Page 1065 – RTO Insider

March 15, 2019

NYISO Business Issues Committee Briefs: March 13, 2019

RENSELAER, N.Y. — NYISO’s Business Issues Committee on Wednesday approved revisions to the Installed Capacity (ICAP) Manual regarding external to rest of state deliverability rights (EDRs).

Ryan Patterson, a NYISO capacity market design associate, told the committee that EDRs in general function similarly to unforced capacity deliverability rights (UDRs), warranting updates to the ICAP Manual to include references to EDRs in several sections that mention UDRs.

The revised sections concern maximum allowances for ICAP provided by resources outside the New York Control Area, excluding resources using UDRs and EDRs, with revisions adding an additional table to show the EDR megawatts awarded.

The proposed changes also would provide the processes for requesting, using and offering megawatts associated with EDRs, parallel with those for UDRs, as well as establish the process for requesting EDRs.

One revision fixes a broken website link, which now links to the correct section and has the correct cross reference, which led one stakeholder to ask if all the ISO’s manuals have been checked for link faults since the grid operator updated its website in December.

Mark Seibert, NYISO manager of member relations, said document links continue to be updated as part of the ongoing review associated with the new website.

OKs New Zone J Operating Reserves

The BIC approved establishing operating reserve demand curves that assign a $25/MWh value to the proposed reserve requirements for Zone J (New York City), similar to the approach taken with the implementation of the Southeast New York (SENY) reserve region. (See “New Zone J Operating Reserves,” Imports/Exports Top Talk at NYISO Carbon Pricing Kick-off.)

The Zone J reserve requirement would necessitate procuring 500 MW of 10-minute reserves and 1,000 MW of 30-minute reserves.

A new Zone J (New York City) operating reserve requirement will necessitate procuring 500 MW of 10-minute reserves and 1,000 MW of 30-minute reserves. | *NYISO*

Ashley Ferrer, NYISO energy market design specialist, told the BIC that the ISO is not proposing to revise the Zone J requirement during thunderstorm alert (TSA) events in order to ensure timely implementation of the curves for June.

The ISO has recognized that activating special case resources in its emergency demand response program to protect Zone J reserves represents a $500/MWh action, which implies that a $500/MWh demand curve price for Zone J reserve products could, in the longer term, be an appropriate value to consider.

However, use of a such a steep demand curve price, absent further evaluating the appropriate reserve requirements during TSA events, could result in unnecessarily high pricing outcomes during such events, Ferrer said.

TSAs are called when actual or anticipated severe weather conditions lead the ISO to reduce transmission limits into SENY.

Assuming Management Committee approval in March, the ISO would submit the proposal to the Board of Directors in April and file Tariff revisions with FERC, seeking approval to implement it in June.

Clarifying TCC Credit Calculation

Sheri Prevratil, the ISO’s manager of corporate credit, informed the BIC that there are three existing historic fixed price transmission congestion contracts (HFPTCCs) with start dates that do not match the first day of a capability period. NYISO identified the issue while developing software to use the market clearing price to calculate the credit requirement for fixed-price transmission congestion contracts (TCCs).

The ISO proposes to clarify in the Tariff how to calculate the holding requirement for HFPTCCs with start dates that do not align with the beginning of a capability period by using the proposed enhancements previously approved by stakeholders, Prevratil said. (See “Committee Approves Repricing TCC Credit Requirement,” NYISO Management Committee Briefs: Jan. 30, 2019.)

The Management Committee will consider the proposed incremental clarifying revisions on March 27.

NYISO, PJM Revising JOA for Tie Line Issues

NYISO and PJM are targeting an April stakeholder meeting to discuss revisions to their joint operating agreement, ISO Principal Economist Nicole Bouchez told the BIC in presenting the monthly Broader Regional Markets report.

The ISO and PJM last September filed with FERC a joint request for waiver of the JOA to permit them to add the East Towanda-Hillside tie line as a market-to-market (M2M) flowgate.

NYISO and PJM are working to address issues on the East Towanda-Hillside tie line near the New York-Pennsylvania border, which was recently designated as a market-to-market flowgate. | *NYISO*

The requested waivers enable PJM to temporarily conduct redispatch operations to control flows to the more restrictive rating on the NYISO side of the line without violating its Tariff while the grid operators work to develop a permanent solution.The commission granted the waiver in November after both grid operators jointly responded to one stakeholder protest that it was a “broad, unlimited waiver,” Bouchez said. (See “NYISO, PJM Win JOA Waiver Request,” NYISO Business Issues Committee Briefs: Dec. 12, 2018.)

The ISO filed its first quarterly report with FERC addressing progress made toward developing JOA revisions to address the tie line issue, as required by the commission.

Natural Gas Prices down 122% in Feb.

NYISO locational-based marginal prices averaged $33.51/MWh in February, down by about 48% from January and only slightly from the same month a year ago, Bouchez said in delivering the monthly operations report. Year-to-date monthly energy prices averaged $44.93/MWh, a 38% decrease from a year ago.

