Page 1145 – RTO Insider

January 26, 2020

NERC Reliability Standards Get FERC Approval

By Holden Mann

FERC on Thursday approved NERC reliability standards affecting transmission system planning performance and communications cybersecurity, while also proposing to streamline the ERO’s list of requirements.

Protection System Preparedness

The first standard approved at FERC’s open meeting was TPL-001-5, which NERC proposed last year because of concerns that TPL-001-4 does not provide a means for addressing single points of failure in protection systems (RM19-10). In 2009, NERC reported that such failures had caused three significant system disturbances in the previous five years. (See “Single Points of Failure,” FERC OKs Cyber Reporting Rule.)

FERC said the new standard also addresses its concern that the earlier standard’s six-month outage duration threshold could exclude planned maintenance outages of significant facilities from planning assessments.

Under the new standard, planning authorities and transmission planners will be required to perform annual planning assessments on their part of the bulk power system, considering a range of system conditions and contingencies with a risk-based approach. Possible incidents are organized by likelihood, with more common scenarios referred to in the standard as planning events, and less likely ones called extreme events.

For planning events, entities would have to develop corrective action plans (CAPs). A CAP is not needed for extreme events, but entities must still conduct an analysis to identify potential impacts and mitigation measures. The standard also requires entities to assess the impact of the unavailability of long lead-time equipment.

NERC Reliability Standards — Leigh Anne Faugust of FERC’s Office of General Counsel gives a presentation on the revised TPL and CIP reliability standards.

“Addressing single points of failure on the protection systems, when identified in routine system evaluations, will help prevent N-1 transmission system contingencies and those results from single points of failure from causing unreliable operations,” Leigh Anne Faugust, of the Office of General Counsel, said Thursday during a presentation on the revised standards.

The commission decided not to require NERC to develop CAPs for single points of failure combined with three-phase faults, saying the probability of such an event “is low enough that it does not warrant being a planning event.” Although there have been an average of one three-phase fault event every three months since 2011, only 10 were accompanied by such protection system failures.

The standard will be effective in 36 months, with another 24-month period allowed for entities to develop CAPs addressing commonplace scenarios.

Cybersecurity Scope Expansion

The critical infrastructure protection (CIP) standard, CIP-012-1, was proposed last year in response to FERC Order 822 to address the cybersecurity of real-time communications (RM18-20). (See FERC Proposes Revisions to NERC CIP Standard.) Entities will be required to protect the confidentiality and integrity of real-time assessment and monitoring data transmitted between BPS control centers.

Order 822 originally directed NERC to identify the types of data that must be protected under CIP-012-1, but in the presentation, Faugust said industry comments in response to FERC’s Notice of Proposed Rulemaking convinced the commission that this requirement was unnecessary.

But the commission told NERC it must further refine the standard to require protections regarding the availability of communication links and data as required by Order 822. The commission said it did not agree with NERC that such a requirement would be redundant.

“The reliability standards cited by NERC either do not apply to communications between control centers or do not create an obligation to protect the availability of data between control centers,” FERC said. “We conclude that the risks associated with losing the availability of either data or communication links between bulk electric system control centers is supported by the existing record and warrants a directive to modify the CIP reliability standards.”

The standard will take effect April 1, 2022, to allow time for implementing the new controls.

NOPR to Retire Requirements

FERC also gave preliminary approval to retire 74 reliability standard requirements that were found under NERC’s Standards Efficiency Review project to “either provide little or no reliability benefit, [be] administrative in nature, or relate expressly to commercial or business practices, or are redundant with other reliability standards” (RM19-16, RM19-17).

In response to a question from Chair Neil Chatterjee, Faugust said FERC was “not concerned” about the possibility that retiring the requirements would pose a risk to the BPS.

NERC had submitted three additional requirements for removal on the grounds of redundancy, but FERC’s NOPR would remand VAR-001-6 Requirement R2, which “requires transmission operators to schedule sufficient reactive resources to regulate voltage levels under normal and contingency conditions.” The commission observed that this is the only requirement that “explicitly [addresses] reactive resources.”

