During the June 24, 2021 meeting of the Regional Expansion Criteria & Benefits Working Group (RECBWG) stakeholders were invited to submit feedback on the FERC approved Tariff provisions from MISO and other Regional Transmission Owners (RTOs) that might be pulled over into what is included in the Tariff for LRTP projects related to Future 1 and MTEP21.
The deadline to submit feedback is set for July 9.
Alliant Energy Comments on LRTP Cost Allocation
Background
During the June 24, 2021 meeting of the Regional Expansion Criteria & Benefits Working Group (RECBWG) stakeholders were invited to submit feedback on the FERC approved Tariff provisions from MISO and other Regional Transmission Owners (RTOs) that might be pulled over into what is included in the Tariff for LRTP projects related to Future 1 and MTEP21.
Alliant Energy Comments
Alliant Energy supports using MISO’s existing MEP tariff provisions for the criteria and cost allocation of LRTP projects related to Future 1 and MTEP21. The current MEP project criteria and cost allocation has been developed over many years which has resulted in improvement and refinements to be implemented. Rather than trying to create a new cost allocation category, MISO should rely on this existing and FERC approved tariff provision.
MISO has provided that LRTP projects are intended to focus on enabling a changing resource portfolio, maintaining reliability and ensuring an efficient regional and interregional transmission system. Considering this, APC and reliability should capture and drive most benefits from this transmission development. The MEP project category captures the primary benefits as transmission system demands and energy flow patterns change from a shift to more renewable resources. For example, MEPs identify and quantify areas that are benefiting from access to lower cost generation and identify the benefits flowing to existing generation from increased revenues. Further, MEPs now include avoided reliability projects as a benefit metric.
Alliant Energy opposes trying to combine the MEP and MVP project categories in some manner. Attempting to cobble together a LRTP project criteria and cost allocation from these two project types would create a path for benefits to be either double counted or create insufficient assurance to customers that the estimated benefits will be realized.
The MEP project category strikes a balance between proactive transmission planning and identifying benefits and beneficiaries that can be relied on to justify projects and allocate costs. Going beyond this project type to either combine MEPs with other projects categories or, for example, identifying new ways to measure reliability places too much speculation into the planning and cost allocation process. This approach also creates a higher risk of identifying unneeded projects and customers bearing unjust and unreasonable costs.
Going forward, Alliant Energy does support further conversation regarding how LRTP project costs could be allocated to generators. Given the difficult nature of this topic, it will likely take an extended amount of time to review, discuss and determine the viability of potential methods to allocate costs to generators.
WEC Energy Group recommends that MISO and stakeholders consider the Shared Network Upgrade (SNU) concept within Attachment X to the MISO tariff as a mechanism to address the allocation of LRTP costs to Interconnection Customers (ICs). An objective of the LRTP initiative is to reliably support the “goals and policies in the Futures” and the integration of renewable resources within an evolving resource fleet. As ICs move through the interconnection queue and receive benefit from LRTP projects, a concept such as the SNU can quantify those benefits and assign costs in proportion to those benefits.
ENVIRONMENTAL SECTOR COMMENTS TO RECBWG - JULY 9, 2021
Summary of Environmental Sector Proposals:
Explanations and citations are provided below the summary.