Day-ahead and real-time load-weighted LBMPs came in lower compared to January. Average daily sendout was 436 GWh/day in February, compared with 449 GWh/day in January 2019 and 426 GWh/day in February 2018.

Transco Z6 hub natural gas prices averaged $2.75/MMBtu for the month, down 122% from January and 12.4% from a year ago.

Distillate prices were up about 2.4% year over year and gained from the previous month, with Jet Kerosene Gulf Coast averaging $14.21/MMBtu, up from $13.25/MMBtu, while Ultra Low Sulfur No. 2 Diesel NY Harbor rose to $14.02/MMBtu, compared with $13.20/MMBtu.

The ISO’s 11-cents/MWh local reliability share in February was down from 32 cents the previous month, while the statewide share climbed slightly to -55 cents/MWh from -57 cents in January.

— Michael Kuser

March 15, 2019

Judge Sides with PGE over FERC in PPA Dispute

By Hudson Sangree

A U.S. district court judge on Monday sided with PG&E Corp. in declining to withdraw the utility’s jurisdictional dispute with FERC from bankruptcy court.

The ruling was a win for PG&E and a rebuff to FERC, which contended it had “concurrent jurisdiction” with the bankruptcy court over power purchase agreements that the company could seek to modify during its Chapter 11 reorganization.

Judge Haywood Gilliam Jr., of the U.S. District Court for the Northern District of California in San Francisco, denied motions by FERC, NextEra Energy and other PG&E contractors to withdraw the case and send it to a federal trial court. The petitioners argued the case hinged on provisions of the Federal Power Act, which the bankruptcy court could not decide. PG&E contended the case could be adequately dealt with under bankruptcy law and need not involve larger questions of federal law.

In his ruling, Gilliam cited a recommendation by Bankruptcy Judge Dennis Montali, who is overseeing PG&E’s reorganization, that the PPA issue be left for him to decide.

The Geyers geothermal plant in Northern California | *Calpine*

In his view, Montali wrote to Gilliam, “all that needs to be done is consider the plain language of Section 365 of the Bankruptcy Code. There you will find the answer to the question of whether FERC can decree that [the code section] must be construed to permit FERC to second-guess the bankruptcy court and impose its own decision on that court.”

The case — and the adversary proceeding PG&E initiated within the context of its broader bankruptcy proceeding — stemmed from two FERC orders issued in late January just prior to the utility’s bankruptcy filing (EL-1935, EL19-36). In response to petitions from NextEra and Exelon, the commission declared it shared authority with the bankruptcy court over any wholesale PPAs that PG&E might seek to modify. (See FERC Claims Authority Over PG&E Contracts in Bankruptcy.)

On the day it filed for bankruptcy, PG&E confirmed in court papers that it hoped to rescind some costly PPAs. (See PG&E Wants to Undo Contracts, Revamp Biz in Bankr u ptcy.) PG&E said it has 387 PPAs with 350 companies worth about $42 billion. Those PPAs represent 13,668 MW of contracted capacity, it said.

PG&E quickly sought injunctive relief from Montali to prevent generators from seeking FERC relief. Montali must still rule on the injunction, which he told Gilliam he intends to do soon.

Gilliam agreed that resolution of the PPA issue would not necessarily involve the consideration of non-bankruptcy law. Moreover, Gilliam wrote, Montali had already received PG&E’s motion for a preliminary injunction against FERC along with opposing briefs from the commission, NextEra and other generators that had intervened in the case.

The most efficient use of judicial resources would be to let Montali decide the matter, Gilliam wrote.

March 15, 2019

New Mexico Moves Toward Clean Energy, EIM Participation

By Hudson Sangree

New Mexico’s largest utility is still hoping to join the Western Energy Imbalance Market on schedule, despite a setback from state regulators, saying the planned move has taken on added significance after state lawmakers passed a bill requiring investor-owned utilities to get all their electricity from carbon-free sources by 2045.

“We are headed for a very high level of [renewable portfolio standard] similar to California,” Todd Fridley, vice president of New Mexico operations for Public Service Company of New Mexico (PNM), told the EIM’s Regional Issues Forum (RIF) in Albuquerque on March 11. “PNM is on board with this, and we’re moving toward these goals.”

Public Service Company of New Mexico wants to join the Western EIM by 2021. | *CAISO*

Senate Bill 489 would raise New Mexico’s RPS to 50% by 2030 and 80% by 2040, in addition to requiring 100% carbon-free energy by 2045 for IOUs. The measure has passed both houses of the state legislature and is awaiting signature by Gov. Michelle Lujan Grisham, who ran on a clean energy platform last year and championed the bill. If she signs it as expected, New Mexico would become the third state after California and Hawaii to establish a 100% clean energy mandate with a clear timeline.