Decisions on the other two, FAC-008-3 Requirements R7 and R8, have been postponed as FERC seeks additional information from NERC. The commission said that “NERC’s petition does not address … elements of Requirements R7 and R8 that do not appear to be redundant,” in particular the mandatory exchange of facility rating-related information with transmission owners. If this mandate is not provided by other requirements, then the proposed retirement could prevent TOs from using accurate information in their planning models, FERC said.

Comments on the NOPR are due 60 days after its publication in the Federal Register.

Ongoing Action

In approving the items, FERC emphasized the importance of adapting to an evolving landscape of hazards.

“None of this is static. We’re constantly looking and need to keep looking at what’s changing, what needs to be updated, [and] what needs to be discarded because it’s no longer needed,” Commissioner Bernard McNamee said. “I think that’s something that we should all be proud of, that … we’re constantly looking at things. I know how hard NERC’s working on it, how hard you all are working on it, and I know the three of us are concerned with these issues.”

January 26, 2020

NERC Wins Another 5 Years as ERO

By Rich Heidorn Jr.

FERC on Thursday approved NERC as the Electric Reliability Organization for another five years while ordering the organization to audit its regional entities and improve its oversight of the Electricity Information Sharing and Analysis Center (E-ISAC).

It also ordered changes to NERC’s organization certification program and how it uses reliability and security guidelines and said it should provide more transparency about how it and the REs determine penalties (RR19-7).

NERC must submit a compliance filing in 90 days and updates to its Rules of Procedure in 180 days. NERC said Friday it was reviewing the order and had no immediate comment.

FERC said it found that “NERC continues to satisfy the statutory and regulatory criteria for certification as the ERO, and … that the regional entities continue to satisfy applicable statutory and regulatory criteria.”

The commission credited the ERO for shifting to a risk-based approach to focus on the most significant reliability issues and said it was responsive to suggested improvements from stakeholders.

FERC identified five areas for improvements: periodic RE audits; guidance documents; E-ISAC oversight transparency; sanction guidelines; and organization certification.

“The commission generally is satisfied with other features of NERC’s Rules of Procedure, including rules that provide fair and impartial procedures for enforcing reliability standards and rules that provide for broad participation, notice and opportunities for comment in developing reliability standards,” the commission said.

Regional Entity Audits

NERC’s Rules of Procedure and the regional delegation agreements it signed with the REs in 2007 require it to perform “comprehensive” audits of the REs’ compliance monitoring and enforcement programs (CMEPs) at least once every five years.

But after doing five limited audits through 2010, NERC failed to mention in its 2014 or 2019 performance assessment whether it had completed any audits. The commission noted that it rejected NERC’s attempt to eliminate the audit requirement in 2015.

An independent audit of NERC in 2016 concluded that it had failed to perform any comprehensive five-year audits of the REs’ CMEPs during 2013 to 2015, conducting only “limited oversight reviews.”

“We are concerned that, from 2011 through the end of 2018, NERC may not have performed comprehensive audits of the regional entities,” the commission said. It ordered NERC to produce any RE audits it has performed or provide a plan to perform them within the next 18 months and continue them going forward.

Efficacy of Guidance Documents

FERC also called for more transparency regarding the effectiveness of NERC’s reliability and security guidelines, noting that the organization developed more than 20 guidelines during the last assessment period, compared to only two during the prior five years.

“We are not aware of any formalized written process to steer the development and approval of guidelines or to provide feedback to the NERC standard development process on whether the guideline is effective,” FERC said. “Moreover, unlike the transparent standards development process, in at least some cases, guidelines are based on the input of a limited number of interested participants and NERC staff’s perspective is unknown. … NERC’s process and criteria for determining whether and when to develop mandatory reliability standards versus voluntary measures to comply with [Federal Power Act] Section 215, and how NERC uses information gained from the issuance of a guideline to improve or develop a new reliability standard, are unclear.”

The commission ordered NERC to explain its guidance development process and how it proposes to determine if guidance documents are addressing the risks and “how and at what interval NERC will evaluate whether components of the guidance document should be incorporated into the reliability standards.”

