Page 1151 – RTO Insider

January 22, 2020

PJM MOPR Rehearing Requests Pour into FERC

By Christen Smith and Rich Heidorn Jr.

A broad range of stakeholders asked FERC on Tuesday to reconsider its Dec. 19 order requiring PJM to overhaul its capacity market, saying the commission’s directive is unnecessary and oversteps federal jurisdiction (EL16-49, EL18-178).

The commission said PJM must expand its minimum offer price rule (MOPR) to counter increasing state subsidies, primarily for renewables and financially struggling nuclear generation. (See FERC Extends MOPR to State Subsidies.)

The ruling builds on PJM’s “MOPR-Ex” proposal, filed in response to the commission’s June 2018 order finding the RTO’s capacity market rules unjust and unreasonable because they failed to address growing subsidies. The RTO’s existing MOPR covers only new gas-fired resources. (See FERC Orders PJM Capacity Market Revamp.)

But state regulators, utilities and load-serving entities alike argued in their rehearing requests that the order goes too far in attempting to control their generation choices and fails to prove state-subsidized resources suppress capacity market prices.

“The December order imposes an extraordinary cost on states that seek to exercise some control over their generation mix, effectively commandeering states into FERC’s preferred approach to resource planning,” wrote FirstEnergy Solutions, which last year became the chief beneficiary of an Ohio law subsidizing its nuclear and coal plants via ratepayer surcharges.

“The alternatives to submitting to FERC’s regime are grim,” FES wrote. “States will either have to incur significant duplicative costs for capacity — which will only increase as time goes on and emissions-reduction targets escalate — or exit the market altogether.”

PJM MOPR Rehearing — New PJM CEO Manu Asthana addressed the Market Implementation Committee during a discussion on FERC’s MOPR ruling on Jan. 8. | © *RTO Insider*

Overstepping Boundaries

State commissions in New Jersey, Ohio, Maryland, Pennsylvania and West Virginia complained that the order encroaches on their jurisdiction while inexplicably abandoning the resource-specific fixed resource requirement (FRR) alternative FERC itself suggested in June 2018 to address alleged price suppression from subsidies.

The result, they argue, means the expanded MOPR will distort price signals and force market participants to over-procure capacity and charge ratepayers twice for it.

“In the long run, the expansion of the MOPR to all new and existing resources under the repricing proposal advanced by the commission is likely to harm the energy and capacity markets administered by PJM,” the Pennsylvania Public Utility Commission said. “Imposing administratively adjusted offer prices at prices well above historical competitive market prices will only hasten the demise of truly competitive markets.”

The Maryland Public Service Commission said the order “forcefully treads” on state policies that value a resource’s environmental attributes by denying them capacity payments and “undoing the benefit of state support.”

“By raising barriers to state-sponsored renewable resources and effectively excluding them from participating in wholesale markets, the commission has acted ultra vires to shape generation mix and thwart states from exercising that function,” the Maryland PSC wrote. “The December 2019 order is particularly dangerous in that it severely curtails cooperative federalism in the regulation of generation by acting to stymie state efforts to value resource attributes.”

The New Jersey Board of Public Utilities said the “clunky” MOPR results in a “systemic and calculated” expulsion of new clean energy resources from the market, upsetting FERC’s “decades-long precedent” of leaving environmental regulation “largely to the states.”

“Nowhere does the order adequately explain this sudden antagonism to the cooperative federalism principles that underlie the” Federal Power Act, the BPU said. “Make no mistake: The alternative to granting rehearing is increased consumer harm in the form of higher prices and worse environmental outcomes. If the commission does not reverse course, state clean energy efforts will be frustrated and the PJM market will be at risk for dissolution.”

PJM itself urged the commission to rethink the order’s impact on states, saying that expanding the MOPR in pursuit of economic efficiency “may in fact unintentionally cause economic inefficiencies over the long term.”

“That new approach is over-broad and over-prescriptive and will dramatically curtail new resource options for integrated utilities, including those that meet the previously accepted net short and net long tests, whose offers have not previously been viewed as posing unacceptable risks to efficient price formation,” the RTO wrote. “The new approach also needlessly interferes with state resource policies well beyond what is needed to protect the market against inefficient price formation and achieve rates within a zone of reasonableness.”

[PJM also posted answers Tuesday to stakeholders’ questions on the MOPR ruling. The document will be updated each Friday afternoon, the RTO said.]

The Nuclear Energy Institute took issue with FERC’s refusal to allow a resource-specific FRR, which the commission had invited comment on in its June 2018 order, saying it may be just and reasonable. “However, in the December 2019 order, the commission reversed course and declined to adopt the resource-specific FRR with virtually no discussion of the issue, much less a reasoned justification,” NEI said.

NEI also criticized the commission for failing to address state preferences regarding capacity resources and the risk that an expanded MOPR without the resource-specific FRR option could leave ratepayers paying twice for capacity.

“The commission’s failure to conduct any such analyses [of a resource-specific FRR] and completely disregard legitimate state interests and goals, including failing to provide any kind of transition mechanism to accommodate such state interests and goals, is arbitrary and capricious and does not represent reasoned decision making,” the group said.

The Public Utilities Commission of Ohio asked FERC to consider ordering PJM to hold the delayed 2022/23 capacity auction without applying the expanded MOPR — similar to action taken during the implementation of Capacity Performance — to “get a forward capacity price signal in place, plug the three-year forward hole that currently exits and will likely grow, and provide for a transition period.”

“At a time when the commission has already significantly delayed the reveal of the three-year-forward capacity price, it is the PUCO’s fear that the forces set in motion by the order will promote long-lived uncertainty,” PUCO said. “This will, accordingly, strongly motivate states and market participants to take flight from the consequences attributed to the order.”

The Maryland attorney general’s office also questioned FERC’s decision to mitigate state subsidies while ignoring their federal counterparts and said the order “will have an outsized effect on existing business models for demand response, public power and voluntary renewable energy credits.”

Self-supply Exemption

Self-supply entities, like the Southern Maryland Electric Cooperative and Old Dominion Electric Cooperative, urged rehearing after describing PJM’s existing fixed resource requirement alternative (FRR-A) “unwieldy” and “unworkable” for planning new capacity.

FERC’s decision to abandon previously accepted exemptions for self-supply LSEs puts many resources at risk of being unable to clear the capacity auction, SMECO said. PJM’s existing and narrow FRR-A would require SMECO to carve out its entire load when using the option to accommodate a single new capacity resource subject to the MOPR, the cooperative said.

ODEC argued that eliminating the exemption would “indeed cause disruption of the industry” and fail to preserve existing investments. Further, the cooperative argues, the expanded MOPR will chill future ventures and disregards the entire business model of self-supply.

