Page 1174 – RTO Insider

May 9, 2018December 13, 2023

Oncor Financing Tamps Down Sempra Earnings

By Jason Fordney

Financing costs related to the acquisition of Texas utility Oncor helped pushed Sempra Energy’s earnings down by $94 million in the first quarter compared with the same period last year.

The parent company of San Diego Gas & Electric (SDG&E) reported net income of $347 million ($1.33/share), compared with $441 million ($1.75/share) in the first quarter of last year. Sempra closed on the Oncor transaction on March 9, the day after the Texas Public Utilities Commission (PUC) approved the $9.45 billion all-cash deal. (See Texa s PUC OKs Sempra-Oncor Deal, LP&L Transfer.) Sempra said it expects $320-$360 million in earnings from Oncor this year. Sempra funded the transaction with $3 billion in equity and $6.6 billion in debt.

Sempra, which also owns Southern California Gas, earned $2.96 billion in revenues for the quarter, compared with $3.03 billion a year earlier.

SDG&E reported earnings of $170 million in the quarter, compared with $155 million in the same quarter last year, primarily because of changes in consumption patterns that affected electric distribution revenues this year and a lower tax rate, partially offset by a higher interest expense.

Like other utility interests in California, Sempra is focused on revising California’s liability laws to reduce the risk and financial impact from wildfires, which have led to lawsuits and other financial woes as state investigators explore evidence that power lines caused the devastating and costly disasters.

Sempra CEO Jeff Martin, who replaced retiring chief Debra Reed on May 1, noted there are several pieces of legislation moving through committees in the California legislature. (See Calif. L egislation Shields Utilities from Wildfire Costs.)

“While the current text of the bills doesn’t directly address inverse condemnation, we and other stakeholders are also looking to separately address this issue in Sacramento,” Martin said.

Last November, the California Public Utilities Commission (CPUC) rejected SDG&E’s request to recover from ratepayers $379 million in costs related to 2007 wildfires. The ruling ignited a “three-pronged” — legislative, regulatory and legal — effort from the state’s investor-owned utilities to change wildfire liability laws. The CPUC found that SDG&E had not properly maintained its system. (See Besieged CPUC Denies SDG&E Wildfi r e Recovery.)

California’s investor-owned utilities say climate change plays a large role in the increasing number and severity of wildfires, and they cannot be held solely responsible for the billions of dollars in related costs for the disasters.

May 9, 2018

Report: Customer Needs Should Lead Resilience Effort

By Tom Kleckner

With the deadline for filings in FERC’s resilience docket looming, two aides to former FERC Chairman Pat Wood III last week sought to reset the definition — saying resilience is about transmission and distribution, not generation.

In a report funded by the Natural Resources Defense Council and the Environmental Defense Fund, Alison Silverstein and Rob Gramlich say resilience should be measured from the customers’ perspective: the number of outages (frequency), customers affected per outage (scale) and length of time before restoration (duration).

“Customers pay the ultimate price for power outages, whether through their electric bills or their own personal losses and expenditures,” says the study, whose third author is Michael Goggin, who worked with Gramlich at the American Wind Energy Association and has since joined Gramlich’s consulting firm.

DER FERC Resilience Walkemeyer-North Liberal transmission project — Silverstein | © *RTO Insider*

Silverstein, the former senior energy policy advisor to Wood, made headlines last year when, after helping coauthor the Department of Energy’s grid study, she denounced DOE Secretary Rick Perry for using it as a pretext for price supports for struggling coal and nuclear plants. (See Author of DOE Grid Study Disputes Recommendations.)

The DOE NOPR sought “resilience” payments to power plant with 90 days of fuel on site.

In rejecting the NOPR in January and initiating the resilience docket, FERC offered its own definition of the term: “The ability [of the grid] to withstand and reduce the magnitude and/or duration of disruptive events, which includes the capability to anticipate, absorb, adapt to and/or rapidly recover from such an event.”

RTOs made filings in the docket in March. Comments on the RTO filings are due May 9 (AD18-7). (See RTO Resilience Filings Seek Time, More Gas Coordination.)

The Silverstein-Gramlich-Goggin report was filed in the docket Tuesday. [Editor’s Note: RTO Insider will have coverage of the filings later this week.]

“I’m a customer, you’re a customer. We operate the grid for the customer, not just for our jollies,” said Silverstein, in an interview. “It seemed to me that if the point of preventing outages is protecting the customer, as NERC and others assert, we should look at the most effective ways of measuring resilience.”

The report notes the vast majority of outage events occur at the distribution and transmission levels because of weather events — which has only led customers to expect more outages.

The authors cite a Rhodium Group study that found less than 0.1% of customer-outage minutes in 2012-16 were caused by generation shortfalls or fuel supply issues. The study found most outages can be attributed to routine causes such as local storms, vegetation, squirrels and equipment problems, with high-impact, low-frequency events such as hurricanes and winter storms causing about half of customer outage-minutes.

“We cannot prevent and mitigate all the hazards and threats that cause outages, and we can mitigate some but not all of their consequences,” the authors write. “So which risks should we take, what level of resilience and mitigation cost are we willing to bear and how should we choose among resilience measures?”

The paper doesn’t answer the risk question, but it does offer a path for “assessing and selecting resilience regulatory policy options.” The report suggests regulators and stakeholders ask how each remedy “might reduce the frequency, magnitude and duration of customer outages relative to the entire scope of customer outages, not just those resulting from generation- or transmission-level causes.”

In attacking the problem, Silverstein said she borrowed from the Rocky Mountain Institute’s co-founder and chief scientist, Amory Lovins, who has said you can solve the energy problem by enlarging it. By carving problems into bite-sized chunks, Lovins has said, “you don’t have a big enough design space to have enough options, degrees of freedom and synergies.”

“There’s a big difference between generation resilience and the resilience of the power system and resilience from customers’ perspective,” Silverstein said. “When you look at resilience from the customer’s perspective, there’s a whole lot of ways to solve the problem quickly. If I spend a fortune on reducing generation failures, that’s a whole lot of money that could have been spent on tree trimming or strategic spare equipment. Tree trimming and situational awareness are not addressed by a generation resilience proposal.”

Because most outages occur at the distribution level, Silverstein, Gramlich and Goggin write, “it logically follows that measures that strengthen distribution and hasten recovery would be highly cost-effective.”

One example of this would be mobile substations, which proved invaluable during Hurricane Harvey’s restoration effort. Other examples include hardening distribution poles, physical security, outage-management systems, mutual assistance, and emergency planning and drills.

Silverstein said this will become even more important as severe weather events continue to increase in the years ahead. According to the report, the United States weathered 16 “disaster events” last year, each incurring at least $1 billion in damages. Most of the events damaged some electric system infrastructure and caused service disruptions, totaling more than $350 billion in damages.

“We really need to take that threat seriously and think about how to design power system architecture and assets for the long-term threat,” she said. “A lot of the designs today were developed in the early 1900s. The weather is going to be a lot more severe and meaner 10, 20 and 30 years in the future. We designed the grid for Ozzie and Harriet weather. What’s coming at us is Mad Max.”

May 9, 2018

Don’t Rush on Resilience, Commenters Urge

Warn Against PJM Overreach, Abandoning Stakeholder Process

By RTO Insider Staff

FERC should let RTO stakeholder processes work and not issue broad and costly new mandates on grid resilience, commenters told the commission in its proceeding to examine the resilience of the bulk power system in the nation’s RTOs (AD18-7).

RTO Insider’s review of more than 40 of the dozens of comments filed ahead of the May 9 deadline indicated widespread support for RTOs’ requests in their initial filings in March for time to discuss the issues with stakeholders, more coordination with natural gas operators and more information on cyber threats. (See RTO Resilience Filings Seek Time, More Gas Coordination.)

But many commenters criticized PJM’s call for setting firm deadlines for rule changes, saying the RTO’s proposals would increase costs without necessarily improving resilience.