| Summary of Environmental Sector’s Proposal | Source |
Voltage Threshold | 100 kV | MVP |
Cost Threshold | $ 5 million | MEP |
Planning Threshold | Projects result from long-range scenario planning, looking 20-40 years into the future | MEP-like |
Meets One of Three criteria |
| MVP-like |
Benefit Metrics – Types | Any financially quantifiable benefit to transmission customers that is transparent and replicable. This will necessarily include all benefit metrics that are already included within the MVP and MEP tariffs but would exclude any duplicative items or items that would result in the double counting of benefits. | MVP and MEP |
Benefit Metrics – scope of benefits measured | 40 years | SPP |
Cost Distribution | Two Options for Distributing Costs Option 1: Postage stamp all costs on a subregional basis; or Option 2: Original Certain TO Proposal presented on 4/28/21 on Slide 10[1], viz. quantify the economic benefits and allocate them to the relevant beneficiaries; for any remaining costs that have not been allocated, assume they pertain to regional reliability benefits and apply a subregional postage stamp. | Option 1: MVP-like Option 2: Combination of MEP and MVP |
Subregions for Postage-Stamp Cost Distribution | MISO North and MISO South would be the subregions. | MVP-like |
Project Hierarchy | LRTP trumps BRPs and MEPs; MVPs trumps LRTPs | MVP-like |
OPENING STATEMENT:
MISO says MISO’s current regional cost allocation – the MVP tariff – will not be applicable to the LRTP, because LRTP will not include a region-wide portfolio of projects as “portfolio” is defined in the MVP tariff.[2]
Under Order 1000, MISO is required to have a regional cost allocation that can apply to regional reliability projects. Order 1000 ¶ 689. Because there is no applicable regional cost allocation for LRTP projects, to comply with Order 1000, MISO must create a new regional cost allocation for the regional reliability projects arising from LRTP. In short, simply saying “no” to a new cost allocation is not an option for MISO or its stakeholders and would be a violation of FERC Order 1000.
THRESHOLD CRITERIA TO QUALIFY FOR THE LRTP PROJECT TYPE[3]:
MEET AT LEAST ONE OF THE FOLLOWING ADDITIONAL CRITERIA:
4.A. A definition similar to MVP Criterion 1[4] but expanded to include the focus of LRTP, viz. achieving goals set forth in state and utility plans that are captured in the Futures used for scenario planning including the ability to reliably deliver energy produced by certain types of generators over, at least, large subregions of MISO; 4.B. Economic savings across multiple pricing zones with a benefit to cost ratio of 1.0 or higher, which is similar to MVP Criterion 2[5]; OR
4.C. A definition similar to MVP Criterion 3[6] but without the economic requirement because the focus of LRTP is the reliable delivery of energy while accommodating a dramatic change in the generation portfolio. This criterion should articulate one or more projected violations of a NERC or Regional Entity standard arising from the transformation of the generation portfolio as captured in the Futures used for scenario planning. The reason we are removing the B/C requirement is because fixing reliability violations must be done regardless of cost. As the generation portfolio transforms throughout the MISO footprint, there may be discrete grid fixes that must occur regardless of whether that specific remedy pencils out by itself.
PROJECT HIERARCHY:
BENEFIT METRICS:
A. Application of Benefit Metrics (BMs): BMs are used for two purposes in MISO tariffs:
Given that stakeholders have vigorously argued that the evaluation of LRTP benefits should be “as granular as possible,” [8] the Environmental Sector proposes to use the following MVP tariff language: “Any other financially quantifiable benefit to transmission customers.” See Attachment FF § II.C.5.e. The Sector proposes to include the following additional limitations. Benefit Metric calculations should be:
MISO already has numerous BMs that it applies and the Environmental Sector proposes to use all of those metrics as long as they do not result in double counting. The following lists the existing MISO BMs:
(1) MEP Methodology: Attachment § FF-7, I.A.
(2) MVP Methodology: Attachment FF § II.C.5.a.
MISO limits its economic benefit calculations to 20 years, but given that these projects have an asset life of 60 or more years, failing to capture the benefits beyond 20 years results in omitting projects that would save ratepayers money. While the Environmental Sector believes the best approach is to calculate the benefits for the depreciable life of the project, we would accept the SPP approach that uses a 40-year economic benefit metric.[10]
DISTRIBUTION OF THE COSTS FOR LRTP PROJECTS:
The false accuracy of a granular distribution of costs for regional projects: throughout this stakeholder process we have heard many argue that benefits—and the attendant distribution of costs tied to those benefits—should be calculated at the most granular level possible. However, such an approach does not reflect how benefits will change over time while simultaneously adding to MISO’s administrative burden. Thus, the goal of more granular distribution of costs does not result in a more accurate distribution of costs especially when dealing with large regional lines like the MVPs or LRTP projects. Further, granular distribution is not required under FERC Order 1000. FERC Order 1000 states that the distribution of costs only needs to be “roughly commensurate” with benefits which provides the needed standard and guideline for the process of assessing benefits in a timely transmission planning process. Order 1000 ¶ 622.