“The Energy Transition Act is a promise to future generations of New Mexicans,” Grisham said in a news release. “When we were presented the chance to move toward cleaner sources of energy, we took it, boldly charting a course to a carbon-free future, permanently centering our commitment to lower emissions and setting an example for other states. Crucially, this legislation does not leave our neighbors in San Juan County behind, as we will provide millions for trainings and economic development.”

The measure could speed the closure of the coal-fired San Juan Generating Station in northwestern New Mexico. PNM is the largest owner of the plant and has said it intends to close it by 2022, despite protests from workers and local officials.

While planning to leave coal behind, New Mexico has experienced a boom in oil production in the Permian Basin area in its southeast.

At the same time, developers are moving to install thousands of megawatts of wind generation in the hills and plains southeast of Albuquerque. The area experiences some of the strongest and most reliable winds in the U.S. (See Tx Path Uncertain for Massive New Mexico Wind Farm.) Solar is also a growing industry in the Land of Enchantment.

By joining the EIM, PNM is hoping to take advantage of the real-time market’s ability to easily trade electricity produced from wind, solar and other resources across state lines in the West.

New Mexico is moving toward a clean energy future and away from fossil-fuel generation such as the coal-burning San Juan power plant. | *PNM*

New Mexico’s Public Regulation Commission unanimously approved a measure in December that would have smoothed the way for PNM to join the EIM by permitting it to recover about $21 million in costs. But after two new members were sworn in to the five-member commission, the PRC vacated its December order and decided to rehear the case. (See State Regulators to Re-e xamine PNM’s EIM Membership.)

Fridley told the RIF that it will be a close call as to whether PNM can stay on its timeline to join the EIM by spring 2021. It needs PRC approval by April 1 to do so, he said.

A PRC hearing examiner is expected to issue a recommended decision by Monday, and commissioners will likely vote on the issue before the end of March, he said.

Fridley said PNM is unwilling to move forward on joining the EIM without a decision by the PRC because of the costs. On the other hand, not moving ahead by April 1 could bump PNM out of CAISO’s queue for joining the market. Having to wait another year would mean New Mexico would miss out on approximately $17 million in predicted annual benefits, he said.

“If we don’t have a decision, that’s going to jeopardize the schedule, but we believe it will be approved,” Fridley told the RIF.

March 15, 2019

Monitor Says PJM’s Capacity Market not Competitive

By Christen Smith

Unsound rules for calculating default market seller offer caps and other persistent structural flaws made PJM’s capacity market uncompetitive in 2018, the RTO’s Independent Market Monitor said Thursday.

“The offer cap is six times too high,” Monitor Joe Bowring said while presenting the annual State of the Market report. “The math doesn’t work the way PJM has it. The offer cap is way too high, permitting uncompetitive results.”

Bowring’s statements echoed the Monitor’s Monitor Asks FERC to Cut PJM Capacity Offer Cap.) Bowring suggests implementing a new market rule that mitigates those factors or reducing the number of performance assessment hours (PAH) used to calculate the minimum offer price rule (MOPR).

Capacity prices | *Monitoring Analytics*

“The offer cap is too high because of the use of the wrong number of PAH,” he said. “We suggest implementing a sustainable market rule instead of MOPR … most units, even though they are being subsidized, would clear with truly competitive prices.”

The Monitor evaluated the capacity market design as “mixed,” citing several features of the Reliability Pricing Model that threaten competition, including a definition of demand response that permits inferior products to substitute for capacity, issues with replacement capacity, the definition of unit offer parameters, the inclusion of imports that are not substitutes for internal capacity resources and the definition of the default offer cap.

Bowring said DR should be removed from the capacity market entirely and redesigned to facilitate customers’ response to prices. Payments should be immediate, and the offer cap should mirror that for generation, he said.

Gas Outpaces Coal in Energy Market

Gas-fired energy output exceeded coal in PJM’s market last year for the first time, Bowring said. Despite this, LMPs rose 23.4% and the fuel diversity index increased. Still, the Monitor characterized PJM’s energy market as being “competitive” in 2018.

Load spiked 4.3% — the biggest increase since 2012 — on account of frigid temperatures in January and other weather-related events in 2018, according to the report. PJM’s energy sources remain relatively balanced among gas (30.9%), coal (28.6%) and nuclear (34.2%), with renewables accounting for a small, but growing share of less than 3%.

Average load-weighted LMP in PJM | *Monitoring Analytics*

“Energy prices have increased quite significantly,” Bowring said. “Even though gas and coal have crossed lines, coal is still a significant presence in PJM and is still setting the price about 25% of the time.”

The Monitor also suggests PJM prioritize a stakeholder process to clearly define criteria for operator approval of real-time security-constrained economic dispatch cases used to send dispatch signals to resources. The RTO should also implement a rules-based approach to pricing in order to minimize operator discretion, Bowring said.