In a joint filing, CAISO, MISO, NYISO, SPP and ISO-NE asked FERC not to impose PJM’s proposals in their regions.

“The record in this proceeding does not support any universal resilience standard or tariff changes requirements to be applied to all RTOs/ISOs. To the contrary, the record demonstrates that RTOs/ISOs have different resilience issues and priorities, and requiring all RTOs/ISOs to follow PJM’s proposed schedule on the issues pertinent to PJM will undermine each RTO/ISO’s efforts to address the specific challenges within its region,” they said. “Thus, the commission should reject PJM’s requests and allow individual RTOs/ISOs to pursue the resilience-related issues and initiatives they have identified in their region through collaborative efforts with their stakeholders and pursuant to the timeframes they have established.”

Others, including the Advanced Energy Management Alliance, agreed that RTOs should continue their existing efforts to address their unique challenges. “PJM’s explanation of the need for changes to certain energy and ancillary market rules is helpful to inform the commission as to areas PJM is working on, but PJM cannot ask FERC to require rule changes to be filed in pre-emption of the stakeholder process or development of an evidentiary record that change is necessary.”

After rejecting the Department of Energy’s call for price supports for coal and nuclear generators in January, the commission asked its six jurisdictional RTOs and ISOs to respond to two dozen questions on resilience. This week’s deadline was for responses to the RTOs’ comments.

The comments touched on topics including FERC’s jurisdiction, fuel security, cyber threats and climate change, as well as individual regional issues.

Jurisdictional Concerns

Several commenters raised jurisdictional issues, noting that states, not FERC, have authority over distribution systems where most outages occur. Arizona Public Service said NERC’s reliability standards already address resilience.

“Before taking any additional steps to address resilience, the commission [should] consider the … comprehensive federal, state and industry efforts [that] address all levels of the electric grid and significantly contribute to ensuring” resilience, APS said. The utility criticized proposals it said “are clearly focused upon expanding the role of ISOs and RTOs and are, without understanding efforts at the state level and among utilities commercially, premature.”

The Pennsylvania Public Utility Commission as k e d FERC to “clearly articulate” its jurisdiction regarding resilience, saying it disagrees with PJM’s assertion that resilience is “‘within the commission’s existing authority with respect to the establishment of just and reasonable rates under the Federal Power Act.’ Therefore, clear and precise justification of FERC’s authority on this matter will be beneficial prior to any initial steps in regulating resilience,” the PUC said.

Entergy also disagreed with PJM’s “overly broad” interpretation of the commission’s jurisdiction.

The Large Public Power Council (LPPC) agreed with commission’s proposed definition of resilience but urged that “to the extent further rules or standards are considered, FERC must be mindful of the statutory limits on its authority,” saying the Federal Power Act does not provide the agency a general grant of authority “to take action on reliability or resilience outside its specific statutory role in the approval and enforcement of standards.”

The LPPC also contended there is “no basis” for applying any rule governing resilience to non-RTO areas, as had been recommended by MISO and PJM. “This is not an issue within FERC’s domain in non-RTO regions, where states and localities maintain authority over generation investment decisions and cost recovery,” the group said.

Cyber Threats

PJM’s Transmission Owners Agreement-Administrative Committee (TOA-AC) said their members need more information from the government on potential cyber threats. “The threat data that resides at, for example, the Department of Energy, Department of Homeland Security, National Security Council and Department of Defense is vital for the RTO/ISOs to have access to for developing and implementing effective protection mechanisms,” they said.

“Therefore, it is essential that the commission develop a process by which PJM may receive verification concerning the reasonableness of vulnerability and threat assessments based on internal government data that has not been made available to RTOs on national security grounds.”

Climate Change’s Role

The Center for Climate and Energy Solutions said that FERC’s scope of grid resilience lacks an acknowledgment of climate change and how it could hinder resilience.

The environmental nonprofit said that although it would prefer FERC order “an economy-wide pricing mechanism” to absorb the economic impacts and even prevent some physical impacts of climate change, it said the commission should at least ensure that wholesale power markets are “internalizing the costs of carbon emissions” through carbon pricing.

The center added that increasing regularity of droughts threatens cooling systems for generating stations and rising temperatures will impede the capacity of bulk transmission lines to transport power. The nonprofit called on FERC to convene a technical conference to explore best practices for an industry coping with global warming.

Fuel Supplies

Numerous commenters cited the certainty of fuel supplies as an essential element of resilience.

NERC said FERC should consider encouraging firm transportation, multiple pipeline connections and dual-fuel capability for gas generators. “Further, the commission could consider requiring that resource adequacy assessments account for potential reliability ramifications associated with the ‘just-in-time’ natural gas fuel delivery model.”

“Fuel security risk is the most important factor to include in the commission’s definition of resilience and in its evaluation of grid resilience generally,” the American Coalition for Clean Coal Electricity said. The American Coal Council said coal generation retirements are a threat because intermittent resources can’t always be counted on.

Basin Electric Power Cooperative said its fossil generating units continue to be affected by markets “that fail to adequately compensate resources” for providing “essential electric service” in the wholesale markets.

The North Dakota co-op called for “equity across all fuel types,” saying the RTOs’ comments did not address the “preferential treatment” wind generation receives. It said a new ramp product, “if structured appropriately,” could reflect the value of stand-by products and provide “sufficient mitigation for assets that must stay online and incur losses” to backfill wind.

Americans for a Clean Energy Grid, a coalition supporting a “fully electrified” society, noted that this winter’s “bomb cyclone” forced Northeast grid operators to rely on more expensive generation such as coal, oil and dual-fuel units, even while wind output — stranded by transmission constraints — was higher than normal during the weather event. “Thus, while wind power can be more reliable than other resources during extreme winter weather, it is limited by interregional transmission constraints,” the group said.

PJM Comments Under Scrutiny

PJM’s March filing was the subject of numerous commenters, including David Patton, whose company Potomac Economics provides market monitoring services to MISO, ISO-NE, NYISO and ERCOT. Patton said adopting PJM’s proposal to allow inflexible generators to set clearing prices would have boosted MISO’s system marginal prices by 30%, based on analysis of the 12 months ending in October 2017. (See Critics Slam PJM’s NOPR Alternative as ‘Windfall’.)

“This plan is a fundamental departure from the efficient locational marginal pricing framework that has been the foundation of all successful wholesale markets in the U.S.,” Patton said. “It would, for the first time, introduce fixed costs into real-time pricing that are clearly not marginal in the real-time dispatch horizon. In effect, PJM would be requiring that the average costs of all resources needed to service load be reflected in every five-minute interval.”

The Pennsylvania PUC said it supported some of PJM’s proposals but feared that some “offered in the name of resilience may shortchange or even bypass normal PJM stakeholder deliberative processes” and warned against giving RTOs “a license to ‘gold-plate’ the generation, transmission and cyber assets of its members to achieve standards of resiliency that are disproportionate to a particular vulnerability or threat assessment.”

The regulators said they were concerned over the potential scope and costs of PJM’s proposals. “Some of PJM’s recommendations, especially in the market design arena, appear to utilize the grid resilience docket as another forum to advocate for specific market modifications, such as energy price formation, that are not immediately germane to the resilience discussion,” the PUC said.

It agreed with PJM that FERC may need to “revisit” NERC reliability standards. “However, revision of NERC standards is a complex, time-consuming process that should be allowed to proceed on its own timeline without an accelerated impetus from this docket.”

The PJM Power Providers Group (P3), on the other hand, praised the RTO’s “thoughtful recommendations” for addressing “antiquated energy price formation structures.”

“However, the stakeholder deliberations regarding this issue have been unproductive to date. Commission direction may be required for energy price formation goals to come to fruition as a means to support the commission’s resilience aims,” it said. P3 expressed concern over PJM’s proposal to permit non-market operations during emergencies, saying the commission should require the RTO to submit Tariff revisions to allow the change.

PJM also received support from American Electric Power, Dayton Power and Light and East Kentucky Power Cooperative, which made a joint filing as the PJM Utilities Coalition.