E-ISAC Oversight Transparency

FERC criticized the E-ISAC, saying that despite its growing share of NERC’s budget, its irregular public reports typically use “high-level information, such that the reports may be neither timely nor informative enough to assist the development of reliability standards.”

NERC created the E-ISAC in 1998 at the request of the Department of Energy to function as a means for voluntary information sharing. Its 2020 budget is 28% of NERC’s total spending — 37.5% including the Cyber Security Risk Information Sharing Program (CRISP), which allows real-time, computer-to-computer data exchange of potential security threats. CRISP is fully funded by participant fees.

FERC acknowledged that the E-ISAC’s Code of Conduct bars it from sharing information it receives with enforcement staff but said it does not appear to prohibit the sharing of information for the development of reliability standards. It ordered NERC to provide information on how the E-ISAC determines what data to share with NERC and how NERC uses the information.

The commission also called for NERC to clarify the E-ISAC’s relationship with the Electricity Subsector Coordinating Council’s (ESCC) Member Executive Committee (MEC) and how the MEC provides “strategic oversight and guidance” to the E-ISAC.

It said NERC must develop E-ISAC metrics for fiscal year 2020 and detail how it developed them and how they will help it oversee the E-ISAC.

“Recognizing the important role that the E-ISAC plays, it is imperative that NERC consider the perspectives of those stakeholders that rely on E-ISAC services to develop and track metrics to assess the performance of the E-ISAC,” FERC said. “Moreover, we believe that E-ISAC-specific metrics and goals used to assess the performance of the E-ISAC should be transparent and publicly available so that the stakeholders that rely on E-ISAC services can assess E-ISAC’s effectiveness and identify opportunities for improvement.”

Sanction Guidelines

The commission called for an update to NERC’s Sanction Guidelines to reflect its shift to a risk-focused enforcement strategy. It also directed the organization to provide more transparency regarding how it and the REs apply the base penalty, adjustment factors and non-monetary sanctions, including how they consider “the violator’s financial ability to pay the penalty” so that “no penalty is inconsequential to the violator to whom it is assessed.”

Organization Certification

FERC also called for improvements to the formal certification oversight program NERC introduced in 2018, saying “it is necessary to provide more specific guidance on the tools and skills needed to perform the registered function.”

The commission cited last year’s certifications of CAISO (RC West) and SPP as reliability coordinators to replace Peak Reliability as evidence of the need to include contingency plans in the program. “If either RC West or SPP had failed to meet certification requirements, there would be a period during which no entity is certified as the reliability coordinator responsible for performing critical reliability functions,” FERC said.

It also ordered NERC to establish minimum requirements for certification teams, including “necessary diversity in technical training and experience of team members specific to the function being certified.”

Performance Assessment

This is the third time FERC has reapproved NERC as the ERO in the 13 years since it was certified under the 2005 Energy Policy Act. FERC regulations required the ERO file an assessment of its performance three years after its initial certification in July 2006 and every five years thereafter.

In its performance assessment filed in July for June 1, 2014, to Dec. 31, 2018, NERC cited its development of reliability standards — it has completed more than 100 to date — and the refinement of its compliance and enforcement procedures.

NERC said that it made “continued progress” in reducing the ERO’s backlog of older violations and saw a drop in repeat moderate- and severe-risk violations in the last five years. After peaking in 2013 at 529, the number of moderate or severe violations dropped to 107 in 2018. Moderate or serious violations for entities with prior noncompliance with similar conduct dropped from a peak of 111 in 2016 to 22 in 2018.

The three-year rolling average of serious violations as a share of all violations (non-critical infrastructure protection and CIP versions 1-3) dropped from 4.9% for 2014-2016 to 3.3% for 2016-2018. Serious CIP violations dropped from 5.9% of all CIP violations in 2014-2016 to 3.9% for 2016-2018. NERC’s goal is to keep both measures below 5%.

NERC also cited a decrease in protection system misoperations and the expansion of its Generator Availability Data System (GADS) to include wind farms of 75 MW or more commissioned since 2005. It is planning to expand GADS further to include some solar projects.

