PAC: JTIQ Whitepaper Feedback (20220831)

LS Power Development (LS Power), on behalf of its qualified transmission developer affiliates in the MISO and SPP regions, appreciates the opportunity to submit these comments on MISO’s and SPP’s proposed treatment of projects identified pursuant to the Joint Targeted Interconnection Queue (JTIQ) study, and the cost allocation treatment and competitive eligibility of JTIQ projects in particular. We support and applaud MISO's and SPP's creativity and collaborative work to identify these projects. In these comments, however, LS Power clarifies the aspects of JTIQ projects that (a) distinguish them from Generator Interconnection Projects (GIPs) and (b) require that they be competitively bid.

MISO and SPP base the proposed “90/10” cost allocation methodology (90% allocation to generators, 10% to load) for JTIQ projects, as well as the proposal to reserve JTIQ projects for incumbent TOs, on MISO’s approved tariff provisions for GIPs operating at 345kV and above. Likely relying on FERC’s finding that generator interconnection procedures were outside of the scope of FERC Order No. 1000[1], MISO did not address the competitive eligibility of GIPs operating at 345kV and above in its Order 1000 compliance filings. However, arguments for exempting JTIQ projects from competitive bidding are unavailing, as these projects emerged from an interregional planning initiative, would have a portion of costs allocated to load, and do not constitute “immediate need” reliability projects that may be exempted from competitive bidding.

JTIQ projects are the product of proactive interregional planning between MISO and SPP, which accomplishes the goal of selecting the more efficient or cost-effective solution.[2] These projects were not developed as “bottom-up” Point of Injection Network Upgrade projects. The RTOs jointly identified needs and solicited JTIQ project solutions from stakeholders, for which MISO offered (or indicated it would offer) planning participation credit in the Competitive Developer Selection Process.

MISO and SPP identified and fine-tuned the JTIQ projects such that they provide an optimal balance of reliability and economic benefits to customers in both regions. This approach meets the standard for regional planning described in Order 1000: “a full assessment by a broad range of regional stakeholders of the benefits accruing from transmission facilities.”[3] Further, the projects’ scope and scale is broader than those of generator interconnection Network Upgrades identified in MISO Definitive Planning Phase and SPP Definitive Interconnection System Impact Studies, which are funded by individual generator interconnection customers or clusters of such customers.[4]

Moreover, the JTIQ projects are eligible to be “selected in a regional transmission plan for purposes of cost allocation” because the costs of these regionally-planned projects “will not be borne entirely by the public utility transmission provider in whose retail distribution service territory or footprint that new transmission facility is to be located.”[5] Ten percent of JTIQ project costs (an amount above zero, as provided for in Order No. 1000-A) would be allocated to load – and not just in two or more transmission zones, but across two Order 1000 planning regions. Such a cost allocation approach requires a regionally (or in this instance, interregionally) planned project to be competitively bid unless it meets the criteria for an exemption.[6]

MISO’s and SPP’s current proposal is for load in both regions to pay 10% of JTIQ project costs. In addition, it is likely that either the constructing entity or load (by paying the constructing entity's rates) will provide project funding up front, with Interconnection Customers repaying these funds as they sign interconnection agreements – when and if all of the predicted projects proceed to this stage. In contrast, current arrangements for MISO GIPs operating at 345kV and above require Interconnection Customers to fund 100% of project costs up front, with 10% repaid by the constructing entity and subsequently recovered in rates.

JTIQ projects do not meet the definition of “immediate need” projects, since the projects are not aimed at resolving a specified system reliability violation or violations within a short-term planning timeframe. Rather, JTIQ projects are backbone projects that were identified in response to larger, longer-term optimized needs across the MISO/SPP seam and across study clusters.[7] The JTIQ methodology and report both contemplate the identification of larger-scale projects that provide economic benefits in the form of Adjusted Production Cost to load.[8]

The urgent need for JTIQ projects to interconnect generators and resolve queue backlogs is also unpersuasive as a reason for excluding these projects from competitive bidding. Given their scope, at least a few years of lead time will be required to develop the JTIQ projects, whether they are reserved for incumbents or awarded to non-incumbent developers. Additionally, as LS Power has previously noted, competitive bidding and proposal evaluation periods can be significantly shortened compared to the timelines that MISO and SPP currently employ. LS Power has experience with submitting competitive transmission bids in several regions and can suggest process improvements that would streamline the solicitation timelines for JTIQ and other competitive projects.