“It’s at the core of the energy market and the rules aren’t clear how the market is run,” he said.

Energy uplift charges increased 56.5% last year, with combustion turbines and combined cycle gas units receiving $109.3 million and $20.3 million in credits, respectively — more than half the $198.5 million allocated last year. The Monitor wants to eliminate day-ahead operating reserve credits, include regulation offsets in the calculation of balancing operating reserves and calculate the need for balancing credits and lost opportunity cost credits on a daily basis for a $47.4 million reduction in credits overall.

Day-ahead energy market: days with pivotal suppliers | *Monitoring Analytics*

‘Unsurprising’ Nuclear Retirement Signals

Three of PJM’s 18 nuclear facilities face revenue shortfalls through 2021, a natural reaction to competition, Bowring said.

“We have plenty of capacity,” he said. “We don’t need any particular unit to be reliable. If they can’t compete, they can’t compete. The fact that a unit is going to retire is not a surprising thing in a competitive market.”

Unit retirements across PJM since 2011 | *Monitoring Analytics*

The three facilities — Davis-Besse, Perry and Three Mile Island (TMI) — each operate just one reactor, which is the source of their financial strain, the Monitor said. The remaining multi-unit facilities, including the subsidized Quad Cities in Illinois, will remain profitable. Even without zero-emission credits, Quad Cities would cover its costs for the next three years, Bowring noted.

Bowring said ZECs could upset PJM’s competitive markets as Pennsylvania considers subsidizing TMI and its other nuclear plants after Exelon scheduled the plant for early retirement in September. (See PA Lawmakers Unveil $500M Nuke Subsidy Bill.)

Nuclear unit annual forward surplus | *Monitoring Analytics*

“Providing subsidies is a bad idea,” he said. “It’s contagious.”

In addition, 24 coal-fired units with 12,017 MW of output are at risk of retirement as newer, more efficient technologies take over, the report pointed out.

March 15, 2019

MISO Considering Slimmed-down MTEP Report

By Amanda Durish Cook

MISO plans to revamp its annual Transmission Expansion Plan (MTEP) report to emphasize the justifications and analyses behind the list of proposed projects while removing some planning process narratives.

Director of Strategy Jesse Moser said Wednesday that the streamlined MTEP report will focus more sharply on the business cases for transmission projects.

“We think some of these changes will make the report more user-friendly with a few resource efficiencies along the way,” Moser said during a March 13 Planning Advisory Committee meeting.

MISO’s last five MTEP reports have typically stretched to about 200 pages.

“Over time — I think the first MTEP report was MTEP 03 — it’s grown and grown to include everything related to our transmission planning process,” Moser said. He said the report currently includes “a lot of repetitive, boilerplate” descriptions of the planning process that could be relocated to MISO’s website. He added that some compliance-necessary language must remain.

Moser said last year’s report included a late addition of load shape forecast changes, which “wasn’t necessarily tied to transmission projects being approved in that cycle” and ultimately delayed the PAC’s vote to recommend the report.

Instead of detailing the planning process, MISO could create a more exhaustive executive report that explains industry trends and summarizes important stakeholder decisions in the year, he said.

MISO is also proposing to scrap the report’s first draft review before the PAC that historically takes place in early August. The committee would get its first look in September under the proposed changes.

“What we’ve found historically is that it’s pretty early in the process and we’re still wrapping up the report. Sections of the report vary in terms of completeness. We’ll have a more complete product for review,” Moser said.

Moser said one less review would also cut down on stakeholders’ workload.

Consultant Roberto Paliza asked if stakeholders found the current report “tedious or impenetrable,” or if MISO staff are introducing the change independently.

“This is our initiative. We’ve had this in mind for several cycles now,” Moser replied.

But some stakeholders said the existing format provides a good historical — and preserved — record of reasons behind transmission project decisions.

“The problem of including website links is they’re volatile,” Paliza said. He pointed to MISO’s 2017 website redesign where, in some cases, web pages and previously accessible information were lost. “I think it provides a very important memory of what went on in the system of MISO.”

Other stakeholders said they were concerned the new schedule excises an entire month of stakeholder feedback and compresses the time allotted for stakeholder review from four months to three.

But staff said putting an incomplete draft report forward for review creates more confusion than necessary.

“When you get the report, it should be substantially complete,” Director of Planning Jeff Webb said.

“I think it’s probably good for the stakeholders and the board to have a very focused MTEP report,” PAC Chair Cynthia Crane said.

However, Crane asked for a more detailed discussion on what exactly would be removed from the report.

Moser said he would return to the April PAC meeting with more specifics. He also said the move will be discussed before the Board of Directors next week to outline what a more streamlined report might look like.

March 15, 2019

NERC Chief: No ‘Appetite’ for Expanding Authority

By Rich Heidorn Jr.

WASHINGTON — NERC CEO Jim Robb said Thursday he sees no “appetite” among policymakers for expanding the organization’s authority despite rising concerns over the visibility of distributed energy resources.