The coalition said it agrees with PJM’s recommendation that all RTOs be required to submit proposed Tariff changes to implement resilience planning criteria and develop processes for the identification of vulnerabilities.

“No meaningful steps towards a resilient system can begin without appropriate direction given by the commission that explicitly grants power to the RTO to establish resilience planning criteria and other aspects of the process,” it said. It also questioned whether the stakeholder process could address the issues. “If PJM reverts to a stakeholder process to determine resilience criteria, the process may get mired in political debates and cost allocation, and not focus on the necessary task of determining objective resilience criteria. For this reason, clear direction from FERC to guide that process is requested.”

PJM also filed reply comments, saying it wanted to provide additional information on its fuel security initiative announced April 30, clarify its proposals regarding gas-electric coordination and “provide context for its approach to this docket relative to the approach taken by certain other RTOs and ISOs.” (See PJM Seeks to Have Market Value Fuel Security.)

The Organization of PJM States Inc. (OPSI) said PJM’s filing did “not address the prudency and affordability of measures that may be implemented as a result of” the RTO’s recommendations, which it said indicate “extensions of its current mandate.”

“While not the stated intent, a future PJM could be positioned to drive transmission planning and craft new market structures in its mandate to address perceived low-probability, high-impact threats,” OPSI said. “The prospect of this expanded authority, with planning and decision-making impacting billions of dollars in investments with cost recovery from end users, may require a re-examination of PJM’s scope, governance and oversight.”

Industrial energy users, consumer advocates for Delaware, New Jersey and D.C., and American Municipal Power, filing jointly as PJM Consumer Representatives, said the inconsistencies between the positions of PJM and those of other RTOs indicate the need for regional flexibility.

“Unlike the comments of the other RTOs/ISOs, PJM’s comments embark on an aggressively activist course, advocating positions that could result in substantial changes to PJM energy and capacity market rules, in addition to whatever changes may be necessary in transmission planning and system operations rules,” they said.

They called for a cost-benefit analysis or “prudence assessment” of any new resilience rules and said neither the 2014 polar vortex nor the 2017-2018 cold snap “justify subsidizing uneconomic coal and nuclear units … in the name of resilience.”

ISO-NE

ISO-NE’s response to FERC’s identified fuel security as its resilience risk. It said potential responses include additional gas pipeline or LNG capacity, relaxing rules on dual-fuel resources and additional investments in renewables and transmission.

The New England Power Pool Participants Committee stressed that resilience solutions be worked out in the stakeholder process, calling it “a prerequisite to yield the solutions that work best for New England.”

The New England States Committee on Electricity shared ISO-NE’s perspective that fuel security presents the primary challenge to the resilience of the region’s power system. NESCOE recommended additional analysis of potential risks and cautioned “against prescriptive actions or further processes” that could impede regional or state efforts to mitigate fuel security challenges.

The New England Power Generators Association said ISO-NE’s Operational Fuel Security Analysis (OFSA) “neither captures market participant behavior in response to price signals nor the probability of any particular outcome … and therefore should not be the basis for the market solutions to be developed and later filed for acceptance with the commission.” (See Report: Fuel Security Key Risk for New England Grid.)

Eversource Energy said ISO-NE’s fuel security study “may understate the magnitude and scope of the challenges.”

“This could lead one to falsely conclude that only minor changes are required, and that commission action may be unneeded at this time. To the contrary, time is not on New England’s side," the company said.

The company urged the commission to convene a New England-specific technical conference to determine state and federal actions to improve the region’s infrastructure, citing additional gas pipeline capacity from the Marcellus shale deposit and electric transmission to carry Canadian hydropower and on- and offshore wind.

The attorneys general of Massachusetts, Rhode Island and Vermont also cautioned against overreliance on the OFSA, which they said “relies on underlying assumptions that do not present a realistic or complete view of either the present or the future bulk power system.”

“The OFSA presents a deterministic (as opposed to probabilistic) analysis that provides no context about whether modelled events are likely to occur,” they said.

They also said the study’s approach to resilience is overly narrow, failing to consider “cyber and physical adversarial threats, technological accidents, and extreme heat and other weather events.”

The region’s local gas distribution companies recommended FERC “consider expedited review of and decisions on new natural gas pipeline certificate applications in critical fuel security regions.”

NYISO

NYISO told FERC in March that it does not face “imminent resilience concerns that require immediate action.”

The New York Public Service Commission said it agreed that ISO and stakeholder efforts to address bulk system resilience “are comprehensive and continuous,” asking for no other FERC measures beyond its “continued attention.” The PSC also agreed with the ISO’s suggestion for the commission to host a technical conference on bulk system resilience.

The Independent Power Producers of New York also supported the ISO’s approach and said FERC should not force it to abide by PJM’s suggested deadlines. “Efforts to ensure resilience should not be rushed to meet some arbitrarily short time frame unless they are justified by the evaluation of the ISO/RTO,” the group said.

The New York Transmission Owners also called on the commission to respect regional differences. “Any requirement to change course could impede resilience efforts already underway in the stakeholder process,” they said.

MISO

The MISO Transmission Owners emphasized that RTOs have only part of the answer to resilience, noting the role of distribution systems.

“MISO and its utility members have developed an integrated electric system that is currently sufficiently resilient, and MISO has identified no imminent resilience crises requiring commission action,” they said. “Notwithstanding MISO’s and its members’ regional efforts, enhancements to interregional coordination will promote greater resilience. Thus, while seams issues are broader than the concept of resilience, MISO is correct that the commission should not ignore the benefits of greater, more effective and efficient interregional cooperation in this proceeding.”

Entergy said it saw no need for a federal role in determining the proper long-term resource mix — “at least in MISO.”

The company called for resource adequacy to “continue to be a shared responsibility in MISO,” with state and local regulators determining the fuel mix.

“In this way, state and local regulators ensure diversity of fuel resources consistent with each area’s needs and those regulated utilities’ customers bear the cost burden and the reliability and resiliency benefits of those local regulators’ decisions,” Entergy said. “Direct federal action to regulate the long-term resource mix also could jeopardize utilities’ continued participation in MISO.”

In a joint filing, the Coalition of MISO Transmission Customers and Illinois Industrial Energy Consumers said that resilience is already central to the RTO’s reliability assessments. “The commission should not carve out resilience and treat it as a discrete characteristic of wholesale electricity markets,” they said, adding that any resilience requirements should be subject to cost-benefit analyses.

SPP

SPP's Market Monitoring Unit emphasized the importance of creating standards and metrics to quantify and measure resilience.

“We recommend that in addition to defining resiliency, the commission and the parties should also engage in discussions to measure resiliency in order to assess whether an area has or has not attained resiliency. This measurement may also contribute in creating new market mechanisms to promote resiliency,” the Monitor said.

It pointed to SPP’s 30 to 36% capacity margins over peak needs but said that those high levels do not necessarily equate to resilience.

The MMU also said the resilience discussion should not be used “as a venue to promote certain price formation proposals.”

CAISO

The California Public Utilities Commission said the state “has made substantial efforts to ensure grid reliability and resiliency by ensuring redundancy and coordination in its energy planning efforts,” citing the deployment of distributed energy resources and smart inverters.

It also noted the state “continues to aggressively plan for a changing climate to ensure Californians have safe, affordable and reliable access to electricity.”

Nevada Hydro, which develops pump storage projects, said CAISO’s transmission planning process has fallen short in properly valuing hydropower. CAISO’s “transmission economic assessment method (TEAM) has not fully applied the method to storage projects and has not quantified the grid reliability and resiliency benefits of the projects it has examined,” the company said. It said FERC should direct RTOs to include pumped storage hydro in transmission studies and resource adequacy planning.

Southern California Edison said FERC should consider regional differences and costs. It said it shares CAISO’s view that FERC’s proposed definition of resilience is lacking.