Stakeholders have raised additional issues that present logistical and other challenges with MISO's and SPP's proposed treatment of JTIQ projects. These problems are not insurmountable. While not discussed here in detail, LS Power stands ready with additional suggestions that could address the following:

• Demonstrating sufficient generator interest prior to approval of JTIQ projects;
• Timing of JTIQ project approval and development vs. timing of generator(s) providing funds for construction; and
• Payment by generators of a lump sum vs. a rate over time.

We look forward to working with MISO and SPP to resolve the identified concerns and to advance these (and future) JTIQ projects.

MidAmerican has the following questions/comments in regards to the SPP-MISO JTIQ Cost Allocation and Affected System Study Process Change White Paper dated August 17, 2022.

• Section 2.1.1.1 - Will there be differences in the study methodology used by MISO and SPP to determine if a generator is in the affected system zone?
• Section 2.1.1.6 – Can MISO/SPP provide more information or further example on how the true-up is factored in to subsequent study cycles? Specifically, will the true-up “passed along” to MISO and SPP study cycles based on queue priority until fully funded?
• Section 2.1.2.1 – Can the “MW in zone” considering two study “clusters” be further expanded? The way it is shown is not exactly clear. Also, can it be clarified that the $/MW calculation is done for North and South separately and assumably separate for MISO and SPP? I am having a hard time understanding how this is then translated to true-up.
• Section 2.1.4 – At what point does MISO/SPP believe BOD’s will approval JTIQ transmission project to begin construction? A certain % of funding? There needs to be a fine balance between risk from approval too early but approval not so late generators are interconnecting prior to completion of transmission project and causing congestion.
• Section 2.2 – MidAmerican supports proposal as drafted.
• Does a generators NRIS vs ERIS election play any role in JTIQ?
• How will MISO and SPP model the dispatch of storage in JTIQ screening? Are there any noticeable changes from current MISO policy?
• Does MISO/SPP anticipate the JTIQ screening process will result in any delays to the generator interconnection study process? Or result in the need for other affected systems to report known findings in Phase 1 results?

JOINT TRANSMISSION INTERCONNECTION QUEUE COST ALLOCATION, AFFECTED SYSTEM STUDY PROCESS, AND TRANSITION
DATE: SEPTEMBER 6, 2022

The following feedback is offered by the Entergy Operating Companies ("EOCs")1 in response to MISO and SPP’s request during the Joint Stakeholder Meeting on the MISO-SPP JTIQ Cost Allocation, Affected System Study Process, and Transition Details on August 22, 2022.

Entergy supports the JTIQ study as a good approach to fixing the seemingly broken Affected System Study process. Regarding the proposal: 

• We support using a 5% dFax threshold for identifying impacts in the Affected Facilities Zones.
• Entergy believes that the 90/10 cost split between Interconnection Customers and Load appears to be appropriate based on the results of the analysis of benefits of this portfolio, but we question whether the same split would be appropriate for another portfolio of projects. While the analysis shows some benefits to load, these were not close to offsetting the cost of the transmission projects, which are not required, but for the interconnection of new generation in the MISO & SPP regions. Establishing a voltage threshold for upgrades to be allocated to load could address this concern.
• Entergy supports having North & South zones for allocating costs to Interconnection Customers, but we believe that the same approach should be taken to allocation of costs to load.
• Regarding the proposal for MISO and SPP to study impacts to other’s systems within a few busses of the seam and address any overloads, Entergy believes that MISO and SPP must work with the affected TO to identify an appropriate mitigation. 

In general, Entergy sees benefit to this process, and we believe that the first portfolio of projects will benefit MISO North. We do not believe that the projects in this portfolio will provide benefits to MISO South that would justify allocating any of the costs of this portfolio at this time. 

Further, Regional Cost Allocation for approved projects assessed to each RTO is a matter for discussion in the regional stakeholder process, however such allocation should be contingent on demonstrating that such allocation is at least “roughly commensurate” with benefits provided by the portfolio that is to be cost allocated. This is particularly a concern in this first portfolio, which MISO and SPP stated does not provide material benefit to load at all.

1 The Entergy Operating Companies are Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, LLC, Entergy New Orleans, LLC, and Entergy Texas, Inc.

