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February 23, 2020

Michigan PSC Orders DTE to Redo IRP

By Amanda Durish Cook

The Michigan Public Service Commission last week told DTE Electric to extensively revise its 15-year integrated resource plan, finding the utility didn’t adequately factor in the benefits of renewable energy.

The decision, which was neither a rejection nor approval, means DTE must go “back to the drawing board,” the state commission said Thursday. It gave the utility until March 21 to submit a revised IRP (U-20471).

Administrative Law Judge Sally Wallace in late December ruled against DTE’s IRP, saying the utility used outdated information in its modeling that produced results that minimized the advantages of renewable energy and energy efficiency. She also said the plan failed to include competitive bidding for renewable generation to fill capacity needs and leaned too much on natural gas-fired generation. In addition to the $1 billion, 1,150-MW gas-fired Blue Water Energy Center under construction, DTE proposed multiple gas-fired plants rated about 400 MW, 693 MW of wind generation, 11 MW of solar with on-site storage and 859 MW in demand response programs by 2024. (See DTE IRP Draws Fire from Renewable Proponents.)

The commission did not have to follow the judge’s recommendation in its final decision. However, Wallace had said DTE should adjust the plan even if the Michigan PSC decided to approve it.

DTE’s Belle River power plant | *DTE Energy*

But the trio of regulators largely agreed with the judge’s decision, saying the IRP should contain plans for a request for proposals for new renewable resources. The PSC also initiated two new proceedings in the order, including an April 1 deadline for DTE to update its renewable energy plan and a Nov. 13 deadline to file an application for review of its compliance with the federal Public Utility Regulatory Policies Act.

The PSC also required that DTE reach 1.75% energy savings in 2020 and 2% in 2021, the same targets the commission set for Consumers Energy. Michigan’s statutory minimum is 1% per year; DTE had proposed it satisfy a 1.65% savings in 2020 and 1.75% in 2021.

“The commission acknowledges DTE’s focus in the near term on ways to increase programs to cut energy waste, but we’re recommending that the utility do more to tap into this cost-effective resource,” PSC Chairman Sally Talberg said.

The commission said the plan’s failure to use current data and study renewable alternatives painted an incomplete picture.

“These issues inhibited the commission from assessing the full range of alternatives such as utility- and third-party-owned wind and solar projects,” the PSC said in a statement. In the order, it said there were “significant deficiencies” in DTE’s record, “including a starting point that included a range of nonapproved and nonoptimized resources and the failure to issue a request for proposals for supply-side resource additions.” The commission said it would be best for DTE to remove all the supply-side resource additions it proposed to start fresh.

It also said DTE’s proposal to hold off on full retirement of the coal-fired Belle River power plant near the Canadian border until 2030 was “inadequately justified because an analysis of avoiding new environmental upgrade costs was not considered.”

The PSC agreed with the criticism that DTE’s modeling software Strategist is outdated and no longer supported by its developer ABB Group. It ordered the utility to schedule a technical conference within three months to discuss alternative modeling software with “interested stakeholders.”

The commission didn’t mince words about the stakes for the utility. “Should DTE Electric fail to file a revised IRP that substantially adopts the recommended changes, the commission will be left with little alternative but to deny the IRP,” it said.

It said it accepted thousands of public comments since the plan was filed last March, the “vast majority” urging it to reject the IRP and direct DTE to increase its renewable fleet. Michigan’s reliance on coal has fallen dramatically, from more than 65% of the state’s generation fleet in 2007 to more than 40% in 2017.

“We appreciate the unprecedented amount of public participation generated by the interest in this case, a clear indication that Michiganders are becoming more engaged in helping to shape Michigan’s energy future,” Talberg said.

In a statement, DTE said it was evaluating the recommendations to prepare for a response filing. The company said the IRP “reflects our long-term goals and plans to be a leader in providing cleaner energy to our customers.”

“Since 2009, DTE has been the largest investor in renewables in Michigan, driving $3 billion in solar and wind energy infrastructure and investments. Over the next decade, we will triple our renewable energy assets,” the company added.

DTE had defended its plan in January, calling it the “most reasonable and prudent means” of meeting its energy and capacity needs. The utility repeated claims that it will not have a capacity need to be filled by small qualifying facilities under PURPA for at least the next five years and no planning-level need for additional capacity for at least the next decade. After the Belle River units retire in 2029 and 2030, DTE said it would begin to experience a 585-MW capacity shortfall. Until then, there’s no “persistent capacity need,” the company said.