During the assessment period, the ERO completed compliance monitoring arrangements with all Canadian provinces and increased its interaction with Mexico, signing a memorandum of understanding with Centro Nacional de Control de Energia (CENACE), the Mexican grid regulator.

January 26, 2020

FERC Grants Recovery on PATH Project Costs

By Christen Smith

FERC said last week its revised interpretation of accounting rules supports a rehearing request from developers of the abandoned Potomac-Appalachian Transmission Highline (PATH) transmission project, who are seeking recovery of $6.2 million spent on advertising, education and outreach (ER09-1256-03).

The ruling overturns, in part, FERC’s 2017 decision denying American Electric Power and FirstEnergy subsidiary Allegheny Energy recovery of costs the commission had categorized as lobbying and advertising expenses. (See FERC Orders Tx Refunds, Investigates Pipeline Rates in PJM.)

The $2.1 billion, 765-kV “coal by wire” PATH project was approved by PJM in 2007 to run from AEP’s John Amos coal generator in St. Albans, W.Va., to New Market in Frederick County, Md.

By 2011, however, PJM said the need for the line had moved several years beyond 2015 because of reduced load growth following the Great Recession. After ordering transmission owners to suspend work on the line pending a more complete analysis of all upgrades in its regional transmission plan, the PJM Board of Managers terminated it in 2012. PATH developers pursued cost recovery on the abandoned project totaling $121.5 million.

In 2012, two opponents from West Virginia filed a pro se intervention challenging the companies’ request for recovery of the lobbying and advertising campaigns that were intended to win political support for the project. FERC supported most of an initial decision by Administrative Law Judge Philip C. Baten, who found “that all of PATH’s expenditures were directed at obtaining a public convenience and necessity determination.”

FERC’s 2017 order directed AEP and FirstEnergy to refund ratepayers more than $7 million for the canceled project. The commission also found that PATH’s base return on equity should be reduced from 10.4% to 8.11% and disallowed recovery of $1.1 million in expenses booked into a wrong account.

But the commission said Thursday that, upon further reconsideration, efforts to obtain a certificate of public convenience and necessity “do not fall within the ambit of referenda, legislation, ordinances, the grant of franchise and the like because PATH’s efforts were in service of an RTO-approved project.”

“We find that general promotional efforts on behalf of an already approved project to obtain a finding of a public convenience and necessity are not the type of political activity included in the first clause of the regulation,” FERC said, referring to the rules governing which accounts developers can use for certain types of expenses.

In granting the rehearing, the PATH developers must recalculate the project’s total revenue requirement and account for refunds paid during the interim, FERC said.

The commission denied rehearing on PATH’s reduced ROE but ordered the developers to submit supplemental briefs and additional written evidence regarding how FERC’s proposed revised ROE methodology would apply to the proceeding. The methodology — replacing the discounted cash flow model with one that gives equal weight to the DCF and three other techniques — was developed after the D.C. Circuit Court of Appeals determined the commission’s existing formula was unjust and unreasonable. (See FERC Changing ROE Rules; Higher Rates Likely.)

January 26, 2020

MISO West Tx Construction Steady in 2020

By Amanda Durish Cook

Transmission buildout costs in MISO West under the 2020 expansion plan will look much the same as last year’s, RTO officials said last week.

The officials offered that prediction at MISO’s first West Subregional Planning Meeting of the year on Thursday. The meeting is part of a series held by subregions as MISO begins assembling its 2020 Transmission Expansion Plan (MTEP 20).

Some stakeholders have expressed concern over transmission development in MISO West — encompassing Minnesota, Iowa, parts of the Dakotas and western Wisconsin. They complain that proposed renewable generation in the RTO’s interconnection queue is inhibited in recent years by a lack of new capacity combined with prohibitively expensive network upgrades.

MISO has convened a special task team to address the increasing cost of network upgrades in its interconnection queue. Possible solutions involve linking the RTO’s annual transmission planning process with network upgrade planning. The synchronization could have MISO approving more transmission projects. (See MISO Seeks Ideas for Streamlined Tx Planning.) However, those changes will begin with MTEP 21, not MTEP 20.