“As opposed to making investment decisions based on long-term economics and other benefits as ODEC historically has under its traditional business model, investments must now be made based at least in part on whether a resource is likely to clear the single-year, three-year forward capacity auction,” ODEC wrote.

The cooperative said neither the unit-specific exemption nor the FRR-A serve as legitimate substitutions for the self-supply exemption.

“ODEC and others have demonstrated in the past that the FRR may not be a workable alternative for smaller LSEs, given the requirements to opt out of the capacity construct for both purchases and sales, for a five-year period with onerous financial consequences if the ability to do so becomes untenable,” ODEC wrote.

Clean Energy Associations

Advanced Energy Economy, American Council on Renewable Energy, American Wind Energy Association and the Solar Energy Industries Association, filing as “Clean Energy Associations,” said FERC failed to prove PJM’s current market design is unjust and unreasonable, as required under Section 206 of the FPA, or to establish a new just and reasonable rate with its “drastic and unwarranted” expansion of MOPR.

The groups also said FERC overreached its authority under the FPA by effectively nullifying state renewable policies and seeking to mitigate state subsidies that don’t directly affect capacity prices, in violation of the Supreme Court’s 2016 ruling in FERC v. EPSA. (See Supreme Court Upholds FERC Jurisdiction over DR.)

“Based on the commission’s definition of state subsidy, if a town were to offer local permitting support to develop a specific new type of energy resource on a particular plot of land, and such program was not tied solely to ‘generic industrial development and local siting support,’ such program would also appear to be swept into the definition of state subsidy.”

The groups also said the commission failed to support its application of MOPR to state subsidies obtained through competitive processes and that its inclusion of voluntary renewable energy credits is arbitrary. “Further, the order presented no evidence or offered no analysis for subjecting carbon allowances, such as Regional Greenhouse Gas Initiative allowances, to the MOPR.”

EPSA

The Electric Power Supply Association (EPSA) and the PJM Power Providers Group (P3) asked the commission to reconsider its finding that no federal subsidies will be considered in determining whether a resource should be subject to the MOPR, saying the commission underestimated its authority under the FPA. It was EPSA member Calpine that led the complaint that resulted in the MOPR ruling.

“The commission’s refusal to extend the MOPR to offers from resources receiving federal subsidies of any kind was arbitrary and capricious as it cannot be reconciled with the commission recognition that ‘subsidies created by federal law distort competitive outcomes in the PJM capacity market in the same manner as do state subsidies,'” the groups said, quoting from the Dec. 19 order.

“EPSA and P3 do not argue that the commission must expand the MOPR to address all federal subsidies, only that the commission erred in declining to expand it to address any federal subsidies,” the groups said in a press release about their filing. “This request is consistent with EPSA’s past opposition to federal subsidies for uneconomic coal and nuclear resources.”

They also asked FERC to clarify that the definition of state subsidies would not include RGGI or voluntary, bilateral transactions for RECs. And they asked the commission to clarify that its references to the availability of the existing FRR rules “were merely factual statements as to the ongoing effectiveness of the FRR rules and cannot be construed as findings that the FRR rules are just, reasonable and not unduly discriminatory or preferential in light of changes required in the Dec. 19 order or other changes that have occurred since it went into effect.”

They also asked FERC to pressure PJM to hold the next two BRAs before the end of 2020, as the Independent Market Monitor has proposed.

Clarifications

Both PJM and the Monitor asked FERC to clarify that credits received through RGGI and default service procurement programs do not constitute subsidies.

Both Maryland and Delaware use RGGI as a means of reducing carbon emissions, with New Jersey, Virginia and Pennsylvania in line to join the program in the coming years.

“The RGGI cap-and-auction system is not a subsidy, any more than any other environmental limit on a particular plant is a subsidy for any plant that does not have the same emissions or discharges or the same limit,” PJM wrote.

AES likewise requested clarification on whether the MOPR applies to RGGI transactions.

PJM also asked confirmation on its interpretation on what triggers MOPR for resources that receive both state and federal subsidies, the latter of which FERC said aren’t impacted by the order.

The Monitor wants the commission to clarify treatment of the existing MOPR, noting that current rules subject capacity from landfill gas units, cogeneration units and fuel cells to an offer price floor, while exempting coal-fired steam units that are repowered as oil- and gas-fired steam units. Questions also remain about calculations for net revenues and rules for resources that seek must-offer exceptions, the Monitor said.

FirstEnergy Utilities expressed concerns about the unknown timeline for upcoming capacity auctions and worried that they wouldn’t have enough time to evaluate PJM’s FRR-A as an option. They requested clarification that PJM should provide flexible timelines to give utilities leeway in making a near-irreversible decision to use the FRR-A.

The utilities also said the commission should clarify that the self-supply exemption will apply when a self-supply entity purchases an existing generation asset that has previously cleared a capacity auction. Its rehearing request centered on FERC allegedly ignoring their arguments for a holistic market review.

January 21, 2020

Deposit Rule OK’d for New ISO-NE Capacity

By Rich Heidorn Jr.

ISO-NE will apply different deposit rules on new capacity resources for Forward Capacity Auction 14 under a proposal approved by FERC last week (ER20-395).

The RTO will calculate financial assurance for noncommercial resources — those that have cleared an FCA but have not yet achieved commercial operation — based on the net cost of new entry rather than the FCA’s starting and clearing prices.

The financial assurance policy is intended to ensure that resources achieve commercial operation by the time their capacity commitment period begins.

Under the previous rules, noncommercial resources had to submit a deposit before the auction equal to its qualified capacity multiplied by the FCA starting price. If the resource obtained a capacity supply obligation (CSO), the deposit would be recalculated to equal the product of the CSO awarded, the clearing price from the first round in which the CSO was awarded and a multiplier.

Under the new rules, effective Jan. 15, the deposit will be based on net CONE before and after the FCA. ISO-NE said that will reduce uncertainty, meaning market participants will no longer need to speculate as to the eventual deposit.

ISO-NE Capacity — NTE Energy’s 650-MW natural gas-fired Killingly Energy Center in Killingly, Conn., is expected to go into operation in 2022. | *NTE Energy*

The change was prompted by concerns that the previous rules could allow noncommercial resources to benefit financially from their CSOs, even when they fail to achieve commercial operation in time to honor them.

The proposal faced no protests, although the New England Power Generators Association contended it discriminated against resources that first clear in FCA 14 because those that cleared in earlier auctions are not affected by the change.

But the commission said resources that clear for the first time in FCA 14 and future FCAs are not “similarly situated” to those that cleared earlier.

