Page 1059 – RTO Insider

March 17, 2019

Overheard at ISO-NE Consumer Liaison Group: March 14, 2019

PROVIDENCE, R.I. — Offshore wind will soon be comparable in scale to other renewable energy resources such as onshore wind and solar, participants at the quarterly meeting of ISO-NE’s Consumer Liaison Group heard last week.

New England never had natural gas or oil and has always had to pay for energy imports, but the region’s luck is changing with offshore wind, said Jeffrey Grybowski, co-CEO of Ørsted US Offshore Wind.

Jeffrey Grybowski, co-CEO of Ørsted US, addresses ISO-NE’s quarterly Consumer Liaison Group meeting in Providence, R.I., on March 14. | © *RTO Insider*

“Offshore wind has no size constraints like there are onshore,” Grybowski said. He cited the ever-growing size of commercial wind turbines as proof: Siemens (8 MW), Vestas (10 MW) and General Electric (12 MW).

“Each one of these manufacturers tries to one-up the other,” he said. “The projects are getting larger, reducing costs, and Ørsted is now working on a 1.2-GW project off the U.K.”

The lucky break for the region is that big load centers along the Northeast coast match the location of the highest offshore wind generation potential, Grybowski said.

“In addition, New England super-peak days in winter coincide with what are normally the highest production times for offshore wind here,” he said.

On the solar front, Acadia Center projects the region, combined with New York, will have 24 GW of distributed solar installed by 2030, plus about 12 GW of utility-scale solar.

“The economics of siting solar farms is driving developers to large, flat, forested sections of land, and this isn’t Kansas,” said Erika Niedowski, the center’s Rhode Island director and policy advocate.

According to the state’s Energy Plan, Rhode Island could develop more than 1,800 MW of solar by 2035, compared to the current 105 MW. “But we need to be developing clean energy with a balanced approach, with environmental considerations,” Niedowski said.

Douglas Gablinske, executive director of the Energy Council of Rhode Island, joked about the increasing resistance among New Englanders to any kind of new energy infrastructure: “I’ll introduce a new acronym to the sector, NWN, for ‘nobody wants nothing.’”

Market Policy Debate

Anne George, RTO Insider Reporter Admitted to NEPOOL.)

Under the proposal’s two-settlement structure, resources would be paid or charged for deviations between the inventoried energy purchased in a forward position for the entire winter season and the spot settlement rate — representing energy maintained during each trigger condition.

ISO-NE estimates the voluntary program will have direct costs of $112 million to $158 million a year. George noted that “the markets work together, so though this will be a payment through the energy market, when that’s dealt with in the capacity market the net cost is likely to be a lot less than that.”

The New England Power Pool Participants Committee on Wednesday rejected the RTO’s interim proposal, which would cover capacity commitment periods 14 (2023/24) and 15 (2024/25). Despite the proposal receiving less than 33% vote in favor, the RTO will move ahead with its filing. Members also rejected a proposal by energy services firm Energy New England (ENE) that would have limited compensation to oil and certain natural gas, demand response and electric storage resources.

Meg Lusardi, executive vice president of PowerOptions, the largest energy-buying consortium in New England, also questioned the RTO’s reasoning.

“The interim program … we refer to it as winter reliability on steroids,” Lusardi said. “The program failed to win passage at NEPOOL, though how that will affect decision-making at FERC is hard to say.”

PowerOptions signed on to a study by Synapse Energy Economics last May that showed the RTO’s January 2018 fuel security analysis to have been too conservative, which resulted in overplaying the risk of rolling blackouts, she said.

“There are cost impacts to customers with all of these market mechanisms that are going on, and it is complicated,” Lusardi said. “We all know that Mystic is being paid to run for 2022 to 2023, and maybe for 2023 to 2024, and this has been approved. The estimated cost for that is $200 million a year, so customers are going to have to take on that cost.”

George also mentioned that the RTO’s enhanced storage participation rules go into effect April 1, 2019. In February, FERC accepted Tariff revisions that enable batteries and other emerging storage technologies to more fully participate in the region’s wholesale electricity markets. (See FERC Accepts ISO-NE Storage Tariff Revisions.) But still pending before the commission is the RTO’s December 2018 filing that demonstrates full compliance with FERC Order 841.