MPSC and LPSC Staff Feedback on JTIQ Whitepaper

The Mississippi Public Service Commission and Mississippi Public Utilities Staff (MPSC) and the Louisiana Public Service Commission Staff (LPSC) (Retail Regulators) appreciate the JTIQ Whitepaper  because it is intended advance generator interconnection and spread the costs of interconnection across a broader  pool of developers.  The Retail Regulators offer the following feed-back to the whitepaper:

Recommendations

The current MISO – SPP JTIQ whitepaper proposal presents an unknown financial risk to load.  The Retail Regulators recommend the following steps to better understand loads’ exposure to financial risks:

• The Queue withdrawal rate of 50% for MISO and 60% for SPP noted in the whitepaper appears low based upon historical data.  The RTOs should provide historical data supporting a reasonable Queue withdrawal rate.
• The RTOs should provide a detailed spreadsheet depicting all calculated costs with a breakdown of cost assignment to load and generators.  The spreadsheet should depict the number of years/Queue cycles for load to fully recover costs assigned to generators.
• MISO notes the 90/10 split is based on the cost allocation used in MISO for generator interconnection related network upgrades for facilities operated at voltages of 345 kV and greater (for facility voltages less than 345 kV, the interconnecting customer pays 100%).  MISO should affirm this same 345 kV or above facility voltage limit will apply in the JTIQ process.
• The RTOs should confirm that the 10% cost assignment to load as noted in the previous bullet is a cost cap on load cost responsibility. 
• JTIQ projects should be limited to voltage levels of 230 kV and above.
• Consistent with current interconnection policies and procedures, the RTOs shall avoid incurring any costs (e.g., design, construction costs) until sufficient interconnecting generators have executed GIAs to ensure recovery of at least 90% of the transmission costs from generators. 
• The RTO proposal addressing construction, operation, and maintenance expenses for JTIQ projects and how these expenses may differ from actual expenses, is unclear.  The RTOs should provide a spreadsheet depicting how a rate based on these expenses assumptions will be carried forward to subsequent Queue cycles to resolve under- or over-collection.  These expenses are not to be assigned to load as the funder of last resort.
• The posted APC calculations should be net of FTR revenues received by load to represent the true value of congestion reduction to load.
• MISO should provide a written response describing its proposal to allocate MISO’s share of the 10% of costs assigned to load.  In early August, MISO noted the portion of the 10% of the costs allocated to MISO would be addressed at the RECBWG in September.  Last week, at PAC, MISO said this cost allocation will follow current procedures that allocate 10% of costs for GI projects 345 kV and above to load using a MISO footprint wide postage stamp.  To date, this issue has not been discussed at the RECBWG. Has MISO already decided without stakeholder discussion?
• MISO should provide a Schedule 26 spreadsheet depicting cost allocation of MISO’s portion of costs assigned to load if Schedule 26 is MISO’s preferred method for cost allocation.
• MISO should survey generator developers to determine what $/MW rate they would accept?
• Retail Regulators request that the RTOs advise on the feasibility to adopt refundable/non-refundable language contained in the current DISIS and DPP processes for each RTO respectively as part of the JTIQ.  

General Concerns with Proposal

The retail regulators oppose being assigned the risk to fund the transmission needed for generator interconnection.  As vertically integrated utilities, the costs of those projects would be borne by retail customers unless and until sufficient interconnecting generation agrees to assume those costs.  Only if and when sufficient interconnecting generation sign GIAs should the projects be built.  As a practical matter, the Retail Regulators are concerned with load financing JTIQ projects and recovering 90% of the costs from generators that later decide to execute a GIA.  

Proposal Violates Cost Causation Principles: MISO and SPP representatives acknowledge that the projects contemplated by JTIQ are classic “but for” projects; that is, projects that would not be built “but for” the need to facilitate new generator interconnections.  FERC generator interconnection policy and MISO Tariff provisions place the burden for network upgrades needed to facilitate generator interconnection on the interconnecting generation developer.  The cost of network upgrades to facilitate generator interconnection is a business risk that belongs to the developer, not load.

Proposal Shifts Generator Interconnection Network Upgrade Risk to Load:  Making load the “funder of first resort” shifts the generator’s network upgrade burden and risk to load.  If the ultimate price tag for these upgrades is too great, generators may decide to locate elsewhere.  And, as one or more generators withdraw (opt-out by not executing a GIA), the share of the costs to those generators that decide to remain will increase.  At some point, the cost per generator may be so great that no generators remain, leaving load with responsibility for 100% of upgrade costs, not just 10%.  High withdrawal rates from RTO interconnection queues bear this out.