The Union of Concerned Scientists had been particularly vocal, dogging DTE throughout the process for its reliance on traditional resources and on self-scheduled coal generation.

“So much of the resource plan was ‘hardcoded’ that DTE actually prevented the model from selecting resources that would otherwise provide real economic value to DTE’s customers,” UCS Senior Energy Analyst Joseph Daniel said last year.

A day after the PSC’s decision, Daniel said state regulators cut a “Gordian knot” by “neither approving nor rejecting the IRP but recommending major modification in such a way that is sending DTE back to the drawing board.” He characterized the order as a “Midwestern rejection.”

February 23, 2020

Calif. Energy Commission Relaxes Rooftop Mandate

By Hudson Sangree

SACRAMENTO, Calif. — In a controversial decision, the California Energy Commission on Thursday allowed the Sacramento Municipal Utility District to sell solar power to homebuilders and homeowners as an alternative to the rooftop solar panels required on all new homes built in the state after Jan. 1.

The commission adopted the cutting-edge regulations requiring rooftop solar last year but provided that “a community-shared solar electric generation system” could substitute for rooftop solar in new subdivisions. SMUD was the first utility to apply for permission to build community solar under its Neighborhood SolarShares Program last fall.

The commissioners unanimously approved SMUD’s request after a three-hour hearing, during which about 75 speakers addressed them in a hot, crowded hearing room.

Stakeholders packed the chambers of the California Energy Commission and overflowed into a second room for the Feb. 20 debate on rooftop solar. | © *RTO Insider*

Opponents argued that a decision in favor of SMUD would open the door for public utilities, community choice aggregators and eventually investor-owned utilities such as Pacific Gas and Electric to sell solar power to new subdivisions instead of each house or neighborhood having its own solar panels.

“This proposal will significantly undermine rooftop solar and storage in the SMUD territory, and it will set a precedent and a blueprint for other utilities, particularly the IOUs, to do the same,” State Sen. Scott Wiener (D), a PG&E critic, told commissioners. “Because we know that when it comes to PG&E and the other investor-owned utilities … there is no attack on rooftop solar and storage that they will not engage in because they want it to go away, and they see it as competition.”

Wiener said he regretted having to oppose SMUD, which broke away from PG&E more than 70 years ago — as San Francisco, which he represents, wants to do now — and has been a statewide leader in renewable energy.

Steven Lins, director of government affairs at SMUD, countered, “We’re focused on the big picture here, and for us that’s net-zero by 2040. That’s an audacious, aggressive goal, and we’re going to need every tool in the toolbox to get there.

“Neighborhood SolarShares is just one of many strategies that we have for reaching that goal,” he said. “It meets all the requirements. It’s just another path or option for compliance. It creates a choice for builders and buyers. Without Neighborhood SolarShares, there’s quite simply no other choice but rooftop, and that’s not what was intended in the regulations.”

Homebuilders, utility lobbyists and numerous SMUD employees spoke in favor of the community solar proposal. Not all new home buyers want rooftop solar panels, which can increase the purchase price of a house by thousands of dollars and require regular maintenance, they contended. Under SMUD’s proposal, homebuyers would have the choice of purchasing rooftop solar from builders as an add-on option or buying into the community solar program.

“Fundamental to the Energy Commission’s 2020 standards is choice,” said Frank Harris, manager of energy regulatory policy with the California Municipal Utilities Association. “In establishing the eligibility of a community solar option, the Energy Commission recognized that homeowners should have these options. The community solar program can provide a more efficient way to increase solar and maintain choice for homeowners for whom rooftop may not be the best way for introducing solar.”

Smart vs. Dumb Buildings

Environmentalists and solar industry representatives backed Wiener’s views, saying the SMUD plan would harm the movement toward rooftop solar and distributed energy resources.

“The proponents are trying to frame this as a solar-versus-solar decision, which I would imagine would be a hard choice for any and most environmentalists to make,” said Bernadette Del Chiaro, executive director of the California Solar & Storage Association.

“This is not solar versus solar,” she said. “This is the smart buildings of the future versus the dumb buildings of the past. The Energy Commission hoped for innovative community solar projects to come out of the alternative compliance option. All you’re getting today is a very commonplace utility-scale project, the likes of which the [renewable portfolio standard] will already support and bring to the fore.”

Commission staff recommended approval after SMUD agreed to make changes to its Neighborhood SolarShares proposal.

CEC Executive Director Drew Bohan said SMUD had agreed to build new solar farms within its service territory of less than 20 MW each to serve its community solar program. The utility’s initial plan could have imported power from large arrays hundreds of miles away, he said.