From left to right: Douglas Gablinske, Energy Council of Rhode Island; Jonathan Schrag, Rhode Island Division of Public Utilities and Carriers; Erika Niedowski, Acadia Center; Timothy Hebert, Energy New England; and Meg Lusardi, PowerOptions. | © *RTO Insider*

Grid Transformation

Transformation of the Rhode Island power sector extends beyond grid modernization, said Jonathan Schrag, deputy administrator of the state’s Division of Public Utilities and Carriers.

“The larger power sector transformation … includes the work that the Office of Energy Resources is leading on procurement of clean energy resources … and the work that our Public Utilities Commission is leading on guidance for the way we do performance incentive mechanisms,” Schrag said.

The transformation also includes work his agency is taking on in collaboration with OER on non-wires alternatives, he said.

“We’re not just technology-agnostic, but hostile to any particular one” being pushed over any other, Schrag said.

Since the state deployed the bulk of its advanced meters between 1999 and 2003, most “are aging out now,” requiring state officials in the next few years “to make some critical choices around a very large distribution system asset.”

One strategy for the state is not so much “to promote electrification, but to optimize it,” he said.

“Rate design is a big deal,” said Timothy Hebert, COO of ENE, which serves municipal power companies. “What’s driving cost structures for customers is really changing. Around some of the new strategies that are being employed — distributed generation, storage — we’ve seen a lot of interest at the municipal utility level in developing electric vehicle programs.”

Regarding EV charging, Synapse’s Paul Peterson noted ISO-NE performed a 2016 economic study that showed one scenario with 3 million EVs in New England by 2030.

The RTO modeled the EVs to charge at night, “ran the model, and the problem was now the peak occurred at night,” Peterson said. “So then they told the model to charge the EVs at off-peak hours, and there was virtually no change to peak demand in the model, with or without the EVs, and the actual electrical energy used is not terribly significant.”

Data cannot be talked about enough, as there are so many additional layers of information to look at these days, Hebert said.

“We have a lot of different things happening … a dance going on every day.”

– Michael Kuser

March 17, 2019

CAISO RC Oversight Committee Elects Leaders

By Hudson Sangree

CAISO’s RC West Oversight Committee held its first monthly meeting Thursday at ISO headquarters in Folsom, Calif., as the grid operator prepares to assume the reliability coordinator role for most of the West this year.

Among the committee’s first orders of business was to elect a chair, Michelle Cathcart, vice president of transmission system operations with the Bonneville Power Administration, and a vice chair, Steve Cobb, director of transmission and generation operations at Arizona’s Salt River Project.

The election was an important step “because we really would like to make sure we’re hearing clearly from you, our customers, on how we should be operating this RC,” Phil Pettingill, CAISO’s director of regional integration, told those in the room and on the phone. “That’ll really set things up for us going forward.”

Michelle Cathcart and Steve Cobb were elected chair and vice chair, respectively, of the RC West Oversight Committee. | *CAISO*

Cathcart and Cobb have been serving in their roles for some time but were officially elected by committee members without opposition on Thursday.

RC West, as it’s now called, has secured agreements from 39 entities in the Western Interconnection, including Arizona Public Service, PacifiCorp and Seattle City Light. Its footprint stretches from the Canadian border into northern Baja California, and from the Pacific Ocean to the Rocky Mountains.

CAISO, RC Transition Fraught with Pitfalls, WECC Hears.)

CAISO plans to become the RC for its current territory in California and Mexico on July 1. BC Hydro will become the RC for most of British Columbia on Sept. 2. CAISO will then take over for many areas outside its footprint on Nov. 1, while SPP will take responsibility for other parts of the West on Dec. 3.

RC West has hired 18 reliability coordinators from Peak Reliability, CAISO, MISO, PJM and ERCOT, among others. CAISO set up around-the-clock control centers in Folsom, adjacent to the ISO’s main control room, and at a separate location in Lincoln, Calif., which is also in the Sierra Nevada foothills near Sacramento.

CAISO reliability employees will start shadowing Peak staff on May 1. The ISO is undergoing an RC certification process by the Western Electricity Coordinating Council that is expected to last until Oct. 1.