It said the use of the term “‘disruptive events” is indistinguishable from “‘contingencies,’ which, per NERC reliability standards, refers to unexpected failures or outages of a [Bulk Electric System] component.”

Contributing to this article were Robert Mullin, Jason Fordney, Amanda Durish Cook, Tom Kleckner, Michael Kuser and Rich Heidorn Jr.

May 8, 2018

Cost Containment Proposal Survives; Headed to MRC

By Rory D. Sweeney

VALLEY FORGE, Pa. — In light of the amount of debate that proposed cost-containment provisions provoked at last week’s Planning Committee meeting, it might come as a surprise that both sides seemed pleased with the outcome of the session.

Proponents of LS Power’s proposal to require consideration of cost-containment provisions in PJM’s analysis of transmission construction bids are relieved that the package remains largely intact and on schedule to return for a vote at this month’s Markets and Reliability Committee meeting. Opponents were happy the measure got the standing committee scrutiny it never received the first time around.

The debate has been building to a confrontation since LS Power surprised some stakeholders by presenting the plan with little forewarning at January’s MRC as an alternative motion to Manual 14F changes developed by PJM. The RTO took its proposal, which had been debated at special sessions of the PC, to the MRC, which rejected the plan and deferred a vote on the LS Power alternative, remanding it for more discussion at the PC in the hope of finding consensus. (See “Transmission Flashpoint,” PJM MRC/MC Briefs: Jan. 25, 2018.)

In follow-up special sessions, LS Power has removed operations and maintenance costs from the list of categories in which developers can offer cost-containment provisions, but the company has resisted most other revisions promoted by transmission owners.

At last week’s PC, PJM’s Sue Glatz presented two proposals the RTO is developing. The first would require staff to consider commitments on construction costs and evaluate the risk of costs exceeding the estimate based upon specified project risk factors identified in templates that PJM and stakeholders have been developing over the past two months. PJM has yet to fully flesh out how the consideration will be implemented and what weight such commitments will receive in project evaluations.

PJM’s alternative is continuing the status quo, in which the RTO evaluates cost-containment measures included in transmission development proposals as it sees fit.

Greg Poulos, the executive director of the Consumer Advocates of the PJM States, reiterated his support for the LS Power proposal, which would require the RTO to consider several other types of cost commitments and provides evaluation guidelines.

“As you know, consumer advocates have been clearly voicing their opinion that they would like to see more than the construction costs included” in the analysis, Poulos said. “I do think this is a significant step and [PJM’s] efforts to compromise on this will be greatly appreciated by the advocate offices.”

Cost Containment Proposal PJM MRC — Stern | © *RTO Insider*

Tension grew when Public Service Electric and Gas’ Alex Stern moved for a vote on PJM’s proposals.

“Alex, you’re a good man,” American Municipal Power’s Steve Lieberman responded before criticizing Stern’s call for a vote, noting that Stern had objected when LS Power’s Sharon Segner sought to bring her proposal unannounced for the January MRC vote. [Editor’s Note: While the proposal was not listed on the meeting’s agenda, it was properly posted on the committee’s web page before the meeting.]

Lieberman had teed up his critique by receiving clarification at the outset of the meeting that any items that weren’t on the agenda for endorsement weren’t prepared for a vote.

“What I heard from Sue [Glatz] is there are a number of things here that PJM is thinking about,” he said. “It’s not in a situation where the information being presented is finalized.”

NextEra Energy’s Steve Gibelli agreed.

“This to me doesn’t feel right. It feels like we’re trying to force a decision through. I’m uncomfortable voting on something without seeing the Tariff changes. I’m not sure how we can vote a motion without seeing those details here,” he said.

Stern defended himself, saying PJM’s proposals have been part of discussions for two months while the LS Power proposal was “completely out of the blue.” He argued that he would prefer to have more time to discuss the proposals “on an even footing” and follow the standard committee protocol of readings at no less than two meetings, but he recognized there are no other PC meetings before the LS proposal is scheduled for a vote at the MRC. Manual 34 rules allow for proposals to be brought straight to the MRC without input from lower committees, he acknowledged, while contending that “all stakeholders believe that such an approach should be the exception and not the norm.”

“Trust me when I say my motives were pure. I was trying to restore some balance to the stakeholder process. I was trying to allow the standing committee to do what it’s supposed to do,” he said.

John Horstmann of Dayton Power and Light attempted to be a peacemaker by proposing the committee take an advisory vote recommending that the MRC defer a vote on Segner’s proposal until August and allow special sessions of the PC on the issue to extend past their intended deadline of May 11 if necessary. PJM would prioritize additional meetings if necessary so that the group could recommend a package for the PC to endorse by its July meeting.

“I didn’t think in January consensus was possible. I think it’s possible, but not on the [existing] deadlines,” Horstmann said in explaining the motivation for his proposal. Stern seconded the motion.

The advisory recommendation received a favorable vote of 78%, with 155 in favor and 43 opposed. There were 13 abstentions. PJM’s Dave Anders confirmed that Segner’s proposal would retain its position as the first package to be voted upon on the topic.

A vote on PJM’s proposal received 107 votes in favor and 60 opposed (64%), while the status quo received 82 in favor and 93 opposed (47%).

The advisory vote may not make much difference if the sides can’t agree. Erik Heinle of the D.C. Office of the People’s Counsel argued that the process remains lopsided.

“Consensus can’t be consumers give everything and TOs hold their ground. I’d like to see what TOs are willing to give up. It can’t just be ‘what else can we take from ratepayers and consumers?’” he said.

Such divisiveness could undermine Horstmann’s intent.

“The goal was ideally one proposal comes forward and not multiple,” he said.

Stern said the TOs believed they had achieved compromise by agreeing to caps on construction costs and suggested that “given a little more time to review options on a level playing field, we could actually get to a single consensus-based resolution.”

May 8, 2018

PJM PC/TEAC Briefs: May 3, 2018

VALLEY FORGE, Pa. — PJM’s Patricio Rocha-Garrido last week briefed the Planning Committee on proposed Manual 20 changes to revise how winter peak weeks are calculated.

Staff say the new methodology is necessary because the current “theoretical” approach used in PJM’s PRISM modeling software to estimate RTO-wide generator outage levels during the winter peak does not reflect historical outage levels. Staff proposed using historical outage data to build the winter peak week’s capacity model.

Stakeholders asked for additional data to confirm that PJM has determined the best option.

Rocha-Garrido added that the revisions are only necessary for winter peaks and that he didn’t see any “far-right tail” indicating problems with PRISM’s analysis of summer conditions.

“We took a look at the summer, and we were comfortable with what we saw. What PRISM is doing reasonably matches historical data,” Rocha-Garrido said.

AMP Disappointed with Cancellation of Ratings Discussion

American Municipal Power’s Ed Tatum said he was “exceptionally disappointed” that staff and PC members decided to skip discussion of NERC Standard FAC-008-3, which governs how transmission owners must document their methodologies for calculating facility ratings.

Committee members decided to table it until next month’s meeting after the discussion on incorporating cost containment in transmission planning ran long. (See related story, Cost Containment Proposal Survives; Headed to MRC.)

TEAC Redesign

PJM’s Aaron Berner walked through revisions to Transmission Expansion Advisory Committee processes to increase transparency and opportunities for stakeholder input.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, voiced his approval of the changes.

PJM Transmission Expansion Advisory Committee winter peak — Stakeholders consider revisions to PJM procedures at last week’s Planning Committee meeting. | © *RTO Insider*

“It’s very noticeable. You’ve done a great job,” he said of PJM’s efforts to provide information sooner.

Tatum suggested adding information to templates that addresses repeatedly asked questions.

“That is definitely one of the things on our mind to try to short-circuit … the need for some of those questions,” Berner said.

Reliability Upgrades Needed for Nuclear Deactivations

Staff said they completed an analysis on the reliability impact of the retirements of FirstEnergy’s Davis-Besse, Perry and Beaver Valley nuclear plants, which the company announced last month. (See FES Seeks Bankruptcy, DOE Emergency Order.)