NERC CEO Jim Robb speaking Thursday at the agency’s biennial Reliability Leadership Summit at the Mayflower Hotel in D.C. | © *RTO Insider*

Robb made the comments to reporters after NERC’s daylong biennial Reliability Leadership Summit, where more than 130 regulators, utility officials, RTO executives and others gathered to compare notes on best practices, industry trends and emerging challenges.

The discussions turned repeatedly to the reliability challenges posed by a changing generation mix and the increasing volume of DERs, which are not under the operational control of regional grid operators.

“In the current model, [for] vertically integrated utilities, it’s pretty clear who’s accountable for generator performance, maintenance, testing … but that gets very fuzzy in the DER world,” said John Stephens of City Utilities of Springfield Missouri. “How do we hold them accountable? How do we know our planning assumptions are valid for more than the next six weeks?”

Talking with reporters after the conference, Robb was asked if he thought federal policymakers would someday look to expand NERC’s authority beyond the bulk power system.

“I don’t think there’s a whole lot of appetite for that,” he responded.

“I think visibility is very important. I think that’s one of the issues that … can be done voluntarily. It doesn’t necessarily have to be done through a standard or regulation — because nobody wants this issue, right? Nobody wants to be the [regulator] sitting on top of a major reliability event.”

Robb said NERC has “maintained a fairly regular dialogue” with the National Association of Utility Regulatory Commissions and individual state regulatory agencies. “So, they’re aware of the work we’re doing that’s applicable to them. That’s one of the areas both sides have agreed we need to do more of as this line continues to blur and more and more of the resource sits on the distribution side of the house, or the sub-BPS.”

Confident on Cybersecurity

Robb also expressed confidence over the grid’s ability to withstand cyberattacks, despite the Worldwide Threat Assessment released by U.S. intelligence agencies in January, which raised warnings about the ability of Russian and Chinese hackers to disrupt electrical service and natural gas pipelines in the U.S. (See Senators Call for Urgency on Energy Cybersecurity.)

“The system provides substantial protections in terms of a major cyber event. … It’s built to withstand the loss of large assets,” Robb said. “So, while I would never say zero [risk], I don’t think this is something that we need to be worried about — something taking down half of the Eastern Interconnection.”

How about blacking out a major city?

“Possibly more vulnerability there, but even then, it would be likely something that could be recovered from fairly quickly,” Robb said.

The NERC chief said he agrees that China and Russia “are persistent threat actors.”

“They are working very, very hard to build capabilities to penetrate the grid. Most of the vulnerabilities are on the enterprise side of the house — IT systems — not the operating systems. And we have very vigorous rules around firewalls and air gaps between enterprise systems and the operating systems. If somebody could even get into a company’s enterprise system, their ability to translate that into something actionable on the control side of the system is substantially mitigated.”

Asked whether fuel security is more of a concern than cybersecurity, Robb paused, then laughed.

“It depends on the day. Both are very, very important. The difference is that [with] cyber, you’re dealing with a persistent threat, whereas fuel security is more of a random event, like any other reliability event. But there are clearly areas of the country that are getting closer and closer to the edge, related to fuel. We’ve heard about New England. We heard about the issues in Southern California. And we’ll see more and more of that as the system becomes more and more reliant on natural gas and it becomes harder and harder to develop the gas infrastructure to support it.”

March 13, 2019

Courts Misread Hughes on Nuke Subsidies, Supreme Court Told

By Rich Heidorn Jr.

Merchant generators’ Hail Mary pass for a U.S. Supreme Court review of Illinois and New York nuclear subsidies has won support from PJM’s Independent Market Monitor and others, who said lower courts have misinterpreted precedent on federal jurisdiction.

The Electric Power Supply Association asked the court in January to review rulings by the 2nd and 7th U.S. Circuit Courts of Appeals that the subsidies did not intrude on EPSA Asks Supreme Court to Review ZEC Rulings.)

Exelon joined Illinois and New York officials in saying the court should leave standing the states’ zero-emission credit programs. EPSA was supported by the Monitor, PJM industrial customers, the American Petroleum Institute and a group of economists.

The Supreme Court hears a small percentage of the cases on which it is petitioned. But the stakes of a ruling could have impacts beyond New York and Illinois. New Jersey and Connecticut have also approved nuclear subsidies and Pennsylvania regulators introduced a subsidy bill on Monday. (See Pa. Lawmakers Unveil $500M Nuke Subsidy Bill.)

‘Artful Description’

EPSA’s supporters said the appellate courts misinterpreted the Supreme Court’s 2016 ruling in Hughes v. Talen, in which the court unanimously rejected Maryland’s contract-for-differences with a natural gas plant.