MISO West transmission — MTEP 19 investment in MISO West versus projected MTEP 20 investment | *MISO*

MISO so far estimates similar spending on transmission buildout in West under MTEP 20 when compared to 2019, with both at nearly $790 million.

“We’ll likely have fewer proposed projects this year, but the investment remains the same,” MISO Manager of Expansion Planning Zheng Zhou told stakeholders.

Of that investment, transmission upgrades to accommodate interconnecting generators is predicted to increase year-over-year, from $103 million in MTEP 19 to a projected $133 million in MTEP 20.

MISO has yet to perform independent planning assessments on the MTEP 20 projects proposed by transmission owners. The assessments could identify project alternatives.

Meanwhile, the RTO continues to try to clear MISO West projects from its nearly 82-GW interconnection queue. It is working on negotiating and finalizing generation interconnection agreements for the two remaining generation projects representing 245 MW that entered the interconnection queue in the February 2017 cycle. That cycle once contained more than 5 GW of proposed wind and solar projects, and it was the sharp drop-off of generation projects that caused the stakeholder community to take notice of the transmission-constrained western region.

MISO also said it’s preparing generation interconnection agreements for 13 West projects at about 2.3 GW that entered the queue in August 2016. It identified about $269 million in necessary network upgrades for those projects.

Finally, the RTO reports that affected-system studies are ongoing for the crop of 27 West projects — comprising 4.1 GW — that entered the queue in August 2017.

MISO will hold two more West planning meetings before MTEP 20 approval, one in either May or June and another in August.

January 26, 2020

FERC Denies Rehearing on NYISO LCRs

By Michael Kuser

FERC on Thursday denied rehearing of its October 2018 order accepting NYISO’s revisions to the methodology it uses to determine locational minimum installed capacity requirements (LCRs), rejecting every one of the more than two dozen arguments made by the Long Island Power Authority (LIPA) and its subsidiary, Power Supply Long Island (ER18-1743-002).

NYISO’s installed capacity (ICAP) market rules require all load-serving entities to purchase a specified amount of capacity to count toward the statewide minimum installed reserve margin (IRM), based on each LSE’s coincident peak load. LSEs with customers in certain transmission-constrained areas, defined as “localities,” must fulfill a portion of their respective purchase obligations from capacity resources electrically located within those areas.

NYISO has designated three such localities: G-J, which is composed of load zones G, H, I and J in the Lower Hudson Valley; New York City (Zone J), which is nested within G-J; and Long Island (Zone K).

With the creation of the G-J locality, NYISO supplemented its former method, which recognized that the loss-of-load-expectation (LOLE) reliability standard used in setting the IRM may be achieved by carrying many different combinations of ICAP in various locations. The ISO now takes steps to calculate the LCR for the G-J locality.

In Thursday’s order, the commission found that the ISO’s alternative LCR methodology satisfies the 0.1-days/year LOLE reliability standard, which LIPA asserted was insufficiently demonstrated or certified.

“NYISO presented sufficient record evidence in this proceeding to support its claim that the alternative LCR methodology will meet the 0.1-days/year LOLE reliability standard,” the commission said. “Moreover, LIPA has not provided evidence that would persuade us otherwise.”

The commission also rejected LIPA’s request for additional technical details in the Tariff.

“We find unpersuasive arguments that the commission failed to address … NYISO’s alleged failure to model and analyze ‘known’ likely future system conditions; and the sensitivity of the alternative LCR methodology to actions, such as election of unforced deliverability rights, taken in Zone J that adversely affect Zone K,” the commission said. “LIPA’s arguments reduce to a disagreement with NYISO regarding the number and type of sensitivity analyses” that need to be performed.

January 26, 2020

NYISO DER Participation Model Gets FERC OK

By Michael Kuser

FERC on Thursday approved NYISO’s proposal to allow aggregations of distributed energy resources to participate in its markets.

The commission said the proposed model enhances competition “while also providing DERs with appropriate flexibility to meet various needs both within and outside the NYISO-administered wholesale markets” (ER19-2276).