Unrecoverable Costs:  If these upgrades are not necessary to serve load, it is arguable that they are not “used and useful” and that their costs were not prudently incurred, which raises the question of whether a state commission would agree to site the facilities or authorize their recovery in retail rates.

The purpose of the JTIQ process is not to shift network upgrade costs from generation to load; it is to develop facilities that advance generator interconnection and spread the costs among a group of interested developers so that the financial burden on individual developers is reduced.

Finally, the Retail Regulators cannot support any changes that result in additional cost assignment to load.  Recent stakeholder meetings indicated some stakeholders support using additional benefit metrics to assign additional costs to load.  The Retail Regulators will not support attempts to assign additional costs to load based upon future benefits that are speculative and uncertain.  This includes many of the benefits considered as part of the LRTP.

ENVIRONMENTAL SECTOR 
COMMENTS ON THE JTIQ WHITE PAPER

Introduction:

The Environmental Sector appreciates all the work MISO and SPP have done to study and identify transmission solutions to support interconnection of additional resources along their seam. The recent proposal to replace the existing Affected System Study (AFS) process with a JTIQ-like process is creative and has a lot of potential to address the timing and cost uncertainty that have recently been a serious impediment to new generation on the seam. More details in this proposal need to be worked out, and we hope that these comments and questions are helpful in that regard.

ISSUE:  Transition Period: 

In Section 3.2.1 of the white paper, MISO provided a table and explanation of a proposed transition period, based on a hypothetical future approval date of the JTIQ cost allocation and process to replace the AFS process. Please provide more information regarding why MISO has suggested that interconnection customers in clusters that have an AFS underway as part of Phase 2 would have JTIQ lines included in the base case model, but that these customers would not be subject to the JTIQ Affected System Charge. This part of the transition proposal does not seem to follow beneficiaries-pay principle, in the sense that these parties would likely benefit from fewer required interconnection network upgrades due to the JTIQ lines being in the base case but would not pay a share of the costs of JTIQ lines. One simpler possibility could be to have a more definite cutoff for the transition, such that those in the middle of Phase 2 would continue with their AFS studies to completion with no impact or consideration of the JTIQ projects, as has been proposed for those clusters that have completed their AFS studies under Phase 3. Regardless, we would appreciate more clarity regarding this point.

ISSUE:   Predicting the # of MWs for Calculating the $/MW Charge:   

Originally, MISO and SPP had suggested that the denominator used to determine the $/MW JTIQ AFS Charge would be based on the expected number of MW of new generation along the seam enabled by these network upgrades. This appears to be a reasonable approach, given beneficiaries pay principles, in the sense that the number of MW enabled should be the same number of MWs of new generation that will benefit from the JTIQ lines.

In Section 2.1.2 of the white paper, however, MISO and SPP appear to be suggesting a different approach to determining the number of MWs in the denominator of the $/MW calculation. Rather than a number of MW enabled, the white paper states that MISO and SPP will “determine the amount of generation connecting in the JTIQ Affected System Zone.” The examples provided suggest that this amount would instead be determined by the amount of MW in the existing queue cluster plus a predicted amount (MW) for the following queue cluster.

Please describe why this is a more reasonable approach than basing the calculation just on the MW that are enabled by the JTIQ lines? Also, what will the prediction of the MW in the upcoming queue cluster be based on? It does seem that analysis of the amount of new MW of generation along the seam that can be supported by a set of JTIQ lines, and the $/MW charge itself, are both important to estimate with accuracy in order to ensure proper cost recovery.

ISSUE:  True Up Methodology from § 2.1.1.6:  

The Draft Whitepaper proposes that when setting the Affected System Zone rate at the end of JTIQ study, that any under or over-recovery from the prior JTIQ round would be rolled into the new rate.^[1]  It is unclear how this true-up mechanism could comply with the FERC and judicial mandate that costs must be roughly commensurate with the benefits received in a regional cost allocation. When assessing costs due to an under-recovery, MISO would need to establish how the JTIQ projects from the prior round provide benefits to the projects in the current round. On the flip side, providing a discount to the current round because of over-recovery from the prior round would highlight that the projects in the prior round overpaid. In the latter case, why not just provide a refund to the projects in the prior round? 

ISSUE:  North and South AFS:

At the July 26, 2022 RECBWG meeting, MISO presented the MISO-SPP Joint Targeted Interconnection Queue Study (JTIQ) Update, where the JTIQ AFS Zone Concept was first shared.^[2] There it was proposed that the AFS Zone would be split into two regions: North and South. While it is understandable that bifurcation of the AFS Zones could be applied between north and south in MISO, it is not clear how this could also work in SPP.