While the plants can retire as scheduled, transmission upgrades will be necessary, staff said. All projects that will need to be accelerated have been identified. Staff plan to bring details for all upgrades to next month’s TEAC meeting.

All projects will be classified as “immediate need” so they can be in place by the plants’ planned shutdown by the end of 2021, which means they won’t be competitively bid and will be awarded to FE to build.

— Rory D. Sweeney

May 8, 2018

PJM Market Implementation Committee Briefs: May 2, 2018

VALLEY FORGE, Pa. — PJM’s Market Implementation Committee approved manual revisions reducing the number of virtual bidding locations by almost 90%, a change approved by FERC in February to address uplift (ER18-88). (See FERC OKs Slash in Virtual Bidding Nodes for PJM.)

PJM’s Keyur Patel presented the revisions to Manual 11, which include a link to a list of the eligible locations. The changes reduce the number of bidding locations for increment offers (INCs) and decrement bids (DECs) from 11,727 to 1,563, retaining all hub and interface nodes but eliminating some aggregate and generator nodes. The number of up-to-congestion transaction (UTCs) trading points was reduced to 49 from 418.

pjm market implementation committee virtual bidding — Stakeholders consider revisions to PJM procedures at last week’s Market Implementation Committee meeting. | © *RTO Insider*

Stakeholders approved the revisions by acclamation.

Intraday Offers

PJM’s Susan Kenney discussed other proposed revisions to Manual 11 that staff are trying to move quickly through the stakeholder process to expand the window for submitting generation offers.

Procedures implemented by PJM on April 5 to accept intraday offers limited when generators could submit offers with hourly differentiated minimum run time, notification time and minimum downtime to after the day-ahead reliability run and up to 65 minutes before the dispatch time.

Generators asked that PJM also allow submitting that information before day-ahead offers are due and during the afternoon day-ahead rebid window. PJM plans to make this change by eliminating manual language that restricts the submission timing but also clarifies that those values are used only in real-time commitment and dispatch.

“I appreciate PJM’s efforts to reinstate what I think were some unintended consequences,” NRG Energy’s Neal Fitch said. “The alternative right now is I don’t have an ability to tell PJM this information absent calling them up about every unit.”

Adrien Ford with Old Dominion Electric Cooperative agreed the revisions restore efficiency.

Offer Cap Resolution

Responding to stakeholder reservations about returning to previous language on cost-based offer caps, PJM has developed a new plan that members found acceptable. The Manual 11 revisions, which were approved by acclamation with two abstentions, will cap all offers at $1,000/MWh by default. Generators will be able to submit requests for higher cost-based offers, which PJM will screen and allow if validated.

For price-based offers, generators will have a choice: Either select “Switch to Cost” to exclude price schedules from dispatch — the option that PJM “strongly” suggests — or request the ability to submit price-based offers in line with verified cost-based offers. Kenney cautioned that sellers will be responsible to ensure the price-based offer at each segment remains compliant with verified cost-based offer caps.

Kenney acknowledged that the interaction between cost- and price-based offers is “very intertwined” and that staff are still seeking better ways to help verify offer validity.

Catherine Tyler from the Independent Market Monitor unsuccessfully urged stakeholders to oppose the stop-gap revisions and instead push for a holistic solution that automatically validates offers. She said there were instances during January’s “bomb cyclone” cold snap in which offer rules were violated, and that software options should be explored “to ensure there’s automatic compliance.”

“I think everyone would like to see Markets Gateway [PJM’s offer-submission software] take care of this problem,” Tyler said. “We all want to be in the same place at the end, but we do think there’s a different path forward.”

Modeling Node Changes

PJM REV Market Monitor Manual 15 — Chmielewski | © *RTO Insider*

PJM’s Brian Chmielewski presented staff’s proposed manual language for replacing terminated nodes that are part of financial transmission right paths. An overview of the plan was presented at last month’s meeting but lacked proposed language. (See “Nodal Mapping,” PJM Market Implementation Committee Briefs: April 4, 2018.)

Direct Energy’s Marji Philips, who has repeatedly raised concerns with PJM’s previous plans to address this issue, voiced her approval for the updated plan and thanked PJM for working through it.

Long-term FTR Considerations

Chmielewski also presented PJM’s proposal to change the RTO’s long-term FTRs auction process and modeling practices. The IMM’s Howard Haas called the proposal a “vast improvement” but also offered two proposals that he said “may be better.”

Both of the IMM’s plans would follow PJM’s proposal for the first year forward, but years two and three wouldn’t be biddable. Both proposals would remove the “year all” option that allows bidding on a compilation of all three years. Haas suggested this would give bidders “optionality” should system conditions change unexpectedly because “right now, you can be locked into three years.”

Revenue would be allocated to load in either plan, though FTR volume in the second proposal would only be available through counterflow FTRs.

“The model would start with a net-zero transfer capability on a path, so any created capability for years two and three would have to come from counterflow positions,” Haas said. “In that case, the expectation is that there would be no net revenue available to allocate anywhere, but if there was any, you’d allocate it to load.”

Chmielewski said PJM would have to analyze the IMM’s proposals before deciding whether to support them.

Stakeholders pushed back on the IMM’s proposal.

“I encourage people to take a look at Package A [PJM’s proposal] and consider supporting it,” said Exelon’s Sharon Midgley, who called for preserving the priority rights for load and retaining the term of the existing long-term FTR construct. “The value and the importance of having the financial hedging instrument for market participants with physical generation and customers … is probably equally important to maintaining load’s priority rights, which is why we prefer A. … Firms that have generation and customers, their ability to secure hedges is going to severely limited” in the IMM’s plans, she said.

Philips endorsed PJM’s request for quick action on the proposal, urging stakeholders to “not let the perfect get in the way of the good.” She hoped to have the revisions in place for the upcoming FTR auction in June.

“If we go the method of using counterflow to provide liquidity in the auction, we’re actually going to reduce liquidity,” Vitol’s Joe Wadsworth said, noting that use of counterflow to match prevailing flow resembles how the over-the-counter market works. “There’s not much liquidity in the over-the-counter markets.”

He also voiced concerns about losing transparency. “I fear that if we go the route of relying on counterflow in order to get prevailing flow in an auction, we would lose a lot of the transparency that exists today,” he said.

ODEC’s Ford said she favored PJM’s proposal since the IMM also endorsed it, even if it thought it had a better idea, American Municipal Power’s Steve Lieberman said, “any of these packages is preferable to the status quo.”

FTR Forfeitures

Midgley and Mike Borgatti, representing NextEra Energy, proposed sensitivity tests for analyzing PJM’s FTR forfeiture rule to determine if it’s overly restrictive and foreclosing legitimate trading. Exelon won MIC endorsement in March for a problem statement and issue charge to analyze the rule. (See “Exelon-backed Analyses Approved,” PJM Market Implementation Committee Briefs: March 7, 2018.)

Borgatti (left, seated) and Midgley | © *RTO Insider*

Borgatti and Midgley argued that an overly restrictive forfeiture rule might cause competitive suppliers to add a “risk premium” to customer costs and could reduce the value of load’s auction revenue rights (ARRs) if market participants bid less for affected FTRs.

“You can’t efficiently hedge off the cost of load in the energy market, and so the result of that FTR forfeiture is inefficiency that’s going to show up ultimately as an additional cost to consumers as a risk premium,” Borgatti explained.

“We’re trying to become better educated on why we’re seeing the market outcomes [of increased forfeitures] that we’re currently seeing,” Midgley said. “We’re not really sure exactly what is wrong. I know that my firm is being impacted, and we’re seeing significant levels of forfeitures that we’ve never seen before. And it’s preventing us from using INCs and DECs and FTRs to manage legitimate business risks.”

The stakeholders proposed doing sensitivity analyses to test components of the forfeiture procedure. Borgatti compared it to determining school-zone speeds that are both safe for pedestrians and equitable for drivers.

