transportation, and storage of natural gas, Public Service was directed to craft a methodology using an emission factor of between 1% and 0.25%. The Phase I Decision sets the social cost of methane for at least $1,756 per short ton of methane but states that the ultimate SCM value and discount rate shall be tied to the most recent value and discount rate established by the Interagency Working Group Technical Support Document. Note that this sensitivity is limited to gas-fired electric generating resources. Upstream emissions associated with coal mining, and the mining, manufacturing, transportation, and construction of renewable resources are not included in the Phase II modeling.
Responsibly Sourced Gas
In its Application, Public Service asked for party input on the costs and benefits of pursuing, in the future, obtaining natural gas associated with new gas-fired electric generation from “certified” or “responsibly-sourced” natural gas sources (“RSG”). However, Public Service was not proposing a responsibly sourced gas requirement in the proceeding or seeking any Commission approvals relating to responsibly sourced gas. One party requested that the Commission hold that Public Service should not require ratepayers to pay a premium price for responsibly sourced gas. In the Phase I Decision, the Commission declined to make any broad pronouncements regarding RSG and said it would defer expressing an opinion until an appropriate future proceeding in which the Commission is being asked to adjudicate an issue.
Section 123 Resources
Section 123 resources are defined to mean “new energy technology or demonstration projects, including new clean energy or energy-efficient technologies” under § 40-2-123(1)(a), C.R.S. and § 40-2- 123(1)(c), C.R.S., and Integrated Gasification Combined Cycle projects under § 40-2-123(2), C.R.S. The Phase I Decision recognized that for a resource bid into Phase II to be considered a Section 123 resources, it must be new, innovative, not commercialized technology, and provide unique, scalable, and beneficiation attributes as to future costs, emissions reduction, or reliability benefits. Standalone wind, solar, or lithium-ion based battery storage of any duration and any combination of those technologies together with other resources are not Section 123 Resources.
Public Service was directed to group Section 123 bids by technology and cost and forward them to modeling for portfolio re-optimization and presentation in the 120-Day Report with the least-cost Section 123 bids by technology “locked in.”
Pre-Construction Development Assets
The Phase I Decision states that, as compared to prior electric resource plans, this Phase I proceeding and record show “perhaps an unprecedented amount of uncertainty.” As examples, the Decision points to uncertainty regarding peak demand and energy forecasts; the potential impact of changing climate patterns and extremes during peak times that might reduce hydroelectric output, decrease the availability of thermal units and their fuel, or materially limit generation from solar and wind resources; and other factors such as supply chain disruptions, inflation, rising interest rates, and solar tariffs. The Decision found that, “material risk remains that Public Service’s system may need more capacity sooner because of extreme weather, extended unit unavailability, or an inability to build some of the gas combined cycle (CT) resources selected out of Phase II. Under any of these circumstances, it could take a year to run an acquisition process and at least three years to build additional CTs.”
As a means to address planning uncertainty and unexpected circumstances, the Phase I Decision requests that the Company explore acquiring pre-construction development assets for wind, solar, storage, and CT resources but avoid building the projects now. Instead, the Company would finish development of these pre-construction assets over time and then potentially bid these projects into the all-source 2024 Pueblo Just Transition solicitations. The Phase I Decision also encourages Public Service to provide, concurrent with the 120-Day Report, updated contingency planning proposals that would include any bids for preconstruction development assets. The pre-construction development assets could be either Company-owned or IPP-owned.
The provisions of the Phase I Decision regarding pre-construction development assets are the subject of pending requests for RRR.
The Phase I Decision approves the Updated Settlement proposal that the next regularly-scheduled ERP shall be filed no later than October 31, 2026. (The Pueblo Just Transition Plan is an Interim ERP.) The Decision states that Public Service may request a variance if future circumstances warrant a change.
Not There Yet – Other Items in the Pending Requests for RRR
The summary above notes which items are the subject of the pending RRR requests. But, the RRR requests also concern other provisions of the Phase I Decision not summarized above including:
- A Deferred Tax Asset forecast the Commission directed Public Service to submit after working with Staff to evaluate alternative DTA modeling methods. The concern is Public Service-owned facilities for which Public Service was not, under the prior production/incentive tax credits, able to take the credits. The Trial Staff is seeking in its request for RRR to provide for the exchange of workpapers and other explanations and for a process to resolve irreconcilable disagreements. Public Service, on the other hand, states in its request for RRR that this issue may be resolved by provisions of the Inflation Reduction Act.
- The Updated Settlement Agreement provides for a performance incentive mechanism (“PIM”) stakeholder process. Public Service requests in its RRR that the Commission make certain modifications to its Phase I Decision directives pertaining to this process.
- Public Service requests a modification to the Phase I Decision as to cost recovery mechanism for prudently incurred, investigatory costs associated with the Unaweep Project, a potential pumped storage hydropower project on the Western Slope.
- Public Service requests modification to the Phase I Decision requirements concerning the planning reserve margin study to be submitted as part of the Pueblo Just Transitions Plan. Specifically, Public Service requests modifications to the requirement for it to model all WECC regions.
- The Phase I Decision required Public Service to report certain information regarding its water rights. Public Service has proposed in its request for RRR two options for how it might do the reporting and asks that the requirement to value water rights as part of the reporting be removed. Public Service notes that historic consumptive use is the driver of any valuation exercise and this is a nuanced, fact-drive analysis, and is most often the root of contested litigation in Colorado’s Water Courts.
- The Phase I decision deferred decision on two renewable energy standard adjustment (RESA) issues. Public Service requests in RRR that the Commission to construe the currently pending Proceeding No. 21A-625EG as the appropriate RES plan proceeding for resolution of these issues. Public Service also puts the Commission on notice in its request for RRR that it would like to implement the CEP cost recovery provisions (the “CEPR”) as soon as possible after the Phase II decision and no later than January 1, 2024.
- In its request for RRR, Public Service seeks Commission approval that it is appropriate to account for the passage of the Inflation Reduction Act in its generic resource costs presented in the inputs and assumptions filing to be made prior to commencing the Phase II competitive solicitation.
- Public Service seeks clarification from the Commission regarding the authorization given to it in the Phase I Decision to place coal units into temporary economic shutdown outside of a rate case. Public Service is asking whether the Commission anticipates questioning, or allowing intervenors to question, cost recovery for units that were in temporary economic shutdown, stating that, if so, the Company would need to take that into account in its decision-making process.
- Public Service seeks confirmation that the project level analysis for transmission costs it is required to develop on the truncated 120-Day Report timeline is to be done in a manner similar to previous presentations where the Company will use its best efforts to categorize general areas of anticipated transmission costs unknown at the time, with the understanding that additive transmission studies are necessary to determine the full extent of the transmission investment necessary to implement a portfolio.
- The Phase I Decision approved a provision of the Updated Settlement concerning the use of the social cost of carbon in dispatch or commitment of resources pending FERC approval. Public Service seeks confirmation that if market rules permit it to continuing using the social cost of carbon in the dispatch or commitment of resources, assuming FERC approval of any such approach, it is required to continue using the SCC value in the dispatch or commitment of resources and that such use is consistent with the Phase I Decision.