Controversy arose because California was the first state in the nation, starting seven weeks ago, to require rooftop solar panels on new residential construction, and opponents believed SMUD’s plan compromised that landmark achievement, Bohan said. (See Calif. Code Change Would Mandate Rooftop Solar.)

Commissioner Andrew McAllister, who oversaw the vetting of SMUD’s plan, said California must continue eliminating greenhouse gases and fossil fuels under Senate Bill 100, Assembly Bill 32 and other historic measures. The electrification of transportation and buildings is key to those efforts, and rooftop solar panels and community solar arrays should both play a role, he said.

“Building decarbonization is a huge topic. It’s a huge project for the state, certainly for the CEC, and it’s bigger than today’s discussion, I would argue,” McAllister said. “This is but one piece of that.”

He called for others to bring innovative proposals to the commission for consideration.

“We need to tend the fields of California’s diverse clean energy landscape so that all its many flowers can continue to bloom,” McAllister said.

February 23, 2020

In Rare Surprise, FERC Declines to Act on Jordan Cove

By Michael Brooks

WASHINGTON — FERC Commissioners Bernard McNamee and Richard Glick on Thursday voted not to act on a proposed LNG export facility, resulting in the rare surprise at what are usually tightly scripted monthly open meetings (CP17-494, CP17-495).

The commission was prepared to approve Calgary-based Pembina Pipeline’s application for its Jordan Cove LNG export terminal and accompanying Pacific Connector pipeline in Oregon as part of its consent agenda. The project was listed as being approved in a packet summarizing the actions the commission took as part of the meeting’s agenda.

But during his opening remarks, McNamee announced that he would be voting “nay” on the project after he said the state’s Department of Land Conservation and Development (DLCD) “provided a letter, apparently, to the applicant regarding its permits. I want to see what the state of Oregon said, and I need that information to inform my decision about whether I’m going to ultimately vote for or against” the project.

The Oregon DLCD had notified Pembina on Wednesday that it had “determined that the coastal adverse effects from the project will be significant and undermine the vision set forth by the [Oregon Coastal Management Program] and its enforceable policies.” The department cited the federal Coastal Zone Management Act (CZMA), and the regulations implementing the law, in asserting that because it has objected, neither FERC nor the U.S. Army Corps of Engineers could approve the project unless its objection is overridden by U.S. Secretary of Commerce Wilbur Ross.

A rendering of Jordan Cove LNG export terminal, focusing on the processing facility and marine slip from the northwest | *Jordan Cove LNG*

As required by the CZMA, the DLCD notified both FERC and the corps of its objection, but McNamee told reporters after the meeting he was unaware of what exactly the department had done. According to FERC’s eLibrary, the letter was filed with the commission on Wednesday but not actually published until the day of the meeting.

“All I know is that I saw in the news that Oregon did something on this and supposedly denied certain permits,” he told reporters. “I don’t know the details, and that’s why I want to know what the details are so I can make a reasonable decision.”

Chairman Neil Chatterjee told reporters after the meeting that McNamee informed him of his decision “just prior to the meeting.” Chatterjee had placed the project on the consent agenda in an effort to comply with the directives of the Fixing America’s Surface Transportation Act’s Title 41 (FAST-41), which is intended to improve the coordination between federal agencies in issuing infrastructure permits to speed their construction.

Glick, however, was apparently uninformed of the decision, as he issued a scathing dissent in his opening comments as if the project were going to go through. As the newest commissioner, McNamee is last in the order of who speaks during opening remarks and staff presentations.

Glick said that in addition to his usual objection to FERC not considering the impact of natural gas projects’ greenhouse gas emissions on climate change, the commission was also disregarding an Oregon law charging the state with reducing its carbon dioxide emissions to 14 million metric tons/year by 2050. According to Glick, the project would emit 2 million metric tons of CO₂-equivalent per year.

“This is significant. This is going to make it really tough for Oregon to meet its standards here,” Glick said.

The commission ultimately voted 2-1 not to act on the application at the meeting, meaning the project is still pending before it, said Deputy General Counsel David Morenoff, invited by Chatterjee at his press conference to explain to reporters the procedure.

Prior to the vote, as commission Secretary Kimberly Bose read off the list of agenda items, Glick could be seen conferring with his staff and General Counsel James Danly before he joined McNamee in voting “nay” on the Jordan Cove agenda item. Normally, commissioners vote “aye” on the consent agenda after noting their individual dissents and concurrences on specific items.