However, IMM Joe Bowring argued that the rule is curbing behavior as it’s intended to. He offered to discuss with individual market participants how the rule was applied to their portfolio and pointed out that forfeitures have declined since the introduction of the new rule as participants have come to understand it better.

“Simply the fact that somebody is doing something doesn’t make it legitimate. The fact that somebody is managing risk doesn’t make it legitimate,” he said.

Bowring also questioned whether the intent of the initiative is to figure out how to bypass the rule.

Midgley and Borgatti denied that motivation. “I don’t think it’s either of our companies’ intent to create a cookbook for how to game the rule,” Borgatti said.

Chmielewski said PJM remains confident in its compliance filing to address FERC’s January 2017 ruling on the issue, though the commission has yet to rule on it (EL14-37, ER17-1433). (See FERC Orders Portfolio Approach for PJM FTR Forfeiture Rule.)

Stakeholders approved manual changes supporting the compliance filing in September. (See “Stakeholders Endorse Manual Revisions,” PJM MRC/MC Briefs: Oct. 2, 2017.)

Despite that, he said PJM is willing to consider alternative perspectives. He presented an analysis that showed changing the rule’s sensitivity for its virtual test from 0.1 MW to 10 MW — or 10% of the line’s day-ahead binding limit if it’s greater — would have cut forfeitures in half and eliminated forfeitures for 12 of 67 market participants penalized. Forfeitures for September 2017 would have been reduced by half, from roughly $2 million to roughly $963,000.

“Really what this trigger is doing is if you’re looking at any binding constraint in the day-ahead market with a 100-MW limit or less, you’re basically saying it has to have a 10-MW or more impact, which may or may not make sense depending on how you look at it,” Chmielewski explained.

Under questioning from stakeholders, he acknowledged that the issue could benefit from further analysis.

“If 10 MW is too high, what’s too low? Is 0.1 too low?” he asked.

He said he couldn’t determine whether there would be any market resettlements if the rule is changed again, but that “it’s possible.”

Balancing Ratio

PJM’s Pat Bruno reviewed the RTO’s proposal to address concerns with calculating the balancing ratio (B) used in the default market seller offer cap (MSOC). The calculation became an issue after PJM was unable to determine a MSOC for 2018 and was forced to implement a stop-gap number. (See “Balancing Ratio Study Changed,” PJM Markets and Reliability Committee Briefs: April 19, 2018.)

PJM’s proposal would calculate average hourly balancing ratios from as many performance assessment intervals (PAIs) as have occurred within the past three years and supplement them with estimated hourly balancing ratios from as many of the remaining peak hours as is necessary to meet the required number of hours of PAIs. Currently, that number is 30. The balancing ratios would be averaged together for a final balancing ratio for the year.

PJM argues the proposal is straightforward, reasonable and able to be completed within the necessary amount of time.

Bowring suggested in his proposal that the balancing ratio can be estimated using a forward-looking model of performance assessment intervals.

“If there are no performance assessment [intervals], there is no B and we don’t need to make one up by inventing various weird ways of pretending there really was one,” Bowring said. “It’s still possible to get to an offer cap. … Let’s not make things up. Let’s actually do a model … based on PJM’s current modeling to determine what we expect to happen.”

Quadrennial Review of VRR Curve

Stakeholders asked PJM to justify its recommended revisions to key parameters for the annual capacity auction following its quadrennial review of the demand curve. PJM reviews the calculation of its demand, or variable resource requirement (VRR), curve every four years and makes recommendations based on an analysis of the curve’s performance. (See PJM to Consider Revisions to Demand Curve Design.)

Among PJM’s more controversial recommendations is that stakeholders ignore the recommendation of the Brattle Group, which performed the performance analysis, and continue to base the VRR curve on the cost of new entry (CONE) calculations for a gas-fired combustion turbine. Brattle recommended changing to the CONE for a combined cycle unit, which it said is cheaper.

“This curve has proven over the past years to be reliable and robust,” Bruno said in defense of the CT-based curve.

“I really expected some evaluation of the shape of the curve … and there wasn’t any of that,” said James Wilson, who consults for several consumer advocates within the RTO’s footprint.

Bruno argued that Brattle reviewed the curve’s shape, as the Tariff requires.

AMP’s Lieberman asked why PJM thought it was appropriate to shift the curve right four years ago based on Brattle’s recommendations — increasing the expense to consumers and profits to generators — but not back when they recommend it four years later. ODEC’s Ford echoed the concerns.

Calpine’s David “Scarp” Scarpignato said he wasn’t “convinced” that the curve reduces excess capacity.

“There are a lot of barriers to exit going on. … I don’t think you can study the curve in isolation like that,” he said.

PJM is not recommending a change in the cap, so it would remain 1.5 times net CONE or 0.7 times gross CONE.

Order 844 Revisions

PJM briefed the MIC on its response to FERC’s April order requiring RTOs to submit monthly reports detailing their uplift payments and operator-initiated commitments (Order 844, RM17-2). PJM has until Sept. 7 to make its compliance filing implementing the changes, which have to go into effect by Jan. 7. (See FERC Orders RTOs to Shine Light on Uplift Data.)

RTOs/ISOs are required to report:

total uplift payments for each transmission zone, separated by day and uplift category;
total uplift payments for each resource monthly; and
megawatts of operator-initiated commitments in or near real time and after the close of the day-ahead market, broken out by transmission zone and the reason for the commitment.

In addition, the order requires PJM to add to its Tariff the transmission constraint penalty factor values used in market software; the circumstances under which the penalty factors can set LMPs; and the procedures for temporarily changing transmission constraint penalty factor values.

A discussion on the topic is planned for a special MIC meeting May 10.

— Rory D. Sweeney

May 8, 2018

PJM Operating Committee Briefs: May 1, 2018

VALLEY FORGE, Pa. — The PJM Operating Committee last week unanimously approved revisions to Manual 14D to tighten the notification rules for transferring the ownership of generation units.

Generation owners and PJM staff hammered out the language over the past month after owners expressed concerns over an earlier proposal. (See “Gen Transfer Vote Postponed,” PJM Operating Committee Briefs: April 3, 2018.)

Stakeholders consider revisions to PJM procedures at last week’s Operating Committee meeting. | © *RTO Insider*

PJM’s Rebecca Stadelmeyer presented the revised proposal, which sets deadlines on how long prior to the sale the buyer and seller must provide the RTO with certain information. Sellers must now simultaneously provide PJM with the application they submit to FERC to change ownership, which starts a clock on several other submissions.

At least five days before closing on the sale, sellers must provide PJM with information including the name and W9 form of the buyer, and a list of its current officers.

GT Power Group’s Dave Pratzon, who organized generation owners’ engagement on the issue, said the result addresses owners’ concerns about commercial realities and the need for flexibility that earlier drafts did not.

Synch Reserve Changes

PJM’s Eric Endress presented proposed Manual 11 revisions that would change how the RTO estimates the synchronized reserve maximums for Tier 1 units. The revisions would set a unit’s maximum at the lesser of the economic maximum or synchronized reserve maximum, though an owner could submit a request for a synchronized reserve maximum less than the economic maximum if a physical limitation exists. The economic maximum can be updated intra-hour as necessary.

PJM is targeting a July 1 implementation of the changes.

Carl Johnson, who represents the PJM Public Power Coalition, was one of several stakeholders who voiced concerns about “moving the earth under our feet” while several other larger issues related to the topic are being debated in other stakeholder forums — notably the Energy Price Formation Senior Task Force and PJM’s initiative to increase grid resilience.

He acknowledged that the proposal “makes sense” but cautioned that “we may be changing this entirely.”

Pratzon asked staff to analyze how the different initiatives overlap because they could “benefit from better coordination.”

PJM’s Chris Pilong acknowledged the concern but urged stakeholders to “make sure we don’t just sit on our hands” and not implement a solution to the issue. The RTO has been analyzing stakeholder concerns about significantly overestimated Tier 1 reserves. (See “Changing Tier 1 Reserve Estimates,” PJM Operating Committee Briefs: March 6, 2018.)