1. Economic Benefits: While the economic benefits from good transmission expansion is undeniable, quantifying those benefits with accuracy is sometimes not possible because of limitations in our modeling tools.
When MISO calculates the economic benefits used for cost distribution for a proposed project, it calculates it only once when the project has met the threshold criteria for a project type based on the assumptions in the models at that time (a snapshot in time). Economic benefits are fundamentally dependent on, among other things, power flows, the generation and transmission topology at that time, and the usage of the system over 8,760 hours of a year. The moment these assumptions change, the economic benefit calculations and the beneficiaries change. To be clear, the economic benefits do not go away—only the beneficiaries receiving those economic savings may change.
To overcome the reality of ever-changing beneficiaries due to ever-changing system conditions, when developing the MVPs, we spent 18 months developing a methodology that would have been trued up every few years. However the stakeholders rejected that methodology and instead opted for a region-wide postage stamp, in part, because the utilities preferred predictability in their costs. The MVP stakeholders believed that distributing costs on a region-wide postage stamp sufficiently reflected the benefits received from the portfolio of MVPs. The 7th Circuit agreed, concluding that “It's impossible to allocate these cost savings with any precision across MISO members.” ICC v. FERC, 721 F.3rd 764 , 774 (7th Cir. 2013).
The Environmental Sector does not have any evidence to suggest that identifying the beneficiaries based on a one-time snapshot of who is receiving the economic savings (quantified before projects are even built) is more accurate than assuming that the LRTP regional lines provide broad economic benefits over the 60-year life of a project. In other words, the Environmental Sector believes that for the LRTP regional projects a postage-stamp approach is just as accurate, if not more accurate, than distributing costs on a granular, snapshot basis.
2. Reliability Benefits: Recently, MISO gave a presentation on potential reliability benefit metrics, the conclusion of which is that there currently is not a methodology to accurately identify the beneficiaries of regional reliability projects over time.[11] In the case of the MVPs, the 7th Circuit stated “if crude is all that is possible, it will have to suffice.”[12] Crude is all that is possible for identifying the LRTP reliability benefits and distributing the costs arising from those benefits.
A. Cost Distribution Method One: Postage Stamp on Subregional Level
Today, we are at the same juncture as we were when developing a cost allocation for the MVPs: how to allocate costs when the beneficiaries will continuously change over the life of a project that brings broad regional benefits. While the MVP projects were designed to reliably deliver energy from renewable energy zones, the LRTP projects are somewhat different. They are “designed to ensure grid reliability with significantly higher renewable energy levels than today’s system.”[13]
Because of the false accuracy created by taking snapshots of the beneficiaries when the LRTP projects are approved, the Environmental Sector believes the best way to distribute the costs such that they are commensurate with the benefits over the life of the project is to postage stamp the costs on a subregional level.
Without a meaningful interconnection between MISO North and MISO South, the subregions should be MISO North and MISO South. Should the transfer capability between the North and South subregions be increased in the future, the Environmental Sector proposes revisiting the definition of subregions due to increased flow of benefits between the defined subregions.
B. Cost Distribution Method Two: Two-Step Approach Originally Proposed by the Certain TO’s in April 2021
Step 1: Quantify any economic benefits that are quantifiable and the beneficiaries receiving those economic benefits. Those beneficiaries then pay costs equal to the economic benefits estimated to be received by them.
Step 2: Any costs for the project remaining after Step 1 are assumed to be related to regional reliability, and these costs are postage stamped on a subregional basis with the subregions being MISO North and MISO South. (Note that the Certain TO’s did not define the subregions in their April 2021 proposal.)
[1]https://cdn.misoenergy.org/20210428%20RECBWG%20Item%2003%20Certain%20TO%20Cost%20Allocation%20Proposal544301.pdf
[2] “A Multi-Value Project must be evaluated as part of a Portfolio of projects, as designated in the transmission expansion planning process, whose benefits are spread broadly across the footprint.” Attachment FF § II.C.1.