The court also provided state regulators guidance for crafting their programs in the future, saying it rejected Maryland’s initiative only because it was tied to PJM capacity prices. “So long as a state does not condition payment of funds on capacity clearing the auction, the state’s program would not suffer from the fatal defect that renders Maryland’s program unacceptable,” the court said.

Monitoring Analytics, PJM’s Monitor, said the appellate courts were mistaken in upholding the ZEC programs based on the Hughes ruling.

“Legislators can easily contravene FERC’s authority over wholesale rates by artful description or avoiding description of the mechanism rather than transparent statutory language. An explicit tether like that appearing in Hughes is easily avoidable, as the ZECs programs at issue here illustrate,” the Monitor wrote.

The Monitor said failing to overturn the appellate rulings “may effectively end federal control over the interstate wholesale power markets, contrary to the jurisdictional framework in the Federal Power Act. The record shows that FERC has gone out its way to accommodate the states. How have the states accommodated FERC? If anything, petitioners understate the risk. The public will be ill served if regulation through competition survives in name only.”

Seven economists, including Roy Shanker and Harvard’s William Hogan, agreed.

“The courts of appeals sought to distinguish the ZEC subsidies adopted by Illinois and New York from the contract-for-differences subsidy adopted in Maryland. From an economic point of view, however, those distinctions are without substance,” they wrote. “As with the Maryland program, the ZECs pay favored generators a subsidy based on their wholesale market participation, thereby guaranteeing them a price that is different from the price set in the auction. Although there are differences in the details of the price-setting mechanisms employed by the subsidy programs, those differences are largely irrelevant to their basic design and purpose.”

The economists also said the ZEC programs may not support carbon-free electric generation, as their supporters contend.

“There is no assurance that the generating resources that the nuclear generators will displace are carbon-emitting: on the contrary, the distorted market may discourage entry of clean energy sources and thereby perpetuate carbon emissions,” they said. “It also may discourage conservation, and indeed encourage greater consumption, due to lower wholesale prices, resulting in greater amounts of generation from less ‘clean’ resources.”

A group of industrial consumers disagreed with the lower courts’ likening of ZECs to renewable energy credits. “ZECs are calibrated to backfill the difference between wholesale market revenue and the claimed revenue requirement of particular uneconomic nuclear units,” said the PJM Industrial Customer Coalition, the American Forest & Paper Association, the Illinois Industrial Energy Consumers and the Electricity Consumers Resource Council. “While RECs are traded on an open market among various market participants, ZECs are state-mandated payments from customers in that state to specific qualifying nuclear units.”

The American Petroleum Institute also called for a Supreme Court review of the New York program, calling it “incompatible with federal energy policy governing wholesale markets.”

Exelon, States Respond

Exelon Generation, the largest nuclear operator in the U.S., said the court should leave the circuit court rulings alone, citing what it said are procedural problems with EPSA’s petition.

“FERC, the states and all eight judges to have considered the question agree: There is no pre-emption,” Exelon said. “Petitioners cry that ZEC programs will destroy FERC’s markets, but that is belied by FERC’s own words. FERC and the United States told the court that FERC ‘has the means and the authority to confront’ any ‘effects’ on its markets from ZEC programs, and that ‘the Federal Power Act does not pre-empt’ such state programs.”

Exelon noted that FERC is considering market rule changes to accommodate state programs while insulating wholesale markets. “Judicial intervention now would disrupt FERC’s effort to use the scalpel of regulation, rather than the chainsaw of pre-emption,” it said.

The Illinois Power Agency and Illinois Commerce Commission insisted the 7th Circuit’s ruling upholding the state program was consistent with Hughes and other precedents under the FPA.

“Petitioners’ argument disregards key differences between the two programs that firmly support the 7th Circuit’s conclusion that the ZEC program falls comfortably within the states’ authority over power generation and does not invade FERC’s authority to regulate rates for wholesale sales of electricity,” they said. “Put simply, ZEC payments for generating emission-free electricity do not set the price for any wholesale sale of that electricity.”

The New York Department of Public Service agreed. “Because ZECs are awarded for production without regard to sales, they will not change how eligible plants sell their output,” it said. “They will not induce a generator to sell in a wholesale auction instead of by contract or at retail. Nor will they change the bidding behavior of a generator that opts to sell in a wholesale auction. When a nuclear plant sells its output in a wholesale auction, it does so as a price taker because it cannot readily turn off and on in response to short-term price fluctuations.”

March 13, 2019

PJM to FERC: Hurry Up with Auction Guidance

By Christen Smith

PJM urged FERC on Monday to expedite guidance on the RTO’s upcoming Base Residual Auction as stakeholders prepare for deadlines on two different sets of rules (E L 16-49).

The filing comes days after PJM’s Jeff Bastian walked the Market Implementation Committee through the upcoming schedule in what he called a “parallel path” to the Aug. 14 auction, for delivery year 2022/23. Sellers will have to confirm whether they will be offering resources with “actional subsidies” by March 17 — a deadline stakeholders said was unreasonable. (See Capacity Market Sellers Anxious Over Uncertain PJM Auction Rules.)