“Among other considerations, NYISO’s filing facilitates the participation of DERs and other aggregations of resources in its wholesale markets by enabling heterogenous groups of technologies to aggregate and be compensated for services that they are collectively capable of providing,” FERC said.

A group of stakeholders — Advanced Energy Management Alliance, Advanced Energy Economy, Consumer Power Advocates, Energy Spectrum, Natural Resources Defense Council and the New York Battery and Energy Storage Technology Consortium — jointly contested the Tariff revisions regarding dual participation, metering and telemetry, installed capacity market requirements, and buyer-side mitigation.

Concept for DER coordination entity aggregation (DCEA) in energy, operating reserves and regulation markets | *NYISO DER Roadmap*

But the commission disagreed with their concern that NYISO’s requirement that market participants must “bid in a manner that ensures they will be dispatched by the ISO for the market intervals consistent with the manner in which the resource operates to meet such obligation(s)” creates a barrier to entry.

“We find that this proposed requirement appropriately balances any additional burden placed on market participants in determining their bids against the need for NYISO’s system operators and dispatch software to account accurately for the operation of dual participating facilities,” the commission said.

It also noted that the ISO did not propose any substantive changes to its market power mitigation provisions and, therefore, it found protests of the group, the New York State Energy Research and Development Authority and the state Public Service Commission to be beyond the scope of the proceeding. The protesters had contended that application of NYISO’s existing buyer-side market power mitigation rules to DER aggregations could result in over-mitigation of the resources.

FERC also on Thursday dismissed NRG Curtailment Solutions’ complaint over NYISO’s metering requirements, saying it had been rendered moot by its approval of the ISO’s DER aggregation model (EL18-188). The commission had granted NRG’s complaint in part in 2018 and establishing a paper hearing to determine an appropriate remedy.

January 26, 2020

NextEra Sees Competitive ‘Near Firm’ Renewables

By Tom Kleckner

NextEra Energy CEO Jim Robo said Friday that battery-backed “near firm” wind and solar power will be increasingly competitive by 2025.

Speaking during NextEra’s quarterly and year-end earnings call with financial analysts, Robo predicted that new near firm wind will be a $20 to $30/MWh product and near firm solar a $30 to $40/MWh product in five years.

“At these prices, new near firm renewables will be cheaper than the operating cost of most existing coal, nuclear and less efficient oil- and gas-fired generation units,” he said. “We will be at the vanguard of building a sustainable energy era that is both clean and affordable, and we are driving very hard to continue to be at the forefront of the disruption that is occurring within the energy sector.”

Robo said his company is poised to take advantage of the “enormous disruption” taking place within the nation’s generating fleet.

“Our confidence in renewables being the low-cost generation alternative in the middle of this decade remains stronger than ever,” Robo said. “We expect the disruptive nature of renewables to be terrific for customers, terrific for the environment and terrific for shareholders by helping to drive tremendous growth for this company over the next decade.”

The Florida-based company fell short of analysts’ expectations by reporting fourth-quarter earnings of $975 million ($1.99/share). Although that more than doubled 2018’s fourth-quarter earnings of $422 million ($0.88/share), NextEra’s adjusted earnings of $706 million ($1.44/share) came in below Zacks Investment Research’s consensus estimate of $1.54/share.

The company reported year-end earnings of $3.8 billion ($7.76/share), down from $6.6 billion ($13.88/share), in 2018. NextEra also reaffirmed a 6 to 8% growth rate in adjusted earnings per share through 2021.

Robo said NextEra’s performance “was strong both financially and operationally, and we had outstanding execution on our initiatives to continue to drive future growth across the company.” Wall Street sided with Robo, driving the stock price up $6.38 shortly after market open to close at $263.70.

Renewable energy will play a major role in NextEra’s ongoing performance. The company said NextEra Energy Resources, its wholesale electricity supplier, added more than 5.8 GW to its contracted renewables backlog and commissioned another 2.7 GW of wind and solar projects. More than half of the solar additions included a battery storage component, Robo said.

January 26, 2020

MISO, PJM Weighing New Interregional Study

By Amanda Durish Cook

Fresh off the approval of their first interregional transmission project, MISO and PJM are now contemplating a new study this year and asking stakeholders what direction it might take.