[3] While the LRTP may identify DC lines or identify large AC lines that would ultimately be converted to DC lines, the Environmental Sector proposes that this LRTP cost allocation not apply to those lines because further discussion is required to identify issues uniquely applicable to DC lines. The MVP tariff also had an exclusion for DC lines under certain circumstances. Attachment FF § II.C.
[4] “Criterion 1. A Multi-Value Project must be developed through the transmission expansion planning process for the purpose of enabling the Transmission System to reliably and economically deliver energy in support of documented energy policy mandates or laws that have been enacted or adopted through state or federal legislation or regulatory requirement that directly or indirectly govern the minimum or maximum amount of energy that can be generated by specific types of generation. The MVP must be shown to enable the transmission system to deliver such energy in a manner that is more reliable and/or more economic than it otherwise would be without the transmission upgrade.” Attachment FF II. § C.2.a.
[5] “Criterion 2. A Multi-Value Project must provide multiple types of economic value across multiple pricing zones with a Total MVP Benefit-to- Cost ratio of 1.0 or higher where the Total MVP Benefit -to-Cost ratio is described in Section II.C.7 of this Attachment FF. The reduction of production costs and the associated reduction of LMPs resulting from a transmission congestion relief project are not additive and are considered a single type of economic value.” Attachment FF § II.C.2b.
[6] “Criterion 3. A Multi-Value Project must address at least one Transmission Issue associated with a projected violation of a NERC or Regional Entity standard and at least one economic-based Transmission Issue that provides economic value across multiple pricing zones. The project must generate total financially quantifiable benefits, including quantifiable reliability benefits, in excess of the total project costs based on the definition of financial benefits and Project Costs provided in Section II.C.7 of Attachment FF.” Attachment FF § II.C.2.c.
[7] “Any transmission project that qualifies as a Multi-Value Project shall be classified as an MVP irrespective of whether such project is also a Baseline Reliability Project and/or Market Efficiency Project.” Attachment FF § II.C.4.
[8] For example, OMS’s CAPCom stated “Cost allocation should be as granular and accurate as possible. Benefit-cost analysis should use metrics that are quantifiable, capable of replication, non-duplicative, and forward- looking.”
[9] Attachment FF-7 § B.1 on MEP’s Avoided Reliability Metric. To be an Avoided Reliability Project, the project must:
a. be a reliability project determined to address NERC reliability standards (Baseline Reliability Project) or other localized reliability transmission issues pursuant to Attachment FF, §§ I.C.1.b and II.A and the Transmission Planning Business Practices Manual, and must be contained in the list of Targeted Appendix A projects that are recommended for approval for inclusion in Appendix A of the current year’s MTEP as the preferred solution to one or more Transmission Issues consistent with Attachment FF, § I.C.1.b.i.e.
b. be needed after the expected in-service date of a proposed Market Efficiency Project and
c. be avoided by a proposed Market Efficiency Project.
[10] https://www.spp.org/documents/60090/vatf%20materials_posting%2020190620.pdf. Note that MISO’s Triennial Reviews evaluated the MVP’s over both a 20 year and 40-year period. See Attachment FF § VII.A.3. However, to qualify as an MVP, only 20 years of benefits are considered. Attachment FF § II.C.7.
[11] MISO evaluated three reliability benefit metrics: LODF, DFAX and the avoided transmission investment. MISO concluded that “Both LODF and DFAX are a measure of impact or usage of an element under a specific single scenario” and are “not a measure of ‘benefits’.” MISO explained that while the Avoided Transmission Investment has been shown to be relatively accurate it only captures a fraction of the reliability benefits provided by a project. https://cdn.misoenergy.org/20210611%20RECBWG%20Item%2002%20Discussion%20on%20Reliability%20Benefits%20of%20LRTP%20Projects559476.pdf
[12] The court cited to a PJM cost allocation decision, where it found “if FERC ‘cannot quantify the benefits [to particular utilities or a particular utility] ... but it has an articulable and plausible reason to believe that the benefits are at least roughly commensurate with those utilities' share of total electricity sales in [the] region, then fine; the Commission can approve [the pricing scheme proposed by the Regional Transmission Organization for that region] ... on that basis. For that matter it can presume [as it did in this case] that new transmission lines benefit the entire network by reducing the likelihood or severity of outages’.” Id. at 775, citing ICC v. FERC 576 f3rd at 477.