FERC last summer granted PJM’s request to delay the auction in response to the commission’s ruling requiring the RTO to revamp its minimum offer price rule (MOPR) to address price suppression from rising state subsidies for renewable and nuclear power (ER18-2 222). PJM filed its proposed MOPR changes Oct. 2 and said a FERC ruling by March 15 would keep the August schedule on track — though Bastian said on March 6 it seemed no direction from the commission was imminent.

Stakeholders pressed PJM to file an additional waiver delaying the auction again, but the RTO preferred to prepare for two different scenarios: moving ahead with existing Tariff provisions in the absence of FERC guidance and also requiring sellers to file based on PJM’s proposed rules.

“To avoid a ‘self-fulfilling prophecy’ of frustrating the ability of PJM to implement the substitute Tariff provisions it served up to the commission in this proceeding, PJM believes that for the moment, it is prudent to continue to require submittals under both the new proposed and existing Tariff provisions,” PJM said in its March 11 informational filing.

The RTO went on to say FERC’s inaction grows more problematic every day.

“A timely comprehensive ruling by the commission is clearly needed as we approach the August BRA and the various preparatory deadlines for submittals by market participants leading up to the August auction,” PJM said in the filing. “However, in the interim and at least for the present upcoming deadlines, PJM believes it prudent to continue, as it has done in other instances, to proceed down a path requiring submittals under both the existing market rules as well as the PJM proposed market rules.”

PJM pointed out that while it has previously conducted auctions in the face of pending Section 205 filings and Section 206 complaints, “it has not conducted an auction when there has already been a commission finding that its existing capacity market rules are unjust and unreasonable with no established just and reasonable replacement rate in place — as is the circumstance PJM finds itself in now.”

March 13, 2019

RTO Insider Reporter Admitted to NEPOOL

The New England Power Pool voted Wednesday to admit RTO Insider correspondent Michael Kuser as an End User member under strict rules that prevent him from reporting publicly on what he hears in meetings.

The organization acted in response to NEPOOL Seeks Rehearing on Press Ban Order.)

Many of NEPOOL’s meetings are held at the Westborough, Mass., DoubleTree Hotel. | *Google*

The stakeholder group had sought to amend the NEPOOL Agreement to bar members of the press from joining after Kuser, an electric ratepayer in Vermont, applied to join in March 2018.

In its vote Wednesday, NEPOOL’s Participants Committee conditioned Kuser’s admission on compliance with its bylaws, which were rewritten in June 2018 in response to his application.

NEPOOL said the revisions were intended to codify a longstanding practice barring disclosure of meeting proceedings to nonmembers. But they also appear to carve out an exception for members who are not members of the press.

Section 5.6(a)(ii) states that:

“Attendees may use the information received in discussion, and may share the information received within their respective organizations or with those they represent, provided those who receive such communications are not press and also are aware of and agree to respect the nonpublic nature of the information. In no event may attendees reveal publicly the identity or the affiliation (other than sector affiliation) of those participating in meeting discussions…”

Members who violate the provision, the bylaws state, will have their attendance privileges revoked.

FERC’s January order said it would rule separately on RTO Insider’s complaint asking the commission to terminate the group’s stakeholder role or direct ISO-NE to adopt an open stakeholder process like those used by other RTOs (EL18-196). New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings or discussing them publicly.

RTO’s Interim Winter Fuel Proposal Rejected

In other action Wednesday, NEPOOL stakeholders rejected ISO-NE’s interim proposal for compensating generators for maintaining fuel inventories during winter.

The proposal, which would cover capacity commitment period 14 (2023/24) and 15 (2024/25), received less than 33% vote in favor, with most support from the Generation, Transmission and Publicly Owned sectors.

Members also rejected a proposal by energy services firm Energy New England that would have limited compensation to oil and certain natural gas, demand response and electric storage resources. It failed with less than 40% support, with most backing from the Supplier, Publicly Owned and End User sectors.

The votes were no surprise: Both proposals also fell short at NEPOOL’s Markets Committee last week. However, an ISO-NE Steady on Fuel Plan Despite NEPOOL Rebuff.)

ISO-NE’s plan is intended to prevent otherwise economic resources from retiring because they are not fully compensated for their winter energy security attributes. The RTO describes it as an interim measure until it completes development of a market-based compensation scheme for energy security.

The Participants Committee agenda had teed up a potential vote on proposals concerning the treatment of energy efficiency resources under the Pay-for-Performance capacity rules. However, no motion was made on the issue, according to NEPOOL.

At last week’s Markets Committee meeting, members had rejected a proposal by the New England Power Generators Association to address a disconnect in the calculation of PfP penalties during scarcity conditions in off-peak hours.

— Rich Heidorn Jr.