“In the interim, I think we still need to make sure that the reserves are accurate,” Pilong said.

PJM’s Eric Hsia confirmed that a “very limited amount of resources have a spin max greater than [its economic] max.” The RTO agreed to Johnson’s request to provide comparisons of units’ spin max versus economic max for all operating states, not just during synchronized reserve events.

Later in the meeting, PJM’s Becky Davis explained that the RTO uses the synch reserve ramp rates that units specify if they’re greater than specified energy ramp rates. However, generators aren’t required to provide either of those. If neither is specified, PJM uses the default ramp rate.

She noted an analysis of events over the past two years that showed 10% of units with synch reserve ramp rates greater than their energy ramp rates met or exceeded PJM’s Tier 1 estimate. The RTO contacted the other units to either remove the synch reserve ramp rates, match them with the energy ramp rates or justify why it should remain higher by submitting actual unit performance following a synch reserve event.

In response to a question from Pratzon, Davis said that most generators’ reserve rates match their energy rates.

Black Start Fuel Assurance

PJM’s David Schweizer presented proposed fuel-assurance requirements that will be required of black start units starting next year. The requirements would go into effect at the end of the year following the finalization of PJM’s current black start request for proposals and be in place for any incremental solicitations and the next RTO-wide RFP in 2023, he said.

Units would have to show one of the following:

Dual-fuel capability with onsite fuel storage for a 16-hour run-time at its rated black start output;
Onsite fuel storage for a 16-hour run-time at its rated black-start output for units that can store fuel, such as pumped hydro, batteries or oil;
Connection to multiple interstate gas pipelines with primary firm transportation contracts on at least two lines. This wouldn’t include local distribution company lines, which don’t offer firm service; and/or
That run-of-river hydro units can run at their black start rating for 16 hours.

Existing units would be entitled to a five-year transition plan starting in delivery year 2020/21. Units would be allowed to include the capital costs in the incremental black start capital cost component in their costs and would convert to the base formula rate after capital costs have been recovered.

Schweizer suggested that addressing previous concerns about the minimum tank suction level (MTSL) might be “more relevant” now. David Mabry, who represents the PJM Industrial Customer Coalition, agreed and requested a concrete proposal from PJM, but Calpine’s David “Scarp” Scarpignato argued against rehashing the issue. Prompted by the Independent Market Monitor, stakeholders spent several months earlier this year debating revisions to the MTSL calculation but eventually decided there were other issues of potentially greater significance to address. (See “MTSL ‘Not Going Away,’” PJM MRC/MC Briefs: Oct. 2, 2017.)

Pratzon asked if existing black start units that begin but don’t complete upgrades required by the new rules would have to voluntarily cancel the black start contract or if PJM would cancel it. He said his concern is if the difference will affect whether such units are able to recover their costs fully. Staff weren’t prepared to respond definitively; Pratzon asked that it be determined “sooner rather than later” so generators can make decisions about participating in the current RFP. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: April 3, 2018.)

Base Becomes CP

All capacity resources will be subject to Capacity Performance requirements at the beginning of the new delivery year on June 1. PJM’s Susan Kenney provided a preview on what changes regarding unit-specific parameters those resources will experience.

She noted that parameters will be updatable from May 25 through 10:30 a.m. on May 31 and that updates will transfer through to following days. Any parameters that don’t comply with new limits will be rejected by the system, she said.

Kenney also reviewed real-time value reporting procedures.

Fuel Security

PJM’s Dave Souder addressed the RTO’s initiative to analyze fuel security, which was announced April 30. (See PJM Seeks to Have Market Value Fuel Security.)

Souder said staff will analyze the grid under “stressed conditions” that include an extended cold spell, nuclear and coal retirements and the lack of availability of dual-fuel or onsite storage.

The plan has created concern on all sides of the industry.

Joe DeLosa, who represents the Delaware Public Service Commission, voiced “major concerns about the amount of time that’s going to be able to be devoted to this over the next year.”

“End-use customers especially have communicated to PJM their lack of a desire for criteria in the resilience field. I think that’s been pretty unanimous from customers, as well as substantial discussions about competing priorities in the stakeholder process,” he said.

“My mind’s racing,” FirstEnergy’s Jim Benchek said. “You’ve already got CETO/CETL [capacity emergency transfer objective/capacity emergency transfer limit] constraints. … It sounds like you’re planning to put an additional layer of constraints on the system.”

Later, PJM’s Brian Fitzpatrick explained the progress in staff’s analysis of gas-pipeline risks. The analysis is part of PJM’s ongoing effort to prepare for potential interruptions on the pipeline system. (See “Additional Reserves Needed?” PJM MRC/MC Briefs: March 22, 2018.)

Staff have held five meetings with pipelines within its footprint and have three more planned. While PJM had initially identified 63 contingencies that mostly involved potential compressor failures, pipeline companies said those were lower risk and recommended focusing on the ends of lines and laterals connected to main trunk lines.

“Right now, we have about seven [contingencies], so really, really decreased that list quite a bit,” Fitzpatrick said. “And that number will change because we’re still meeting with pipelines.”

Additional analysis will occur over the next six months.

PJM’s Augustine Caven said conditions during January’s “bomb cyclone” cold snap hit triggers to evaluate the need for any contingencies but that none were necessary. Caven also explained PJM’s plan to add detail to its operational parameters for gas units. The expanded parameters will help support automating PJM’s response to contingencies.

PJM is also planning to expand its ability to track units’ limitations on run time, including fuel inventory, emissions limitations, and supplies of demineralized and cooling water. PJM’s Natalie Tacka explained plans to add ways for units to report “hours remaining” for specified time windows and for RTO dispatchers to keep track of those potential restrictions. PJM is seeking generation owner input and asks those interested to let it know by May 11.

Automating Generator Notification

PJM’s Aaron Baizman explained a plan to automate the dispatch of resources onto the system. The current procedure involves calling the generator directly, but PJM plans to have that notification and verification process become electronic.

The transition will start with combustion turbines through a pilot planned to begin at the end of the year and ramp up in 2019. PJM plans to expand it to all units but has not yet set a target date.

Baizman said the plan is similar to programs at ISO-NE, CAISO, SPP and MISO.

CIR Questions

PJM wants to switch from using average to median capacity factors to calculate units’ unforced capacity. The RTO says the median is closer to units’ actual performance but acknowledges it will reduce units’ capacity injection rights (CIRs). (See “CIR Revisions,” PJM Operating Committee Briefs: April 3, 2018.)

The proposal has created concern among some stakeholders, and PJM’s plan to address the unease has only created additional concerns. PJM’s Jerry Bell outlined the current plan, which gives generation owners until Aug. 31, 2024, to notify the RTO that they plan to convert the CIRs that will be lost into incremental deliverability rights (IDRs) that they will use in an interconnection queue project within one year of the notice to PJM. The CIRs will convert to IDRs on Sept. 1, 2024. The plan is like the procedures already in place for reusing CIRs from retiring generators.

Initially, after stakeholders questioned the value of CIRs without a project, Bell suggested they could be sold at the point of interconnection, used to expand the existing project or allocated to a new project in the same area. However, he eventually conceded that “I don’t know what you’d do with them.”

Stakeholders also questioned why PJM would want to force generators to purchase less transmission capacity than they otherwise would. Bell said he’d have to come back later with an answer.

30-Minute Reserves Target Set

PJM has determined that it should secure roughly 3,800 MW of 30-minute reserves in real time, PJM’s Vince Stefanowicz said. The determination comes after analyzing how other RTOs/ISOs handle such longer-term reserves. Stefanowicz noted that ISO-NE, NYISO and the Tennessee Valley Authority all have a similar requirement.

Staff came to the number by considering several factors and making some assumptions. First, they assumed the largest unit would be about 1,500 MW and determined that the appropriate reserve should equal 200% of that. They added the load, wind and solar forecast errors for each season and came up with a value for each season. They averaged to 3,784 MW.