“This existing noncommercial capacity has already been subject to the previous financial assurance requirements and enters FCA 14 with settled expectations as to its financial assurance responsibilities. As a result, this existing capacity would have secured financing and/or made arrangements in anticipation of, and contingent upon, the incumbent financial assurance requirements,” the commission said. “By contrast, new noncommercial resources will enter FCA 14 without regard to previous financial assurance requirements and unbeholden to any commitments based on anticipated financial assurance responsibilities.”

FCA 14, for capacity commitment period 2023/24, begins at 8 a.m. on Feb. 3.

January 21, 2020February 12, 2025

NEPOOL Markets Committee Briefs: Jan. 14-15, 2020

WESTBOROUGH, Mass. — ISO-NE’s Energy Security Improvements (ESI) proposal neared the finish line last week as study refinements showed a reduced level of total customer payments compared with preliminary results reported in December.

Stakeholders questioned the RTO’s methodology and timing.

Todd Schatzki of Analysis Group present ed new impacts analysis to the New England Power Pool Markets Committee on Wednesday that included updated results for the winter month central case and selected other winter scenarios.

The results for the central case of a representative winter month showed total customer payments increasing in two out of three scenarios, compared to all three in the results shared at the December MC meeting. But total customer payments are lower across all cases in the latest analysis compared with the December results. (See NEPOOL Markets Committee Briefs: Dec. 10-11, 2019.)

The RTO has less than three months to meet an April 15 deadline to file a long-term fuel security mechanism with FERC (EL18-182). The Participants Committee likely will vote on the new market construct at its April 2 meeting. The program would use financial incentives in day-ahead options and forecast energy requirement (FER) payments to persuade generators to buy fuel in advance to avoid shortages during periods of extreme cold.

The new results from Analysis Group reflected ESI shortage prices above those currently proposed by ISO-NE and adjusted solar and wind’s participation in the day-ahead market.

The new analysis showed that in the “frequent” stressed conditions scenario, total payments by load would increase 3.7% to $4.27 billion, with $257 million in FER payments and $222 million in day-ahead option payments partially offset by a $174 million reduction in payments for energy and real-time operating reserves.

Under the “extended” stressed conditions case — based on 2017/18, with its one long cold snap — load costs would decrease $63 million (-2.3%) to $2.66 billion.

The “infrequent” stressed conditions case, based on 2016/17, showed $1.8 billion in load costs, a $48 million (2.8%) increase.

The other scenarios studied produced a wide range of outcomes in customer costs, from a reduction of $316 million (increasing load by 5%) to an increase of $407 million (the “no incremental oil” scenario). Schatzki said the results reflected factors including changes in market tightness, risk premiums and replacement energy reserve (RER) quantities.

Fixed Strike Price Adder

New England States Committee of Electricity (NESCOE) Director of Analysis Jeff Bentz presented a proposal for a $10 adder on the strike price, saying, “We really do remain concerned that consumers could be left on the hook for costs.”

[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to amplify their presentations.]

Increasing the strike price by $10/MWh in all hours, as ISO-NE proposes, reduces the frequency of option striking and should lower costs, according to NESCOE. The fixed-price adder has a minor effect on incentives to cover the call and deliver energy, which translates into a minor effect on energy security. It could also increase participation under the ESI proposal, which increases the likelihood of the design being successful.

“The fixed dollar amount adder diminishes the ‘noise’ of uncertainty … and we don’t think this materially affects the incentive,” Bentz said. “It’s all about cost and benefits.”

NESCOE believes the $10 adder will reduce the cost and risk of the option for sellers, which should reduce the clearing prices and cost to consumers while maintaining strong incentives.

As part of a broader market power mitigation package under the amendment, resources with a capacity supply obligation would be subject to a must-offer requirement.

As recommended by Connecticut regulators, NESCOE wants regular assessments of the competitiveness of ESI and the call option offers.

ESI Methodology in Question

Christina Belew of the Massachusetts attorney general’s office presented two amendments: one to eliminate RER from the ESI design, and the second to add a look-back provision to the ESI program to enable evaluation of its efficacy.

The look-back would take place after ESI has been in effect three years and would use evaluation criteria vetted through the NEPOOL stakeholder process. “We chose a three-year period before reporting because we felt that was adequate to acquire indicative performance data,” Belew said.

On the proposed amendment to eliminate RER, her colleague Ben Griffiths, an energy analyst for regional and federal affairs, questioned the cost-effectiveness of the product and the RTO’s rationale that RER ensures the day-ahead market will award sufficient “replacement energy” options to restore operating reserves consistent with NERC/Northeast Power Coordinating Council restoration time standards.

In addition, RER is intended to account for load forecast error, but the RTO does not define the methodology to be used.

“Unlike the more formulaic requirements of generator contingency reserves [GCR] and energy imbalance reserves [EIR], this open-ended load forecast error makes me uncomfortable,” Griffiths said. Increasing RER requirements leads to “modest impacts on fuel security but could entail large impacts on costs, which doesn’t strike me as prudent.”

“I’m still struggling with a lack of value, a lack of design,” Griffiths said. “From what we’ve done so far, I feel we should proceed with parts that we have a better understanding of, especially because the results don’t show any fuel security benefit, even though our mandate in this docket was narrowly tailored to addressing fuel security.”

The RTO’s lead analyst for market development, Ben Ewing, presented the following day and concluded that RER is a conceptual extension of GCR, and that both awards “cascade down” and their respective clearing prices “cascade up” while ensuring the RTO’s ability to meet reliability standards.

LNG Contracts

Karen Iampen of Repsol, which operates the Canaport LNG terminal in New Brunswick, Canada, said that ISO-NE is misrepresenting or misunderstands how LNG contracting works, and that because LNG contracts require market commitment prior to being procured and scheduled weeks in advance, developing financial options around a day-ahead price does not ensure fuel security.

“Revenue certainty is the only thing that will persuade generators to stock up on LNG or natural gas,” Iampen said.

In his presentation, Schatzki said LNG contract structure is not a “key determinant” in the model’s estimates. He admitted that “the model’s ‘full supply’ assumption may overstate available LNG in some cases” but said a scenario with less LNG available produced ESI impacts similar to the central cases.

Gary Ritter of Excelerate Energy, which runs the Northeast Gateway Deepwater Port for LNG, situated 13 miles offshore Boston, said his company shares many concerns with Repsol.

“Right now, in the middle of January, we are not present here with a [floating storage and regasification unit],” Ritter said. “We don’t have a dedicated ship for New England, not to say we’re not committed to the region. We just need an appropriate commitment.”