Staff from both RTOs laid out the possible options in a conference call of the MISO-PJM Interregional Planning Stakeholder Advisory Committee (IPSAC) on Friday.

PJM’s Alex Worcester said the study could take the shape of a targeted market efficiency project (TMEP) study, a special targeted ad hoc study or a two-year coordinated system plan, the last of which could culminate in the RTOs’ second-ever large interregional market efficiency project (IMEP).

Worcester asked stakeholders to submit ideas on the options by Feb. 26.

“What we’re looking for here is specific study suggestions,” Worcester said. He asked that stakeholders identify specific constraints or flowgates that could use analysis. “Saying there’s lot of congestion to be studied doesn’t really provide us a lot of direction.”

In December, the RTOs finished a data exchange on regional issues, newly approved projects near the seam and the latest historical market-to-market congestion information. They reviewed each other’s information over January.

The RTOs will hold another IPSAC meeting March 27 to explore the need for a new study. By mid-May, the Joint Regional Planning Committee — composed of planning staff from both RTOs — will render the final verdict.

MISO PJM Interregional Study — Michigan City-Trail Creek-Bosserman project map | *MISO*

During the call, a few stakeholders said they would be interested in the RTOs working on another TMEP. The two decided against conducting a third TMEP study process in 2019 after determining that only one year of additional historical data would be available coming on the heels of the 2018 study.

A TMEP must cost less than $20 million, completely cover its installed capital cost within four years of service and be in service by the third summer peak from its approval. The process has a shorter outlook than the RTOs’ IMEP process, which evaluates projects over a 15-year timeline.

Similarly, MISO and SPP will evaluate the need for a 2020 interregional study at their IPSAC meeting March 10.

Meanwhile, MISO is waiting on MISO, PJM Poised for 1st Major Interregional Project.)

The project needs MISO to implement cost allocation rules before it can proceed. MISO last week filed a plan with FERC to allocate interregional economic project costs to benefiting transmission pricing zones.

January 26, 2020

PJM Members Resist TO Critical Infrastructure Filing

By Christen Smith

PJM members endorsed a resolution Thursday that objects to a Tariff attachment pending before FERC that would create a new confidential process to mitigate critical infrastructure on NERC’s CIP-014-2 list.

The unusual step came less than a week after a group of transmission owners submitted the proposal to the commission following several tense conversations dating back to August that left other sectors wary of its vague details.

LS Power, author of the resolution, argues that incumbent TOs don’t get exclusive rights to handling critical infrastructure on the list. Because the projects could carry significant regional implications, the company believes PJM should plan their mitigation — a point other stakeholders echoed during the Members Committee meeting on Thursday. (See PJM TO Filing Stirs Up Transparency Concerns.)

PJM Critical Infrastructure Filing — The Members Committee on Jan. 23 debates a resolution from LS Power opposing a Tariff filing that would mitigate critical infrastructure projects.

“We feel strongly that PJM should have stepped up and taken this issue under its wing as a reliability issue,” said Carl Johnson of the PJM Public Power Coalition. “It would have saved us a lot of trouble.”

The resolution alleges that the filing also conflicts with the Operating Agreement because mitigating these critical assets — which count as a subset of supplemental projects — must involve an open and transparent discussion with stakeholders. But doing so, the TOs contend, poses the dilemma that the highly secretive location of these facilities could be revealed. (See “Critical Infrastructure Resolution,” PJM MRC/MC Briefs: Dec. 5, 2019.)

The TOs also point out 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 consent from other sectors.

In an effort to quell rising concerns, TOs collected questions from other stakeholders and hosted a webinar in November to answer some of them publicly. The two-hour meeting, however, left many issues unresolved. Seemingly frustrated by the unfolding process, the Planning Committee endorsed an issue charge in December to consider whether PJM must develop governing document language to deal with the mitigation of existing and future critical infrastructure on the list. (See “Critical Infrastructure Mitigation,” PJM PC/TEAC Briefs: Dec. 12, 2019.)