CAISO is slated to take over RC responsibilities for most of the West this year. | *CAISO*

The RC West Oversight Committee’s members include representatives from balancing authorities and transmission operators throughout CAISO’s RC territories. Its purpose is to provide input and guidance to CAISO’s RC management team on matters related to the RC function including operational issues, policies and procedures, and new tools or staffing that significantly affect the budget and costs for RC services.

The committee is planning to meet monthly throughout 2019. Its next meeting will be a webinar on April 17 followed by an in-person meeting May 21 in Folsom. The committee has its own webpage on CAISO’s site.

“We’re pleased that the ISO’s RC West is achieving targeted milestones and on track to begin operations later this year,” CAISO CEO Steve Berberich said in a news release upon the committee’s formation last month. “We welcome the participation from balancing authorities and transmission operators throughout the western United States, Canada and Mexico, and view this as a positive example of regional collaboration.”

March 17, 2019

MISO Going Back to the Futures for MTEP 20

By Amanda Durish Cook

MISO says it will rely on the same set of futures for the third straight year when it evaluates transmission projects in its 2020 Transmission Expansion Plan (MTEP 20) — but some stakeholders are eager for a rewrite of the scenarios.

The RTO announced the decision at a Thursday workshop on MTEP 20 futures development after proposing last month to recycle the futures with limited demand, capital cost, fuel price, retirement and renewable data revisions. But some members have argued that MISO’s limited fleet change future is no longer a likely scenario, and others have asked for more integration of the RTO’s ongoing, multiyear renewable generation study. (See “MISO Proposes Virtually Unchanged MTEP 2020 Futures,” MISO Planning Week Briefs: Feb. 12-13, 2019.)

MISO in 2017 created four future scenarios for use in MTEP planning, including:

limited fleet change, in which the fleet remains relatively static with coal units retiring at the end of their useful life;
continued fleet change, in which the grid develops according to the trends of the past decade;
accelerated fleet change, driven by a strong economy that increases demand and motivates carbon regulations and increased renewable use; and
a future in which distributed and emerging technologies become more widely used.

Veriquest Group’s David Harlan questioned whether the scenarios still capture the “bookends” of possibilities in the future. He pointed out that MISO could approve a major transmission project that looks useful under all four futures but proves not to be as beneficial as expected.

“There is a fairly large appetite to think about updating futures for the next cycle,” Harlan said. He also asked for MISO to provide more transparency into how it assembles futures assumptions.

The Union of Concerned Scientists’ Sam Gomberg said the futures “continue to underestimate the pace of renewable generation deployment across the region.”

In written comments submitted to MISO, the UCS said, “In particular, the limited fleet change future presents an unreasonably low assumption. … While we agree with MISO’s assertion that there have been no significant changes to state or federal policies to warrant new futures narratives, other significant drivers of renewable deployment have emerged in recent years and continue to accelerate renewable energy penetration levels.”

But NextEra Energy said, “Extensive updates to the base data are warranted.”

“The most significant economic changes have been cost reductions and technological improvements for wind, solar and battery storage generation. This has fundamentally changed the long-term value proposition of these technologies,” NextEra said. The company also pointed to 10 MISO utilities that have significant renewable or carbon reduction goals.

On the other hand, DTE Energy and American Transmission Co. said MISO’s plan to merely refresh its futures’ base data for MTEP 20 was appropriate. WPPI Energy said didn’t see an urgent need to revamp the futures for MTEP 20, but it asked MISO to plan an extensive retooling for 2021.

Consultant Roberto Paliza questioned whether MISO was properly considering recent climate change studies, electric vehicle expansion, corporate promises to get energy sourced from renewables and several utilities’ decarbonization commitments in the next decades.

There’s a “new potential reality,” he said. “I’m concerned that major transmission expansion will be made without focus on future possibilities that are not covered by these futures.”

“Today that hasn’t been hard-baked into the futures, but it’s an important conversation to have,” agreed MISO Planning Manager Tony Hunziker.

Hunziker said that even though MISO’s goal is to reuse the MTEP 19 futures for 2020, the RTO could incorporate some minor changes if “there’s critical mass on agreement” and it has the manpower, technical capability and time to make them.