— Michael Kuser

January 21, 2020

SPP MOPC Briefs: Jan. 14-15, 2020

SANTA FE, N.M. — SPP staff are expected to return to the Markets and Operating Policy Committee in April with a proposal for either a small task force or something more expansive in developing a “strategic survey” following numerous occurrences of conservative operations last summer.

Senior Vice President of Operations Bruce Rew said the survey would be used to educate staff and stakeholders on possible issues with a summary report given to the MOPC in October. (See SPP Shortfall Leads to Scarcity Pricing Calls.)

The report generated significant discussion among stakeholders, including calls for scarcity pricing, and a request for additional member feedback from MOPC Chair Holly Carias.

SPP MOPC — January’s MOPC meeting | © *RTO Insider*

Rew summarized that feedback as being in four subject areas: supply adequacy, pricing, reliability and task force. He said respondents indicated continued support for scarcity pricing and the continued development of market products. That feedback has been turned over to the Market Working Group (MWG).

Members also expressed support to adopt best practices from other RTOs and ISOs in coordinating outages, he said.

“Maybe we need to have this discussion,” Golden Spread Electric Cooperative’s Mike Wise said, complaining about his staff’s recent difficulty in getting generator maintenance outage requests approved. “If you don’t allow these units to go into outages to get this maintenance, that will be trouble for us. I think it’s apparent something has shifted in your staff about not wanting to approve outages.”

Rew said staff have taken a more conservative approach to approving outages.

“When you’re looking at generation outages in the future, what do you consider the load to be at the time? What do you consider for wind?” he said. “We want to ensure we don’t take too many outages. One of the criticisms we got was that we were approving too many outages.”

Staff are evaluating and may revise their practices, Rew said. Currently, staff deny an outage request when they find the unit will be necessary for even just one day during the outage period, he said.

“If you can’t do maintenance, you’re going to have forced outages anyway,” Southwestern Public Service’s Bill Grant said. “Your solution is not acceptable.”

“I agree,” Rew responded. “We need to improve that. We’re moving that needle back to more in the middle.”

Generation shortfalls and sudden drops in wind energy last summer led to SPP calling its first energy emergency alert since becoming a consolidated balancing authority in 2014. The RTO also operated under conservative operations seven times during the summer.

Western RC Services, Market on Track

In what he promised would be his last presentation on SPP’s reliability coordinator services in the Western Interconnection, Rew said the transition from Peak Reliability to SPP has gone well with “no specific concerns.”

The RTO’s RC function went live on Dec. 3 for 16 entities with 100 GW of net energy for load. (See Westward Ho: SPP Now a Western RC Provider.)

SPP is also building its Western Energy Imbalance Service (WEIS) market, scheduled to go live in February 2021. The RTO has executed joint dispatch agreements with WEIS’ seven participants, and an executive committee has approved an operating tariff for the market. SPP’s Board of Directors will take up the tariff for consideration Jan. 28 before it’s sent on to FERC for final approval.

MOPC Nixes Response to FERC Z2 Remand

The committee rejected the Regional Tariff Working Group’s (RTWG) proposed RR376 that allows FERC to reopen transmission customer invoices as part of the commission’s 2019 remand order for Attachment Z2 credit payment obligations. (See FERC Reverses Waiver on SPP’s Z2 Obligations.)

In the order, FERC noted that the SPP Tariff did not contain language that allows the commission to order the reopening of an invoice after it is considered finalized. The RTWG addressed the agency’s concerns with language patterned after the NYISO Tariff referenced in the Z2 remand order. RR376 would have allowed reopening of invoices if there were “extraordinary circumstances” and that “significant injustice would result in the absence of commission action.”

GridLiance High Planes, Lincoln Electric System and Nebraska Public Power District all abstained from the vote.

Members did endorse without discussion the RTWG’s RR393, which establishes a procedure to expedite requests for replacement generating facilities. The change would allow existing facilities to be replaced with new ones without going through the full generator-interconnection study process.

Stakeholder Group Consolidation Waits on Analysis

Nickell, the MOPC’s staff secretary, said the consolidation of stakeholder groups continues, but that SPP still needs a cost-benefit analysis to further support an organizational structure based on functional responsibilities. (See “SPP Stakeholders React to Proposed Working Group Consolidation,” MOPC Briefs: July 16-17, 2019.)

“We need to ensure the groups don’t just have technical and policy backgrounds, but the talent, expertise and skill sets to develop business practices, Tariff language or criteria language,” Nickell said.

“The costs associated with working groups is pennies, compared to the other costs of SPP participation,” Lincoln Electric System’s Dennis Florom said. “I would be more concerned about losing stakeholder participation in the process. We’ve built up a member-driven organization, and that’s what sets us apart.”

The Balancing Authority Operating Committee and Operating Reliability Working Group are already well underway with their consolidation into a single group. The MOPC’s approval of the consent agenda endorsed RTWG RR386, which facilitates their merger by eliminating the requirement for alternate members.

Members Pass 12 Revision Requests

The MOPC unanimously approved an MWG revision request (RR 3 82) intended to minimize potential gaming opportunities identified by the Market Monitoring Unit. The change allows market-committed resources that have a minimum run time extending beyond initial reliability unit commitment or day-ahead commitment periods to be eligible for make-whole payments after their initial commitment period.

RR382 replaces RR306, which was passed in 2018 by both the MOPC and the board. However, when SPP’s legal department drafted the FERC filing, it found that the Tariff conflicted with RR306, requiring a redo of some of the change’s sections.

The MOPC approved the withdrawal of RR306, which was on the consent agenda.

Members also unanimously approved the Supply Adequacy Working Group’s recommendation to provide a testing exception for derated generating units (RR389). Resources that were out of service or derated because of a forced outage during the preceding peak season can satisfy an operational test requirement after repairs are complete.

The consent agenda included 10 RRs and a sponsored upgrade for a 115-kV project in southern Nebraska. EDF Renewable Energy proposed the re-conductor and rebuild of the transmission lines, which staff’s study estimated will be in service by 2023 at a cost of $12 million.