As is widely known, MISO filed with FERC a regional bifurcation cost allocation associated with the LRTP Tranche 1 and 2 projects, arguing in part that because of the limited connection between the North and South regions of MISO, few of the LRTP Tranche 1 and 2 project benefits in the north would flow to the south. However, it is not clear that such an argument holds true for SPP’s North and South regions. While all the JTIQ projects identified so far are north of Kansas City, future JTIQ projects closer to the four-states region (Kansas/Missouri/Oklahoma/Arkansas) would not logically follow a strict north/south boundary. For years, the Neosho to Riverton region has been discussed as a troublesome area that perhaps JTIQ projects could solve. In that case, it is unclear how cost allocation could reasonably be limited to MISO/SPP North.

ISSUE:  Cost Sharing Thresholds:

During the presentation at PAC, it was suggested that the 90/10 cost sharing arrangement would only apply to facilities rated 345kV and above, with costs for lines with lower capacities being 100 percent attributed to generation. Considering that there are considerably fewer 345 kV transmission lines in MISO South, we ask that MISO and SPP ensure that any such threshold in the South is no greater than 230 kV. See the figure below for more context:

[image not available in text submission portion of the feedback tool - see attached PDF for PDF version of these comments]

Source: US Energy Information Administration, US Energy Atlas, Electricity Energy Infrastructure and Resources (https://atlas.eia.gov/apps/electricity/explore)

ISSUE: Value to Interconnecting Generators:

It has been stated by staff that the benefits generators will receive for paying for JTIQ lines is the ability to interconnect to the grid. In the standard Generator Interconnection Process, generators receive FTRs as well as the ability to interconnect when they help to fund required interconnection network upgrades. Please confirm that generators that contribute towards funding JTIQ lines will also receive FTRs in proportion to the amount of the $/MW charge that they pay.

WEC appreciates the opportunity to provide feedback on the proposed MISO-SPP JTIQ process and cost allocation.  In summary, we believe that the proposed 5% or greater distribution factor (DFAX) threshold on any neighboring region facility to determine the interconnection requests subject to an allocation of JTIQ costs casts a net that is far too wide.  The allocation of JTIQ costs must follow FERC’s cost causation principles whereby costs are allocated to cost causers and beneficiaries (as identified through an appropriate process, per FERC Order 1000) and there are no involuntary allocation of costs to non-beneficiaries.  The proposed 5% DFAX impact on any neighboring facility fails these principles by failing to demonstrate a JTIQ project cost is caused by such a broad impact threshold.  More detail on this concern is in the paragraphs below.

 WEC Energy Group is also concerned that the white paper lacks sufficient detail on rate design and how transmission costs are ultimately allocated to Interconnection Customers and load.  It is our understanding that load is expected to fund up-front JTIQ project costs prior to the execution of GIAs that would assign costs to the Interconnection Customers.  Appropriate refund mechanisms are needed to ensure load is held financially whole in this process.  In the unlikely event that sufficient generation fails to execute GIAs, load should not be assigned the cost of transmission that isn’t needed but for generation interconnection.  At some point in the process, JTIQ costs must be assigned to Interconnection Customers through a non-fundable charge during the DPP/DSIS process and prior to the execution of a GIA.

We note that the proposed DFAX threshold fails to address whether or not an interconnection request would increase or decrease flow on a neighboring region facility.  For example, an interconnection request in MISO may have a 10% impact on an SPP facility but if that impact is counterflow, the interconnection request is reducing flow on the neighboring facility.  Interconnection requests that reduce flow on neighboring system(s) are not a burden, do not cause affected system upgrades, and are not beneficiaries of the JTIQ projects.  Interconnection requests that only create counterflow on the neighboring system facilities should not meet the threshold for inclusion in the JTIQ process.

An interconnection request that causes an increase in flow on any facility on the neighboring system fails to identify whether or not that interconnection request requires or benefits from the JTIQ projects.  We believe a better measure of JTIQ cost causers and beneficiaries is to determine the DFAX of each interconnection request on each of the JTIQ projects.  Interconnection requests subject to the JTIQ process (in-scope requests) should be limited to those interconnection requests with a 5% or greater DFAX that also increase flow on one or more of the JTIQ projects.  We believe this threshold is consistent with FERC’s cost allocation principles.