The Solar Energy Industries Association (SEIA) submits these comments on the cost allocation issues related to the Long Range Transmission Planning (LRTP) efforts underway before the Regional Expansion Criteria and Benefits Working Group (RECB). SEIA is appreciative of MISO’s efforts and progress regarding LRTP. Moreover, SEIA thanks MISO for its willingness to accept stakeholder feedback and work towards an equitable solution that results in more fully integrated transmission planning.
SEIA is very much supportive of the LRTP, coordinating interconnection studies and transmission planning, and developing needed transmission assets to accommodate MISO Member plans to further integrate solar resources throughout the footprint. A primary item in need of resolution with the LRTP, and each of these, is cost allocation. SEIA appreciates MISO setting forth the existing precedent for cost allocation and the going-forward principles it aims to apply to the LRTP. As the footprint approaches solutions to this cost allocation issue it is important to remember that every MISO Member benefits in some way – reliability, robustness, market efficiency, operational flexibility – by transmission expansion. The current practice of saddling interconnection customers with nearly all network upgrade costs that benefit the entire region must be changed.
MISO’s Futures Report anticipates between 121 GWs and 330 GWs of new generation resources will enter the footprint by 2039, with the majority of these resources using renewable technologies. MISO Futures Report at 4-6, April 2021, https://cdn.misoenergy.org/MISO%20Futures%20Report538224.pdf. MISO attributes this transition to “utility members are making future plans, committing to near and long-term retirements and investments, and announcing increasingly advanced decarbonization goals.” Id. at 1. Interconnection customers play only one of the many roles utility members have in the region. As such, these interconnection customers should not be the only party charged with funding the majority of the transmission system upgrades to accommodate new resources needed to meet other utility member generation, environmental, and decarbonization goals.
The cost allocation principles set forward by MISO include (1) balancing cost causers and beneficiaries (2) ensuring the right load pays, and (3) minimizing unintended consequences with resource investment decisions and operations. Balancing cost causers and beneficiaries is a sound and logical approach. Today’s construct fails to do that as it only allows for interconnection customers to be refunded for 10% of upgrade costs for 345kV and above. This refund amount should be expanded to include all interconnection facilities. Nonetheless, MISO should identify an appropriate balance between assigning LRTP costs to load serving members with goals encouraging concentrations of new resources and the interconnection customers rising to the occasion to assist with meeting those goals. SEIA appreciates that ensuring the “right” load pays is an issue that needs more exploration. However, the fairest and most efficient LRTP cost allocation solution will include utility members from all regions of the MISO footprint. MISO’s concern with efficient investment decisions should be clarified. Locational price signals and member utility initiatives provide economic signals to interconnection customers to enter the market at specific locations. Opaque network upgrade costs should not be used to send such new entry signals. SEIA notes the LRTP can, and has, identified areas with transmission reliability issues. The projects with the greatest reliability and economic benefits should be developed with costs being more fairly attributed to MISO Members.
SEIA encourages MISO to work expeditiously to address the cost allocation piece of the LRTP to ensure some LRTP projects can be folded into MTEP 21 for consideration by the MISO Board of Directors. In the alternative, SEIA encourages MISO to set forth a strict schedule for stakeholder feedback and interaction with the MISO Board of Directors that allows for any needed Tariff changes to be submitted to FERC by the close of Q2 2022. This accelerated timeline will allow for MISO to seek Board approval of any LRTP projects by year-end 2022.
DTE proposes that LRTP costs be allocated in a similar manner to Market Efficiency Projects today. Specifically, DTE recommends that the Adjusted Production Cost (APC) metric of Section 7.4.1.1 of MISO Business Practice Manual (BPM) 20 and a modified version of the Avoided Reliability Project (ARP) savings metric described in Section 7.4.1.2 of BPM 20 be used to allocate costs to the beneficiaries of LRTP projects.