The approved RRs were:

BPWG RR369: Updates the notification-to-construct (NTC) business practice’s (BP 7060) guidance to allow all future cost-allocated upgrades greater than 100 kV, and with estimates of $20 million or more, to be reviewed using the same methodology and decision structure as those currently defined as “applicable,” whether or not SPP issues an NTC. “Applicable” projects currently include any SPP-directed legacy construction projects meeting those voltage and cost thresholds.
ESWG RR388: Sets up specific modeling criteria for modeling internal and external resources plans and phase-shifting transformers. Also standardizes items for Integrated Transmission Planning (ITP) scope items consistent over multiple studies.
ESWG RR396: Removes certain sensitivity analyses during the ITP assessment of the recommended portfolio, providing more time to perform more informative sensitivities relevant to futures assumptions.
MWG RR380: Allows for a more appropriate and accurate calculation of the out-of-merit energy (OOME) instruction’s financial impact for a resource by adding logic to ensure evaluation of both the OOME basepoint and the resource’s response.
MWG RR387: Modifies protocol and Tariff language to allow flexibility in the real-time balancing market’s execution and modifies intra-day reliability unit commitment language for planned and unplanned outages.
MWG RR397: Corrects bill determinant names identified within the calculations for RR266, which proposes to allow any resource to elect to be a “combined ownership resource” through a modeling option.
MWG RR398: Corrects the contingency reserve deployment test flag to ensure it is only applied to specific intervals instead of the entire commitment.
RTWG RR386: Facilitates the consolidation of the Balancing Authority Operating Committee with the Operating Reliability Working Group by eliminating the requirement for alternate members.
RTWG RR394: Separates Attachment AO of the Tariff into two separate agreements: (1) for pseudo-ties between SPP and an external BA when there is a joint operating agreement or another agreement with provisions for pseudo-tie coordination; and (2) an agreement for pseudo-ties between SPP and an external BA when there are no provisions for pseudo-tie coordination.
TWG RR392: Provides clarity and adds additional language to support NERC compliance related to TPL-001-4 (Transmission System Planning Performance Requirements) and MOD-032-1 (Data for Power System Modeling and Analysis) standards.

— Tom Kleckner

January 21, 2020

SPP Members Delay Decision on 2021 Tx Assessment

By Tom Kleckner

SANTA FE, N.M. — SPP stakeholders last week delayed a decision over the weighting of futures and the use of economic must-run modeling in the RTO’s 2021 transmission planning assessment.

Staff and the Economic Studies Working Group committed to providing additional information to the Markets and Operations Policy Committee during its April meeting in Little Rock, Ark.

The ESWG last month agreed on a 60-40 weighting split between Future 1 — the “business-as-usual” case that reflects current trends — and Future 2, which is driven by assumptions that distributed generation, demand response, energy efficiency and energy storage will have a major effect on load and energy growth rates. The ratio passed both the ESWG and Transmission Working Group with a single abstention each.

Renewable interests favored a more aggressive forecast that incorporates additional energy growth. Others, wary of increasing transmission costs, favored a more conservative approach. Future 1 projects about 32 GW of wind installations by 2031, while Future 2 foresees about 37 GW.

Casey Cathey, SPP’s manager of reliability planning and seams, said that a similar 60-40 split in the 2019 Integrated Transmission Planning assessment would not have changed its final results for identifying transmission needs.

“Some people think there should have been more wind assumptions,” Cathey said. “In the end, after all that debate, it would not have budged our 2019 portfolio.” (See “MOPC Approves $336 ITP Portfolio,” SPP MOPC Briefs: Oct. 15-16, 2019.)

SPP Senior Vice President of Engineering Lanny Nickell suggested identifying reasonable outcomes and assigning them probabilities.

“Once you do that and you’re confident you considered the outcomes, you’re going to make the best quality decision at that time,” he said, noting no one had mentioned the implications of extended tax credits for wind energy.

“It feels like whether you want chocolate or vanilla ice cream. There’s no scientific basis,” SPP Board Chair Larry Altenbaumer said during the Strategic Planning Committee’s meeting Wednesday. “Some prefer one; some prefer the other. That feels lacking to me. It doesn’t seem a very good way to get to where we need to be.”

Must-run Review

Also drawing considerable stakeholder discussion was the ESWG’s plan to assign economic must-run designations to cogeneration, nuclear and hydro units. Exceptions would have to be requested during the generation review and approved by the working group.

However, a list shared with stakeholders included several coal-fired units previously granted exceptions, including Sunflower Electric Power’s 349-MW Holcomb 1. The 37-year-old unit in western Kansas has been often criticized for causing congestion in the area and creating the need for additional transmission investment.

Al Tamimi, Sunflower’s vice president of transmission planning and policy, told RTO Insider that the utility is contractually obligated to a coal delivery contract, executed in 2004 before it became an SPP member, that does not expire until 2034.

Tamimi said no studies completed through the planning-study processes confirm the assertion that congestion will be reduced by removing Holcomb from the list of economic must-run units. Energy exported from Sunflower’s transmission zone far outpaces Holcomb’s production during periods of high wind and also increases congestion, he said.

“As a must-run unit, [Holcomb] … will be dispatched down during high-wind periods … and dispatched up during periods when wind output is lower, which will help alleviate congestion on the byway lines around the unit,” Tamimi said. “Removing coal units like Holcomb from the economic must-run list will most likely drive new economic transmission capital projects to Sunflower’s [transmission] zone. If the new transmission is byway-funded, the Sunflower zone pays almost 70% of its cost and receives negative benefit from it.”

Greg McAuley, Oklahoma Gas & Electric’s director of RTO policy and development, said his concerns about including Holcomb on the economic must-run list centered around the potential effect of a unilateral decision to self-commit a unit out-of-merit on transmission planning.

“We simply want to ensure that we’re all being treated fairly, and that our customers are not being asked to pay for unilateral decisions made by other entities,” McAuley said.

SPP Transmission Assessment — ESWG Chair Alan Myers (standing) huddles with SPP’s Casey Cathey. | © *RTO Insider*

Coincidentally, while the MOPC meeting was taking place, Sunflower announced it would let its air permit for a proposed second Holcomb unit expire in March. Colorado-based Tri-State Generation & Transmission’s decision to pull out of the $2.2 billion, 895-MW project was the final straw for a project first proposed in 2005 during former Kansas Gov. Kathleen Sebelius’ administration.

ESWG Chair Alan Myers, with ITC Holdings, was able to secure approval of leveraging existing processes to model member-submitted loads from the Bakken shale play in the upper Midwest area; to begin developing approaches that address winter-peaking and cold-weather-driven reliability issues for incorporation in SPP’s normal planning processes; and obtain a waiver of the ITP manual’s requirement to use resource planning software in the 2021 assessment.

Members also approved an ESWG revision request (RR395) that creates a hybrid methodology for gas price forecasts by averaging multiple sources.

January 21, 2020

California PUC to Examine Gas Safety, Reliability

By Hudson Sangree

The California Public Utilities Commission launched an examination Thursday of the state’s natural gas infrastructure and the rules governing it for the first time in 16 years, citing accidents and declining demand as threats to the system’s safety and reliability.