While we appreciate the simplicity in establishing a flat $/MW rate based on the JTIQ cost estimate and total MW of in-scope requests, we support an evaluation of allocating JTIQ costs with a methodology similar to MISO’s allocation of Network Upgrade costs that are driven by more than one interconnection request.  MISO’s methodology allocates costs based on the pro rata share of the MW contribution from each interconnection request.  Use of this methodology for the JTIQ cost allocation ensures that interconnection requests with higher cumulative MW impacts on the JTIQ projects are allocated costs commensurate with those higher benefits.  Similar to the proposed JTIQ process, this cost allocation along with a projected withdrawal rate is fixed at the start of the applicable DPP or DSIS.  The projected number of project withdrawals would each assume the average MW impact of all in-scope requests on the JTIQ projects, reduce the total MW impact of the in-scope requests by the average MWs times the number of project withdrawals, and calculate the percentage share of the total JTIQ costs for each in-scope request based on the reduced total MW impact.  This will result in an allocation of costs greater than 100% at the start of the DSIS/DPP but accounts for the projected dropout rate and provides cost certainty.  Similar to the proposed JTIQ process, this will lead to either an over or under collection of costs that will need to roll forward to future cycles.

As an example, assume 10 interconnection requests are in-scope and the total flow increase on all JTIQ projects from those 10 requests is 800 MW.  If the withdrawal rate is 20% or 2 projects and the average MW flow impact of all interconnection requests on all JTIQ projects is 90 MW, the total flow after accounting for potential withdrawals is 800 – 2*90 = 620 MW.  Each of the 10 projects is then allocated its pro-rata share of JTIQ costs based on a 620 MW total flow, resulting in an allocation greater than 100% to account for potential withdrawal and to provide cost certainty.

We appreciate the RTOs’ efforts to develop a solution to the Affected Systems issues that generators face toward the end of the interconnection process. However, the new proposal is unfairly and unjustifiably removing one major criterion of Affected Systems upgrades - that a facility must be overloaded. Today, (i) a generator must impact the Affected Systems facility (through a distribution factor test), and (ii) the Affected Systems facility must be overloaded. The JTIQ proposal calls for only a distribution factor test and does not consider whether there are overloads attributed to that generator. Generators that are not responsible for Affected Systems upgrades under the current process will have to fund a whole portfolio of unnecessary upgrades for it to obtain interconnection service under the proposal if it meets the distribution factor threshold.

We are concerned that the RTOs still have not adequately justified the use of a 5% DFAX criteria for inclusion in the JTIQ Zone. Requests for more details about the DFAX calculation at the June 27 JTIQ meeting still have not been shared. No data has been provided on how a set of JTIQ projects would’ve helped previous study cycles. No data has been provided on whether, or how severely, all generators within the JTIQ Zone are impacting reliability issues on the other RTO. No comparison has been shared versus other DFAX thresholds (e.g. 10% or 20%). Specifics on how the DFAX will be performed are also lacking. We believe that 5% DFAX is too low of a threshold to require individual generators to pay an equal share in a whole portfolio of major transmission. Further, generators electrically closer to the JTIQ projects (higher DFAX) should be paying a higher rate than those electrically remote (lower DFAX), as they would be impacting more of the driving issues the portfolio is solving.

We are further concerned that the JTIQ portfolio was selected based on a snapshot in time using queued generators and constraints. Those assumptions have already changed but the RTOs have not shown how the portfolio is still the correct solution for future queue cycles.

The RTOs have talked about a certain amount of generation being “enabled” by the JTIQ portfolio. This ‘enablement benefit’ is not a quantifiable benefit that either RTO uses to justify transmission build out. The RTOs haven’t shown how enablement is a suitable replacement to identifying and upgrading reliability-driven transmission issues.

Proposed solution:
We believe the only major shortcoming of the RTOs’ proposal is the linkage between overloaded facilities and the generators impacting them. A solution to this gap, which alleviates most of our concerns, above, is for the RTOs to document which reliability overloads each JTIQ project addresses. Using DFAX on the driving reliability issues – not just any neighboring facility – would then be appropriate to identify which generators in future cycles pay for that JTIQ project. Each JTIQ project could have a separate rate formula and generators would only pay toward projects addressing reliability issues they impact. The JTIQ rate for each generator could still be calculated when entering the queue. We feel this method ensures that generators are only paying for reliability overloads they impact while still allowing the RTOs to pre-build transmission to remove hurdles in the Affected Systems process.

Thanks for the opportunity to provide feedback.