March 13, 2019

MISO Details Fast-track Queue Options

By Amanda Durish Cook

MISO on Tuesday confirmed that it will work with stakeholders to develop a fast-track option in its interconnection queue to accelerate the process for projects that can demonstrate readiness for development.

The RTO’s effort will focus on creating an expedited definitive planning phase (DPP) to move projects into generation interconnection agreements (GIA) faster than in the existing three-phase process.

In what was an about-face for MISO, staff last month expressed receptiveness to a fast-track queue option for shovel-ready projects. (See FERC Again Denies MISO Wind Developers’ Queue Complaint.)

MISO’s queue now contains about 420 projects worth a combined 70 GW, after interconnection customers withdrew 43 projects in January, with renewable resources accounting for about 90% of the queue. The average project takes a little more than 500 days to work its way from application to interconnection approval.

Although MISO has signaled readiness for a proposal, it says several design details need to be worked out. Resource Interconnection Planning Manager Neil Shah said the move would be heavily shaped by stakeholder input.

“We’re all open ears on this,” Shah told stakeholders during a March 12 Interconnection Process Working Group meeting.

Shah said MISO, which deferred fast-track discussion in 2017 based on lukewarm response from interconnection customers, has since received “a handful” of new requests for an expedited DPP. Devising a fast-track option now would be a “proactive” move, he said, adding that MISO’s current provisional GIA process has limitations, with customers completing the process without a permanent GIA in place.

“We heard the process is not meeting needs for shovel-ready projects,” he said.

Shah foresees an expedited DPP that can be scaled in three to six months for select projects: “That’s what I envision. Obviously, they should be ready to provide all the evidence that they’re ready.”

He said project owners would have to “submit evidence of viability at the time of request” to use the expedited process.

However, MISO staff said they have not yet determined exactly how to measure project readiness.

But the RTO is considering multiple requirements for entering the expedited DPP, Shah said, including higher queue fees, more certain environmental permitting, cash as security and a method for covering the risk of queue restudies.

MISO also said projects opting for the expedited process will still be responsible for the full cost of necessary network upgrades.

‘Queue-jumping?’

Entergy’s Yarrow Etheredge asked MISO to look into the possibility of project owners using the expedited process to “game” the interconnection queue.

Shah agreed and asked if stakeholders would have “queue-jumping concerns” if the expedited option becomes available to all interconnection customers. He also asked whether they would prefer either a megawatt cap or a limit of the number of projects an interconnection customer can request.

“If it’s available to all customers, is it queue-jumping?” Shah asked stakeholders. He added that if MISO crafts stringent enough requirements, it may not have to worry about limits.

“If there’s two queues, one for shovel-ready projects, and one for speculative projects, it might not be queue-jumping,” Etheredge said.

“Excellent point,” Shah replied.

Shah also asked for written stakeholder input until April 2. MISO staff will review the feedback and return with more discussion at the May 14 meeting of the Interconnection Process Working Group.

Measures to Accelerate Existing DPP

MISO says it is also developing a plan to reduce its regular, three-phase queue design and GIA process. The current DPP alone is approximately 355 days, which the RTO is proposing to reduce to 265 days, with Phase 1 cut from 140 to 80 days, Phase 2 staying roughly the same at about 80 days and Phase 3 slimmed from 135 days to about 105 days. MISO will also attempt to reduce the timeline allotted to negotiate GIAs from 150 days to about 100 days.

“We looked back in the history of queue reform. We’ve gone through a number of process improvements. … After reassessing the queue … we thought maybe we can look at a different angle to gain efficiencies to reduce the timeline,” MISO Manager of Resource Interconnection Arash Ghodsian said.

To achieve the reductions, MISO said it will start generation modeling before Phase 1 of the DPP begins and complete voltage and thermal studies internally rather than outsourcing them. Ghodsian said MISO found it can complete the study quicker than it takes a third party to develop study models. The RTO also expects less complicated Phase 3 modeling and system impact studies after already moving to reduce the number of late project dropouts by increasing site control deposits and milestone fees. (See MISO to File Queue Changes Before Year-end.)

Ghodsian also noted that reduced time spent on GIA negotiations is an obvious spot to seek efficiencies, given that 57% of projects that sign interconnection agreements do so under the full timeline outlined in the Tariff.

But stakeholders said multiple project applications currently in the queue claim the same patch of land for building generation, which could complicate early modeling. MISO staff agreed that certain steps must be taken before the RTO holds scoping-level calls as part of the queue application process.

“Those things must be addressed before we start analysis. I agree we’re seeing some of this today,” Ghodsian said. He said MISO’s queue improvements proposed last year should help “quality control” the project applications.

“There’s going to be a lot of back-and-forth going on. We’re going to have checkpoints,” Ghodsian said of drafting the models. He also called MISO’s proposed timeline “a starting point” and asked for written stakeholder input through April 2.

“This is just a proposal; we would like to hear your thoughts on these changes,” Ghodsian said.