“California’s energy system is undergoing a period of profound change,” Commissioner Liane Randolph said. “We have committed to the goals of 100% clean energy, doubling of energy efficiency, widespread transportation electrification and a carbon neutral economy by 2045. Given these adopted objectives and policies we should anticipate and plan for the long-term changes in California’s gas distribution system as well.”

The dozen companies named as respondents by the CPUC include Pacific Gas and Electric, San Diego Gas & Electric and Southern California Gas.

“Since the commission’s last decision in [January 2004], several events, such as greenhouse gas legislation, operational issues and constraints, and gas pipeline and storage safety-related incidents, require the commission to re-evaluate the policies, processes and rules that govern gas utilities,” the commission said in its order instituting rulemaking (OIR).

California PUC — The Aliso Canyon natural gas storage facility experienced a massive leak in 2015. | *California Governor’s Office of Emergency Services*

It noted that PG&E was found responsible for the explosion of a 30-inch gas pipeline in 2010 that killed eight people in San Bruno, south of San Francisco. Afterward, the commission adopted a safety plan requiring operators to outline how they would replace or pressure test all intrastate gas pipelines that hadn’t been tested recently at a cost of more than $2.3 billion.

Then in October 2015, SoCalGas identified a leak at its Aliso Canyon natural gas storage facility, which spilled 120,000 metric tons of methane before it was capped nearly four months later. Gov. Jerry Brown ordered a halt to gas injections at Aliso Canyon.

State regulators, including the CPUC, allowed limited injections to resume at Aliso Canyon in July 2017. The continuing limitations have constrained gas supply in Southern California, leading to higher wholesale electricity prices and reliability concerns. (See CPUC OKs Temporary Increase in Aliso Canyon Injections.)

Problems with interstate pipelines have also impacted supply. About 30% of the state’s electric supply comes from gas-fired generators.

Meanwhile, the state has enacted stringent GHG emission laws and required decarbonization of the grid by midcentury. Cities, including Los Angeles and San Francisco, have introduced rules and incentives to eliminate gas heating and appliances from certain classes of buildings. (See West Coast Pushes for Building Electrification.)

Falling Demand, Rising Costs

The demand for natural gas is expected to decline significantly over the next 25 years, leaving those still dependent on gas to pay the costs, the commission said in its OIR.

“Ratepayers who remain on the system the longest will likely be customers who may not be able to afford to switch from gas to electric home heating and cooling systems; yet, these customers would be required to cover the revenue requirement of the remaining pipeline system at higher rates,” it said.

In an October 2019 report titled “Natural Gas Distribution in California’s Low-Carbon Future,” the California Energy Commission discussed the “feedback effect” of building electrification and declining gas use.

“If demand for natural gas in California falls dramatically because of some combination of policy and economically driven electrification, the fixed costs to maintain and operate the gas system will be spread over a smaller number of gas sales and, ultimately, will increase costs for remaining gas customers,” the commission said.

“This outcome raises the possibility of a feedback effect where rising gas rates caused by electrification spur additional electrification,” it said. “Such a feedback effect would threaten the financial viability of the gas system, as well as raise substantial equity concerns over the costs that remaining gas system customers would face.”

The CPUC said the goal of its OIR is to ensure reliable gas service to customers at just and reasonable rates going forward.

The “proceeding will examine how industry-related events that have occurred since the last OIR require the commission to change the rules, processes and regulations governing gas utilities, including, but not limited to, reliability standards, long-term contracting, regulatory accounting, reporting and tariff changes for operational flow orders,” the commission said.

The OIR outlines a three-phased approach, starting immediately.

The first phase will examine reliability standards for the gas transmission system to determine if design changes are needed to account for a changing climate and the service capacity of current and future gas system infrastructure.

The second will consider proposals for mitigating the negative effects that “operational issues with gas transmission systems have on wholesale and local gas prices, and gas system and electric grid reliability.”

Phase three will weigh regulatory solutions and strategies the commission should implement “to ensure that, as the demand for natural gas declines, gas utilities maintain safe and reliable gas systems at just and reasonable rates, and with minimal or no stranded costs,” the CPUC said.

January 21, 2020

Texas PUC Approves LP&L Integration Project

The Texas Public Utility Commission last week approved modifications to proposed transmission lines necessary to integrate Lubbock Power & Light load into ERCOT (48909).

The approval came during the PUC’s open meeting Thursday, following a quick sidebar agreement between Oncor and the city of Lubbock over the project’s dividing point. The project will connect a 345-kV Oncor line with a 115-kV switchyard and line being built by LP&L.

LP&L Integration Project — Oncor counsel Jaren Taylor (left) and LP&L counsel Lambeth Townsend describe their companies’ agreement.

Oncor’s portion of the project could cost as much as $84 million and LP&L’s portion $61.5 million. The municipality is on the hook for $30.2 million in switchyard costs.

The project is one of several needed to move 470 MW of Lubbock’s load from SPP to ERCOT. (See “LP&L Lines for ERCOT Integration near Final Approval,” Texas PUC Briefs: Sept. 12, 2019.)

In other actions, the PUC:

approved Entergy’s request to amend its transmission cost recovery factor and recover $19.4 million (49874).
was notified by Commissioner Arthur D’Andrea that he has directed outside counsel to intervene in a MISO docket at FERC related to the treatment of energy storage facilities as transmission assets (ER20-588). (See Despite Pushback, MISO Pursuing TO-only SATA.)

— Tom Kleckner

January 21, 2020

Disasters Prompt California Rate Case Change

By Hudson Sangree

The effort to prevent utility equipment from causing disasters was a major reason the California Public Utilities Commission decided Thursday to extend the general rate case cycle for the state’s investor-owned utilities from three years to four.

After the 2010 San Bruno gas pipeline explosion and years of catastrophic wildfires starting in 2007, the commission opened its general rate case (GRC) rulemaking in 2013 “out of concern that the energy utilities were not explicitly or adequately addressing safety and reliability issues in their GRC funding requests.”

In December 2014, the commission added a Risk Assessment Mitigation Phase and the related Safety Model Assessment Proceeding to the IOUs’ rate cases. The protocols require IOUs to examine the risks they face and propose strategies to mitigate those risks, which the commissioners must then approve. (See CPUC Adds RAMP Costs to Rate Case for 1st Time.)

California Rate Case — | *California governor’s office*

In its latest decision, the commission said moving to a four-year GRC cycle would bolster disaster-prevention efforts.

“The longer cycle will allow the utilities and stakeholders to dedicate more time to implementing the new risk-mitigation and accountability structures that this commission established earlier in this rulemaking, and less time litigating GRC applications,” it said.