The number would be recalculated annually, and Stefanowicz said it’s often already online much of the time. PJM’s emergency management system calculates 30-minute reserves and found that, over the past four years, the system has been below 5,000 MW of reserves less than 10 hours total.

“We don’t expect this to come into play a lot,” he said. “In reality, the number we’re proposing is not overly aggressive. It’s realistic to what we’ve seen. … We have those reserves on the system normally, through our normal scheduling processes today.”

He noted that resources with a start time of less than 30 minutes could qualify.

PJM’s synchronized reserve requirement is 100% of the largest energy contingency and the primary reserve target is 150%, but the 30-minute “operating” reserve is currently undefined. Stefanowicz said the proposed calculation produces a number like the 30-minute reserve that PJM procures in day-ahead and is comparable to the calculations other RTOs/ISOs make.

“Each area has a different set of numbers, but a very similar methodology for securing their reserves,” he said.

Mabry asked why the target requirement wasn’t dynamic based on the largest unit online at the time. Stefanowicz said they would consider that.

— Rory D. Sweeney

May 8, 2018

PPL Looks to Raise $2B in Equity for 5-6% Annual Growth

PPL last week said it expects to need to raise only about $2 billion from equity sales through 2020, which would enable the company to come in near the top of its projected 5 to 6% compound annual earnings growth per share over that time.

During its first-quarter earnings call, the company also said it expect calls for nationalization of electric utilities in the U.K. to fade and that it isn’t interested in fully or partially divesting its business there.

PPL q1 2018 earnings equity sales — PPL CEO Bill Spence says his company is looking for organic growth. PPL expects to need raise $2 billion in equity sales through 2020. | *PP&L*

PPL earned $452 million ($0.65/share) on revenue of $2.13 billion in the first quarter, as opposed to $403 million ($0.59/share) on revenue of $1.95 billion in the first quarter of last year. Its adjusted earnings were 74 cents/share, beating the Zacks consensus estimate of 66 cents. The difference stemmed from a one-time impact of 9 cents/share from foreign currency hedges.

PPL expects to use its “at the market” offering program for most of its equity sales. CFO Vincent Sorgi said the company has a shelf offering that would allow it to sell up to $3 billion in stock.

The company isn’t looking to perform acquisitions, but rather to pursue organic growth, with midsized transmission projects such as Project Compass being the kind of opportunities it envisions after 2020, according to CEO Bill Spence.

Quotes courtesy of Seeking Alpha.

— Peter Key

May 8, 2018

Exelon to Push for Laws, Rules to Boost Profitability

By Peter Key

Exelon’s plans for its generation subsidiary rely heavily on a push for new legislation and market rule changes that ensure profitability for plants the company is threatening to close, officials said last week.

During a first-quarter earnings call last week, CEO Chris Crane said Exelon plans to push for subsidies for its nuclear plants in Pennsylvania similar to the zero-emission credit (ZEC) programs in Illinois and New York, and the one recently passed by the New Jersey Legislature but not yet signed by Gov. Phil Murphy.

Crane also said he expects Exelon’s generation business to benefit from PJM’s adoption of new price formation rules and FERC’s resilience initiatives.

Although Crane didn’t mention it, Exelon’s Pennsylvania nuclear plants could also earn subsidies from a New Jersey plan that takes into account how plants affect the state’s air quality, regardless of where they’re based. (See Izzo: Nukes Outside NJ Likely Eligible for State ZECs.) Efforts to enact nuclear subsidy programs in Pennsylvania have so far failed to gain much traction.

Crane also said Exelon will work with ISO-NE to develop market reforms allowing it to keep open the four units of its Mystic Generating Station in Charlestown, Mass., that it said it would close in June 2022.

Exelon Everett Marine Terminal Q1 2018 earnings — Exelon CEO Chris Crane says his company will work with ISO-NE on market reforms. Exelon has said it will close the Mystic Generation Station without market reforms.

The company is “going to look to get to the right reforms to make these assets more economic in the future,” Crane said. He noted that ISO-NE “put out a study recently saying that there were five assets in New England needed to ensure reliability into the future, one being the Everett Marine Terminal and the others being the Mystic [units].”

On the same day it said would close Mystic, Exelon announced it was buying the Everett Marine Terminal, an LNG import facility in Everett, Mass., which provides Mystic and other power plants in the area with fuel.

ISO-NE last week asked FERC for permission to waive certain Tariff requirements to allow the RTO to retain Mystic Units 8 and 9 to maintain fuel security, following up on a plan the RTO outlined in an April memo. (See ISO-NE Moves to Keep Exelon’s Mystic Running.)

Crane, along with Joe Dominguez, the company’s vice president of governmental and regulatory affairs and public policy, also addressed a PJM plan announced April 30 to help ensure fuel security. (See PJM Seeks to Have Market Value Fuel Security.)

Dominguez said Exelon would like to see PJM incorporate environmental impacts associated with different fuel mixes, pointing out that during the cold snap last winter, New England had to rely heavily on oil to produce power.

“In 2018, emissions need to be going down,” he said. “And any resolution of this issue that results in emissions going up is going to continue to create incentives for state actions and, indeed, for other federal actions to correct the flaws in those market.”

Crane said that while consumers have benefited from low-cost gas, the industry needs to either build redundancy into the gas delivery system or limit its dependency on gas to make the power production and delivery system more secure.

Exelon had net income of $585 million ($0.60/share) on revenue of $9.69 billion in the first quarter, down from $990 million ($1.06/share) and $8.75 billion in revenues a year earlier. The company’s operating earnings were 96 cents/share, beating the Zacks consensus estimate of 93 cents.

Crane said the company plans to target a 7.4% rate base growth for its utilities and 6 to 8% earnings per share growth through 2021.

Exelon is still on the prowl for acquisitions, if it can find smart ones, according to CFO Joseph Nigro.

“To the extent we can add something that we think will be accretive to the bottom line and fits with the value proposition that we’re trying to bring both to our shareholders and our customers, we’re going to be aggressive with doing that,” Nigro said.

Quotes courtesy of Seeking Alpha.

May 8, 2018

FERC Denies Bayonne NYISO Tariff Waiver Request

By Michael Kuser

FERC last week denied Bayonne Energy Center in New Jersey a waiver of several NYISO Tariff provisions, which the plant said it needed to enter the ISO’s monthly installed capacity (ICAP) auction in June.

NYISO clusters project developers that have achieved similar milestones into a “class year,” and evaluates the cumulative impacts of all of the projects in a given class year through an interconnection facilities study. The ISO recently adopted process changes authorizing it to bifurcate a class year in order to minimize delays for project developers unaffected by additional upgrade studies, allowing those developers an earlier “exit ramp” from the interconnection process.

Bayonne last month asked FERC permission to waive 11 provisions and add two new natural gas-fired units with approximately 120 MW of summer capacity to its existing 512 MW of capacity in time for the June ICAP auction.

The plant said that its 2017 class year study, originally scheduled for completion in December, was now slated to be completed in April. Bayonne would then be potentially subject to an additional 30-day delay while the ISO determined whether it needed to bifurcate the class year, jeopardizing the ability of the new capacity to participate in the June auction. Bayonne contended that it was not seeking waiver of any substantive requirements, but of the timing of certain requirements to allow for timely participation.

The commission’s May 4 order (ER18-1301) found that, in seeking waiver of 11 Tariff provisions, “Bayonne’s waiver request is not limited in scope,” and that granting the request could possibly harm third parties by delaying the ISO’s completion of the class year 2017 process for other projects. The commission also pointed out that “it is unclear whether Bayonne will even need waiver of these provisions given that it is not clear yet that whether class year 2017 will bifurcate.”

“We also note that Bayonne assumes, without support, that both NYISO and its Market Monitoring Unit can expedite their processes if the commission grants the waiver request,” the commission said. “In this way, it is unclear whether granting the waiver request would even provide Bayonne the relief it seeks.”