But Minnesota Public Utilities Commission staff member Hwikwom Ham said the main uncertainty is load growth, more so than retirements and renewable penetration.

MISO will hold another workshop on the subject next month and expects to finalize MTEP 20 futures sometime in June.

March 17, 2019

MISO Floats Draft Storage-as-Tx Rules

By Amanda Durish Cook

MISO last week released draft Tariff language that would allow energy storage resources to compete for projects in the RTO’s annual Transmission Expansion Plan (MTEP).

The provision would allow storage-as-transmission assets (SATA) to pursue consideration in all classes of RTO transmission projects, including baseline reliability, market efficiency and multi-value projects, as well as market participant-funded upgrades.

During a Planning Advisory Committee meeting Wednesday, MISO Director of Planning Jeff Webb said the RTO would work with stakeholders on full Tariff revisions through May.

The rules would apply only to storage assets functioning strictly as transmission. Those assets would be able to bid for all transmission project types and be eligible for any associated MTEP cost allocation methodologies. MISO had originally proposed that SATA only be allowed to solve transmission reliability needs but changed course last month at the urging of stakeholders. (See MISO Opens Storage Proposals to All Tx Project Types.)

However, some stakeholders from the Transmission Dependent Utilities sector still contend that storage should be restricted to solving just reliability needs.

“Our feeling is that this is a significant expansion of the [original] scope,” WEC Energy Group’s Chris Plante said. “Expanding this to market efficiency projects is perhaps a bit much in the first phase of this.”

“The reason we’re doing this is stakeholders implied it was discriminatory to carve out reliability services from the FERC policy statement,” Webb said, adding that he didn’t think it appropriate for MISO to “call the shots” on the types of transmission projects available to storage.

MISO currently has “at least one” battery up for evaluation in MTEP 19 to solve a reliability issue, Webb said.

“I think it’s going to be challenge,” Webb said of the SATA modeling and selection process. “I think it’s a reality that we may never select a storage facility, and by that I mean [meeting] the planning, modeling and evaluation process. … We’re going to have to have a compelling reason to provide cost-based recovery, cost allocation to a storage device that can also provide market services.”

The draft language also notes that MISO is not yet detailing how a storage asset could function as both transmission and generation. “Subsequent phases of policy development will address those issues necessary to permit mixed-mode operation of providing both transmission and market services,” MISO said. Webb called the language a “temporary prohibition” and said future discussion would focus on how SATA could also maintain a market presence.

Load-shedding Considerations

But some members asked if MISO would leverage fully charged SATA during a maximum generation event to avoid shedding load.

“I think that’s an extremely interesting question. I think MISO would be doing a disservice if they didn’t take advantage of that,” WPPI Energy’s Steve Leovy said. “I think we should use fully charged batteries to avoid load shedding whether they formally have the title of … SATA.”

“I’ll have to think about that,” Webb responded. “What we would not want to do is use the resource as a generation asset to relieve a resource adequacy issue.” He said MISO would probably use the asset merely to resolve transmission constraints in order to keep the lines between generation and transmission distinct.

No non-TO Authorization

MISO’s draft proposal also stipulates that SATA can be owned only by those designated as transmission owners. It did not address last month’s proposal by DTE Energy to allow non-TOs’ storage assets to be eligible for cost recovery for providing transmission services. (See “Non-TO-owned SATA?” MISO Opens Storage Proposals to All Tx Project Types.)

After the February discussion, PAC leadership determined that DTE’s request raised complicated and out-of-scope cost-recovery questions. They directed the topic to the Steering Committee, where new topics in the stakeholder process are assigned to corresponding committees.

“We were really interested in seeing the follow-up to that discussion,” Clean Grid Alliance’s Rhonda Peters said.

“This has other elements beyond even treating storage as traditional transmission or generation. People can disagree with that assessment on our part,” Webb said.

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?”

David Morton, chairman of the British Columbia Utilities Commission, said he is concerned about distribution-level cybersecurity. Attacks “can happen in the distribution system also,” he said. “… While NERC and FERC have … standards in place that seem to be working reasonably well on the transmission system we don’t have similar assurance on the distribution system.”

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 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.