The longer cycle also will let the commission monitor “utility spending in something closer to real time, especially when the utility decides to reprioritize authorized funding for another purpose.”

With circumstances changing quickly because of wildfires, utilities have had to redirect money to fire prevention efforts such as tree trimming, line inspections and repairs. (See California Regulators OK Utility Wildfire Plans.)

In addition, the commission said it hoped the four-year cycle would improve efficiency in the GRC process, which can be delay-prone, by providing more time to work through difficulties.

“General rate cases are the bread and butter of what we do,” Commissioner Clifford Rechtschaffen said at Thursday’s meeting. “They’re very complex, very time consuming,” and at least one rate case is always pending, he said.

In a GRC, the commission authorizes a utility to recover capital investments and annual operations and maintenance expenses through rates charged to customers. Fundamental principles include balancing the needs of investors and ratepayers and providing safe and reliable service at a reasonable cost.

The commission’s unanimous decision said the “task we face is how to adhere to these principles in a world where — as all stakeholders can surely agree — events are moving much more quickly than can be accommodated by the existing GRC process.”

“In such circumstances, the importance of commission oversight in the midst of a utility’s GRC cycle increases,” it said. “It is no longer sufficient for the commission to authorize a multiyear GRC revenue requirement for the utility and then sit back and wait for the utility and intervenors to report back three years later regarding whether the utility spent the authorized amounts, for specifically authorized purposes, or found it necessary to use the funds elsewhere.”

The move to a four-year cycle was supported by two of the state’s large IOUs, Pacific Gas and Electric and San Diego Gas & Electric, and by the commission’s Public Advocates Office.

PG&E said the four-year cycle would allow for adjustments to the revenue requirement to address unusual circumstances and give the commission more time to weigh “the extraordinary amount of evidence” in GRCs.

CPUC staff, Southern California Edison, the state’s second largest IOU, and The Utility Reform Network, a consumer advocacy group, objected to the move.

Staff expressed concerns about switching to a four-year cycle, citing potential problems such as increased uncertainty about forecasted expenditures in the additional fourth year.

SCE did not oppose a four-year cycle outright but said it worried the longer cycle would lead to shortfalls in authorized spending. It asked for “greater tolerance on the part of the commission and parties with respect to errors and variances in forecasting.”

The new four-year cycle and other provisions incorporated into the order take effect June 30. A series of workshops to deal with implementing the changes and increasing efficiency in the GRC process will take place over the next year, the commission said.

January 21, 2020

MISO Gauging Aftershocks of TO Self-fund Order

By Amanda Durish Cook

CARMEL, Ind. — MISO is still assessing the impact of FERC’s recent order reinstating transmission owners’ rights to self-fund network upgrades while renewable proponents express worry the decision could significantly increase the cost of new generation.

The RTO is currently sorting through generator interconnection agreements struck over a three-year period to determine which need to be revised to allow TOs the opportunity to fund network upgrades, MISO counsel Mike Blackwell told stakeholders at a Jan. 14 Interconnection Process Working Group (IPWG) meeting.

MISO previously reinstated TOs’ right to self-fund starting Aug. 31, 2018, anticipating FERC’s final December order on the matter. (See Ruling Reinstates MISO TO Funding of Upgrades.) That leaves contracts signed between June 24, 2015, and Aug. 31, 2018, open to alterations.

MISO Self-fund — MISO counsel Mike Blackwell | © *RTO Insider*

“We are working to determine which of those interconnection agreements would need amendments,” Blackwell said.

He said MISO would also create “companion facility service agreements” to work out refunds to interconnection customers on network upgrades that are already being constructed.

Those agreements would vary based on how far along construction is, Blackwell said. “We are working to determine the full breadth of filings that will need to be made.”

MISO’s renewable generation proponents remain unhappy with FERC’s decision, with some arguing that the ability of TOs’ to both bill for the cost of upgrades and charge rates to use them stands to increase costs for interconnection customers, as TOs will essentially issue them loans with interest for the network upgrades. Some fear that the prospect of accruing interest could add millions to the cost of new generation, making agreement amendments attractive to TOs.

Clean Grid Alliance’s Rhonda Peters asked how MISO would guarantee its responsibility under its Tariff to provide the least-cost solution to solving transmission constraints.

“There may be multiple approaches to solving a constraint,” Peters warned at the IPWG, suggesting that MISO may need to supervise TOs’ construction decisions.

Repeat Protests Under Facilities Service Agreement

The RTO also continues work on developing a standardized pro forma facilities service agreement (FSA) to reflect the self-fund option, recently the subject of a deficiency notice at FERC.

MISO filed separately in November to standardize the TO self-fund option with a new pro forma FSA that establishes interconnection customers’ terms of repayment (ER20-359). In late December, the commission said the agreement needed more specifics on, among other things, how MISO would calculate tax benefits TOs receive on network upgrades, whether TOs would use projected or actual formula rates in their monthly revenue requirement for the network upgrade, and why the RTO included expanded liability provisions not included in its generator interconnection agreement.

The American Wind Energy Association, CGA and the Solar Council — an ad hoc group of companies that are members of AWEA’s RTO Advisory Council — used the issue to again register displeasure with the reinstatement of TO self-funding, arguing that interconnection customers bear a lopsided amount of risk in funding network upgrades versus TOs.

“Under MISO’s proposal, the [interconnection customer] must take on 100% of the risk, in addition to paying the full cost and rate of return for any network upgrade. If a TO elects to self-fund the upgrade, and seeks to earn a rate of return on its investment, then it is appropriate that the TO should also bear the risks and costs associated with the upgrade. However, under MISO’s proposal, the TO bears no risk whatsoever,” the three groups wrote in a December protest of the new FSA.

“In contrast, the [interconnection customer] is required to post security that is reduced over the payment term of the network upgrade charge, effectively requiring the [interconnection customer] to tie up its own capital for upgrades that will ultimately belong to the TO, and which the TO receives a rate of return on.”

MISO officials maintain the protests are misplaced under the FSA proceeding. FERC has already made its decision, they said, and it likely won’t permit relitigating under a filing that merely serves to streamline a process for what’s already been decided.

“They should not be considered by the commission,” Blackwell said of arguments in an interview with RTO Insider. He added that MISO is drafting a response to the deficiency letter.

Moreover, Blackwell emphasized, TOs’ option to self-fund has been a reality in MISO since Aug. 31, 2018. Based on TOs’ current rates of exercising the self-fund option, he said he anticipates only a “small fraction” of the 2015-2018 agreements will need revisions.

Blackwell said he realized TOs’ scant participation in self-funding seems counterintuitive considering the prospect of earning a rate of return.