Currently, the ARP savings metric is limited to including only projects recommended as a preferred solution targeted for Appendix A. DTE expects that many major violations of NERC criteria will be found in the LRTP study process for which no projects have been planned, because the LRTP is long-range and evaluates the system under a state of widescale transformation. Therefore, some modifications to this metric are appropriate to estimate the avoided cost of projects that have not yet been planned.
DTE suggests that a rough exploratory cost metric be used to approximate the avoided cost of these projects based on MISO’s Transmission Cost Estimation Guide, where possible. For example, avoiding an overload on a 120 kV line could result in an estimated cost savings of $1.5M per mile. Multipliers could also be used to account for large overloads. For instance, a line with a maximum loading of 165% of its rated capacity could have a cost multiplier of 1.65. Although such an approach would result in some misestimates that could be avoided with more careful and time-consuming engineering studies, they are not expected to affect cost allocation if the mismatch between these exploratory cost estimates and detailed engineering estimates is evenly distributed across member utilities.
Finally, DTE believes LRTP should focus on mitigation of high overloads (e.g. over 125% of rated capacity) or multiple overloads on parallel facilities. Small overloads (e.g. 105% of rated capacity) are less certain to occur in the future and can be addressed through the normal planning process, and single-issue overloads should be outside of the scope of LRTP per the “common issue” criteria. Because LRTP is meant to construct backbone projects to facilitate large-scale power transmission, DTE believes a minimum line voltage threshold of 345 kV and minimum cost threshold of $100 million should be used.
Michigan Public Service Commission (MI PSC) Feedback to the RECBWG.
Feedback request:
During the June 24, 2021, meeting of the Regional Expansion Criteria & Benefits Working Group (RECBWG)stakeholders were invited to submit feedback on the FERC approved Tariff provisions from MISO and other Regional Transmission Owners (RTOs) that might be pulled over into what is included in the Tariff for LRTP projects related to Future 1 and MTEP21.
MI PSC feedback:
The MI PSC thanks MISO for the opportunity to provide feedback on current FERC-approved cost allocation methodologies that could be used for LRTP projects. As the driver for the LRTP process is maintaining system-wide reliability during a time when the resource fleet transitions – involving both significant retirements and resource additions, the MI PSC believes that the primary challenge currently before MISO and stakeholders in establishing a cost allocation method for LRTP projects is the determination of reliability benefits and resulting cost allocation to beneficiaries, while at the same time capturing the economic benefits of these projects and allocating these benefits appropriately.
MISO has previously addressed transmission projects that include both reliability and economic benefits with the Multi-Value Project Criterion 3, which includes projects that provide a combination of regional reliability and economic value across multiple pricing zones. As such, the MI PSC finds it appropriate to include the six MVP benefit metrics as a starting point for capturing and allocating the reliability and economic benefits of projects identified through the LRTP process. These benefit metrics include:
Building on the MVP metrics, the MI PSC proposes the following three refinements to how such benefits are measured:
In addition, related to the increase in reliability and economic value derived from increased transfer capability, the MI PSC proposes three additional benefit metrics be included in the tariff for projects identified through the LRTP process associated with Future 1. These include:
Finally, economic benefits and allocation methods included in the MEP tariff should also be included.
Cost Allocation to Beneficiaries
The MI PSC recommends that cost associated with economic and reliability benefits are allocated to Cost Allocation Zones (CAZs) with a Benefit to Cost (B/C) ratio greater than 1.0 (MISO MVP tariff) pursuant to the distribution of benefits (MISO MEP tariff).
Recommended benefit metrics:
MISO MVP tariff: Congestion and Fuel Savings; Reduced Operating Reserves; Optimized Wind Turbine (and Solar) Investment; Avoidance of Future Transmission Investment (including avoided or deferred local reliability projects); Reduced LRZ Planning Reserve Margin Requirements; Reduced Transmission Line Losses
MISO MEP tariff: MISO-SPP Settlement Savings
New benefit metric: Mitigation of LOLE events and the ability to reliably retire existing thermal units pursuant to announced utility and/or state generation plans through increased transfer capability. Allocating costs based on increased transfer capability more accurately reflects the beneficiaries of these projects in terms of system-wide reliability.