Top-secret Cost

PJM has refused to take sides in the debate, despite protests from stakeholders that mitigating the facilities presents risks to reliability that the RTO should handle. It’s a decision staff now question, Vice President of Planning Ken Seiler said. (See PJM Remains Neutral in CIP-014 Debate.)

“I agree, we could have done things differently,” he said, noting that a rough estimate of the cost to remove these assets from the list would total much less than $1 billion.

When stakeholders pressed for a more accurate cost estimate — key information many said may make them more comfortable with the Tariff filing — Seiler declined.

“We’ve looked at what the potential solutions would be and most of them are fairly simple,” he said. “Line rerouting, substation reconfiguration, very minor things that would keep the cost at a reduced rate for everybody … we are nowhere near into the billions of dollars on this.”

Sharon Segner, vice president of LS Power, said that although Seiler’s feedback was “encouraging,” there’s nothing in the Tariff proposal that caps costs.

“What would encourage my company even more would be for PJM to be in charge of these top-secret projects,” she said. “If PJM were to be in charge, then this language would go in the OA and not the Tariff. If it’s in the Tariff, at the end of the day, the TOs are in charge. There’s nothing in this language that provides cost containment. There’s a finite number of projects, but there is no restriction on cost.”

PJM Board of Managers member Susan Riley — who last month encouraged TOs and PJM to tally a cost for projects on the list — pushed back against sentiments that the RTO should have greater authority over the process.

“We’ve agreed to have an oversight role,” she said. “TOs have ultimate authority. I know the costs have been moving around, but they are moving down. We are reasonably confident that it won’t be more than $1 billion and won’t be more than 20 projects. We are committed in a very public way. Whether or not there wasn’t enough discussion, that’s up to you. I think there was.”

The MC endorsed the resolution in a sector-weighted vote of 3.83 to 1.17. Segner said LS Power intends to submit the resolution as part of its protest against the TO proposal. Comments on the filing are due within 21 days, Segner said, hence the timing of the vote.

January 26, 2020

FERC Stalls PJM Fast-start Compliance Filing

By Christen Smith

FERC said Thursday it will hold PJM’s fast-start pricing compliance filing in abeyance until July 31 in order to give the RTO enough time to resolve pricing and dispatch misalignment issues currently under review by stakeholders (ER19-2722).

In April, the commission ordered PJM and NYISO to revise their tariffs to allow fast-start resources to set clearing prices, saying their current rules are not just and reasonable. (See FERC Orders Fast-start Rules for NYISO, PJM.) PJM submitted a compliance filing in July that the Independent Market Monitor, state commissions and consumer advocates argued didn’t provide clear evidence that it would implement fast-start pricing correctly.

Specifically, the groups said that PJM uses different market intervals to calculate prices and dispatch instructions, suggesting that resources’ compensation doesn’t correspond to their dispatch instructions.

PJM Fast-start Filing — PJM control room | *PJM*

As part of its April order, FERC directed PJM to alter its real-time energy market clearing process to consider fast-start resources “in a way that is consistent with minimizing production costs.” The process requires PJM to first execute a cost-minimizing dispatch run, followed “by a pricing run where integer relaxation for fast-start resources allows them to set price.” The use of integer relaxation is intended to pinpoint a unit’s commitment costs in the pricing run and allow for their recovery through a market process rather than administrative methods.

“However, PJM may not be able to implement these separate dispatch and pricing runs in a way that is just and reasonable without first resolving the pricing and dispatch misalignment problem,” FERC said Thursday. “If fast-start resources dispatched in a given market interval could be compensated with a price from a different market interval, prices may not accurately reflect the marginal cost of serving load.

“Moreover, implementing fast-start pricing as directed … could exacerbate the pricing and dispatch misalignment issue because the lost opportunity cost payments … may be calculated based on inaccurate prices and, therefore, may not correctly compensate opportunity costs.”

FERC said implementing fast-start pricing now could also render lost opportunity cost payments ineffective “because they may not provide correct incentives to follow dispatch.”

PJM’s stakeholder process to fix the issue remains ongoing, with plans to conclude the effort by May.