“You would think everyone would elect to self-fund,” but they don’t, he said.

MISO officials declined to speculate further on how many interconnection agreements might need amendments.

AWEA, CGA and the Solar Council have also protested the FSA’s proposed term of 20 years’ repayment for self-funded network upgrades, arguing that MISO also provide interconnection customers the options of upfront repayment and the more standard 10-year repayment term.

Deadline to Declare TO Self-fund

MISO is simultaneously considering imposing deadlines on TOs’ decisions to self-fund upgrades, possibly requiring them to definitively elect to self-fund “at some point in time” in the definitive planning phase process of the interconnection queue, Blackwell said. The proposal is the RTO’s own and not a result of a FERC directive.

The RTO is so far considering a requirement that TOs make a “general indication” of their intent to self-fund network upgrades, Blackwell said. However, that commitment would be “nonbinding and subject to change,” he added.

MISO is also contemplating making TOs declare their intention to self-fund before it publishes the results of its system impact studies.

Some stakeholders urged MISO to make sure it has an answer from TOs on self-funding before it begins system impact studies.

“I feel very concerned about the looseness of this proposal,” CGA’s Peters said.

Stakeholders also asked if creating deadlines might be discriminatory to TOs.

Blackwell said he didn’t think deadlines would impede a TO’s ability to decide to self-fund, pointing out that it could elect to fund one network upgrade and decline to fund another. He reiterated that the proposal was merely a first draft.

“We will definitely work to find a balance,” he told stakeholders. “We invite feedback from all stakeholders on the design … and how the deadline should be structured.”

He said MISO would likely file this year to implement a self-fund deadline.

January 19, 2020

PJM MRC/MC Preview: Jan. 23, 2020

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committee meetings Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:10-9:15)

B. Manual 38: Operations Planning — updates from the periodic cover-to-cover review and updated procedures.

1. Modeling Generation Senior Task Force (9:15-9:30)

After deferring on the issue in December, the MRC will consider a rule change that would implement “soak time” modeling of resources. (See “Modeling Generation Senior Task Force Recommendations,” PJM MRC Briefs: Dec. 19, 2019.)

The MRC endorsed recommendations from the task force last month that can be implemented in the near term while PJM focuses on completion of its next generation energy market (nGEM). But stakeholders requested more time to investigate the soak time recommendation after expressing concerns about the time and energy it would require.

Soak time refers to the minimum period a unit must run from the generator breaker closure until it is dispatchable.

The Modeling Generation Senior Task Force (MGSTF), assembled in 2017, developed the solutions to improve resource modeling for “complex resources” in PJM’s market clearing engines, including combined cycle units, coal units with multiple mills and pumped hydro.

2. Primary Frequency Response Task Force Update (9:30-9:40)

The committee will decide whether to keep the Primary Frequency Response Task Force on hiatus through the first half of 2020.

Primary frequency response (PFR) is the ability of generators to automatically change their output in five to 15 seconds when the grid’s frequency strays above or below 60 Hz. As more renewables enter the resource mix and coal plants retire, the grid can become more susceptible to these frequency swings, threatening system reliability.

In October, PJM said 583 units with capacities of 50 MW or greater were evaluated for PFR across 10 events between March and September. The selected events for analysis met one of three qualifications: frequency goes outside the +/- 40-MHz deadband, frequency stays outside the +/- 40-MHz deadband for 60 continuous seconds or minimum/maximum frequency reaches +/- 53 MHz.

No more than 28 units provided PFR during any of the selected events. In some cases, no units responded. PJM said most critical load and black start units evaluated did not provide PFR because many were offline, operating at maximum capacity or had inconclusive results.

The task force would continue to update the Operating Committee on a quarterly basis of PFR results across the RTO.

Members Committee

Consent Agenda (11:05-11:10)

The MC will be asked to endorse:

B. r evisions to the Operating Agreement endorsed by the Financial Risk Mitigation Senior Task Force and MRC to hold five long-term financial transmission rights auctions a year, instead of three, to increase oversight and visibility into portfolio conditions so that more collateral can be collected if necessary. The revisions also would alter the structure of Balancing of Planning Period auctions so that participants can buy and sell in any month of the year, rather than being limited to a specific quarter. (See “FTR Credit Rules Endorsed,” PJM MRC Briefs: Dec. 19, 2019.)

C. r evisions to the OA to implement changes to the competitive transmission proposal fee structure. PJM will charge a $5,000 nonrefundable flat fee to all developers who submit competitive proposals. Itemized study costs will be added as necessary. RTO officials said the current tiered approach doesn’t account for the increased cost of the new comparison framework that involves an independent consultant’s review and legal and financial analyses. (See “Competitive Transmission Proposal Fee,” PJM MRC Briefs: Dec. 19, 2019.)

D. r evisions to the Tariff and OA related to the hourly differentiated ramp rate changes originating from the MGSTF. The changes will increase the number of segments on the energy offer curve (2020); introduce hourly differentiated segmented ramp rates (late 2020) and implement the soak time parameter referenced in MRC item 1 above (2022).

E. r evisions to the Tariff and OA to align them with PJM’s actual implementation of market-based parameter-limited schedules. (See “Parameter-limited Scheduling Fix,” PJM MRC Briefs: Dec. 19, 2019.)

F. r evisions to the OA clarifying the requirements for sharing forecasted unit commitment data to transmission owners for reliability studies, to ensure consistency with NERC standards and PJM manuals.

1. Members Committee Resolution (11:10-11:35)

The MC could approve an advisory against TOs’ proposal for a new Tariff Attachment M creating a new, confidential process for projects to address NERC critical infrastructure protection standard CIP-014.

LS Power drafted the document and presented it at the Dec. 5 MC meeting as tensions over the TO proposal grow increasingly fraught. (See “Critical Infrastructure Resolution,” PJM MRC/MC Briefs: Dec. 5, 2019.)

The company said the attachment conflicts with the OA because it will move forward without any vetting from the MC. At the heart of company’s argument is a belief that incumbent TOs don’t get exclusive rights to handling critical infrastructure on NERC’s CIP-014 list. Because the projects could carry significant regional implications, LS Power believes PJM should plan their mitigation. (See PJM TO Filing Stirs Up Transparency Concerns.)

Incumbent TOs argue that NERC’s confidentiality standards — and their rights under PJM’s Attachment M-4 process — support their intention to file the mitigation plan at FERC without input from other sectors.

PJM maintained its neutrality in the debate and urged all stakeholders agree about mitigating critical assets so they are no longer vulnerable to attack. (See PJM Remains Neutral in CIP-014 Debate.)