Allocation to Generators
The MI PSC continues to see value in pursuing discussions around some allocation of costs to generators, beyond the contributions currently paid by generators. However, as interconnections and the growth of renewables are not the primary drivers of projects associated with Future 1, the MI PSC finds that no change is needed at this time, and that this discussion continue through the MISO Stakeholder process to inform any additional tariff changes, including an expanded MISO Shared Network Upgrades (SNUs) (MISO GIP) tariff, which might be appropriate for projects associated with Futures 2 and 3.
One idea worthy of further exploration for the future is allocating project costs to generators in a manner similar to CAISO’sLocation Constrained Resource Interconnection Tariff[1] where a generator pays for its share of transmission facilities on a simple per-MW basis. The cost of transmission capacity not initially subscribed by generators is recovered in general transmission rates until additional new generators come online and pay for that capacity.
Project Criteria
The MI PSC Staff recommends an LRTP voltage level of at least 230 kV (MISO MEP tariff) plus necessary lower voltage facilities necessary to facilitate the project (PJM tariff) and a B/C ratio greater than 1.0 (MISO MVP tariff) for economic benefit cost allocation.
Thank you for the opportunity to provide comments to the RECB working group. Regarding the request to provide approved tariff provisions from MISO and other RTOs, we should not be limiting ourselves to just these approved tariff provisions for LRTP Future 1 cost allocation. At this point, the list of identified LRTP Future 1 projects is not complete so it is difficult to determine who are the beneficiaries and how to appropriately develop new tariff provisions to cost allocate LRTPs. The assumption that everyone benefits equally and that a sub region-wide postage stamp could be appropriate is unjustified at this time. Time should be taken after the initial list of LRTP Future 1 projects are developed to review the project list and have a more robust dialogue on new tariff language and cost allocation provisions, including generator pay consideration, before we limit ourselves to existing approved tariff provisions and sub region-wide postage usage which will likely be arbitrary and non-deterministic to actual cost causers and beneficiaries of the LRTP futures. The cost allocation of tens of billions of dollars on new LRTP transmission projects will have significant impact to customer bills and a robust cost allocation development is needed once real projects are identified.
Response of ACP to Request by RECBWG for Stakeholder Feedback
July 9, 2021
The American Clean Power Association (ACP) is a national trade association representing a broad range of entities – including renewable developers, transmission owners, utilities, manufactures, suppliers, financiers, marketers and customers – with a common interest in encouraging the expansion and facilitation of wind, solar and storage energy resources.
ACP appreciates this opportunity to provide these very brief comments in response to the request by RECBWG for stakeholder feedback on FERC approved tariff provisions from MISO and other RTOs for inclusion in a cost allocation tariff for LRTP projects related to Future 1 and MTEP21. ACP is a strong supporter of the LRTP, designed to identify efficient transmission and non-transmission solutions to reliably support the portfolio shift underway across the MISO footprint. We look forward to continued active engagement in the LRTP process, including the timely establishment of a cost allocation methodology for transmission projects developed therein.
ACP supports the comments filed in response to this request by Certain MISO Transmission Owners, as well as those filed by the Environmental Sector These two sets of comments propose two cost allocation approaches. The first borrows heavily from the MVP tariff but assigns project costs to MISO North and MISO South on a sub-regional postage stamp basis depending on where the project is located. The second assigns economic benefits to zones, and the remaining regional reliability benefits are postage-stamped on a sub-regional basis. Both of these approaches would facilitate the construction of greatly needed backbone transmission for the benefit of customers seeking low-cost reliable clean energy, and would result in costs being allocated roughly commensurate with benefits.
Certain MISO Transmission Owners’ RECBWG Feedback - July 9, 2021
During the June 24, 2021 meeting of the Regional Expansion Criteria & Benefits Working Group (RECBWG) stakeholders were invited to submit feedback on the FERC approved Tariff provisions from MISO and other Regional Transmission Owners (RTOs) that might be “pulled over” into what is included in the Tariff for LRTP projects related to Future 1 and MTEP21.
In response, the Certain MISO Transmission Owners propose to modify the LRTP cost allocation proposal previously discussed at the April 2021 RECB, as detailed below. Essentially, the Certain MISO Transmission Owners propose to “pull over” MVP Criterion 3 into a new LRTP project classification set forth in MISO Tariff Attachment FF, and to make minor revisions as necessary to incorporate the slightly different characteristics and purpose of LRTPs. The LRTP project classification would operate in a manner very similar to the existing MVP projection classification, with the most notable exception being that the Certain MISO Transmission Owners propose that LRTP project costs are assigned to MISO North and MISO South on a postage-stamp basis depending on where the project is located. LRTP project costs would be recovered within the North and South sub-regions using the same usage-based cost recovery mechanism that is currently used for MVPs. The existing MVP project classification would be retained in the MISO Tariff, undisturbed. Additional preliminary details of the Certain MISO Transmission Owners’ revised LRTP cost allocation proposal are set forth below.
LRTP Cost Allocation – Certain Transmission Owners Proposal
1) Criteria
a) MVP Criterion 3 - The project must address at least one Transmission Issue associated with a projected violation of a North American Electric Reliability Corporation (“NERC”) or Regional Entity standard and at least one economic-based Transmission Issue that provides economic value across multiple pricing zones. The project must generate total financially quantifiable benefits, including quantifiable reliability benefits, in excess of the total project costs based on the definition of financial benefits and project costs, as defined in Section __ of Attachment FF.
2) Benefits
a) MVP economic value benefits
i) Production cost savings
ii) Capacity losses savings
iii) Capacity savings from reductions in overall Planning Reserve Margins
iv) Avoided project costs
v) Any other financially quantifiable benefit
(1) Potential other financially quantifiable benefits
(a) Minimizing loss of load events and magnitudes by enabling the transfer capability necessary for energy adequacy
(i) This may include increased adequacy with neighboring regions.
(b) Ability to reliably retire thermal units as per utility and state plans and utility goals
(c) Reduced generation investment costs to meet local renewable energy and carbon goals by access to regional renewable resources as well as local (SMILE Curve)
3) Benefit-to-Cost Ratio
a) Same as MVP
i) 20 year project life
ii) 1.0
4) Voltage Threshold
a) Same as MVP
i) 100 kV
5) Cost Threshold
a) Same as MVP
i) $20 million
6) Hierarchy
a) If an LRTP also qualifies as a Baseline Reliability Project and/or Market Efficiency Project, the project shall be classified as an LRTP.
b) If an LRTP also qualifies as a Multi-Value Project (MVP), the project shall be an MVP.
7) Cost Allocation
a) Postage stamp to the sub-regions – North and South
(1) North Projects – postage stamp to north
(2) South Projects – postage stamp to south
b) Auction Revenue Rights (ARRs) credits to offset postage stamp charges
i) Same as MVP ARRs per Section 47 of MISO Tariff Module C
c) North/South projects – TBD, not addressed in this filing/proposal
8) Portfolio evaluation
a) A LRTP must be evaluated as part of a Portfolio of projects, as designated in the transmission expansion planning process, whose benefits are spread broadly across the sub-region
i) Portfolio definition mirrors the MVP definition
(1) Two or more LRTPs proposed to be located in one or more Transmission Pricing Zones that, when evaluated together, are expected to result in sub-regional
benefits.
9) Charges - who pays
a) Same as MVP, but sub-regional components
i) Usage rate charged to Monthly Net Actual Energy Withdrawals, Export Schedules, and Through Schedules
The Certain MISO Transmission Owners include: Ameren Services Company, as agent for Union Electric Company d/b/a Ameren Missouri, Ameren Illinois Company d/b/a Ameren Illinois and Ameren Transmission Company of Illinois; American Transmission Company LLC; Duke Energy Business Services, LLC for Duke Energy Indiana, LLC; Great River Energy; International Transmission Company d/b/a ITCTransmission; ITC Midwest LLC; Michigan Electric Transmission Company, LLC; MidAmerican Energy Company; Northern Indiana Public Service Company LLC; Northern States Power Company, a Minnesota corporation, and Northern States Power Company, a Wisconsin corporation, subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric Company; Otter Tail Power Company; and Prairie Power, Inc.