McNamee said in a statement after the meeting that he voted against the project without prejudice, meaning he did not vote on the merits of the application. But Glick told reporters after the meeting that he was concerned that he could be deemed to have prejudged the matter because of his comments before the vote — though he noted that would mean he would have to recuse himself from the proceeding, leaving the commission without a quorum to act on it. He said he would not have said anything had he known what McNamee was going to do.

The commission could vote on the project again as soon as McNamee is ready, Chatterjee said. McNamee said he expected to be able to vote on it this week.

The Jordan Cove export terminal would be in Coos County, on the southwestern coast of Oregon. It would produce 7.8 million metric tons of LNG per year, according to FERC. The Pacific Connector pipeline would run 229 miles, transporting 1.2 million dekatherms/day of gas to the terminal from a trading hub near the city of Malin, Ore., on the border of California. The project’s website lists “proximity to active Asian markets” as one of its “essential characteristics for an optimal export facility.”

Glick ‘Disappointed’ and ‘Saddened’ by Dissents

Glick issued 14 dissents at the meeting, saying he was “very disappointed that we have gotten to this place, and I’m saddened about what that says about this agency.”

“This is an agency that used to be known for nonpartisanship and compromise, but … I still can’t vote in good conscience for orders that violate the law and come nowhere close to reasoned decision-making.”

Speaking about Jordan Cove, he listed several different impacts unrelated to emissions that he said the commission failed to adequately consider and mitigate.

“I think in this order, we’re actually being honest” about whether the commission weighs the benefits of a project against the adverse impacts in determining if it’s in the public interest, Glick said. “We say, ‘We don’t really do that. We just look at the adverse impacts on landowners, and we weigh that against the economic benefits of the project, and then later on, in the order, we’ll talk about the environmental impacts, but we really don’t include the environmental impacts in our decision-making process.’ Something’s really rotten with that. … I think that’s why the commission has really earned its reputation as being a rubber stamp for these types of pipeline and LNG projects.”

Glick noted that one of the orders he dissented on denied reconsideration of staff giving Enbridge a two-year extension to complete construction of its Atlantic Bridge, a project to expand its Algonquin Gas Transmission and Maritimes & Northeast Pipeline systems (CP16-9). Staff approved the extension Dec. 26, 2018 — the same day it was requested, only 34 minutes after it was published on eLibrary.

“I just don’t understand why … we’ve delegated this [function] to staff,” Glick said.

Glick gave his colleagues credit for establishing a new procedure for requests for extension of time to complete construction going forward. In the order, the commission directed the Office of the Secretary and Office of Energy Projects to notice all such requests within seven calendar days of receipt and establish a 15-calendar-day intervention and comment period deadline.

“But that doesn’t eliminate the injustice that occurred in this case,” Glick said. “I think at the very least we could have granted rehearing and reconsidered” Enbridge’s request.

McNamee acknowledged that the extension approval “doesn’t look good.” He noted that staff were aware of the incoming request and of the project’s ongoing delays because of litigation. But McNamee agreed with Glick that “the public should have more of an opportunity” to comment.

The meeting was interrupted seven times by protesters from environmental group Beyond Extreme Energy, the first such disruption since April 2019. (See Enviro Protesters Scale FERC HQ as Agency OKs More LNG.) The protesters were escorted out of the meeting room by security.

February 23, 2020

CAISO, NYISO, Companies Win Partial OK on Order 845

By Amanda Durish Cook

FERC on Thursday largely approved the Order 845 compliance filings for CAISO, NYISO and a handful of utilities, though none of the entities received perfect marks.

The commission said the companies and grid operators mostly adopted its pro forma large generator interconnection procedures but fell short of adopting all language required under Order 845.

FERC issued Orders 845 and 845-A in 2018 and 2019, respectively, to increase the transparency and speed of generator interconnection processes. (See ‘Boring Good’ Rulemaking Seeks to Clean up Order 845.)

The commission directed the two grid operators and five utilities to make additional changes to their filings, focusing on contingent facilities, provisional interconnection service, generators’ technological advancements and surplus interconnection service. The entities have 60 days to address the shortcomings.

In addition to CAISO’s (ER19-1950) and NYISO’s (ER19-1949) partial compliance, FERC found partial compliance from Arizona Public Service (ER19-1939), Cube Yadkin Transmission (ER19-1956), Deseret Power (ER19-1902-001), El Paso Electric (ER19-1953) and LG&E and KU (ER19-1916).

Contingent Facilities

In a familiar line, the commission said the entities’ proposals “lack the requisite transparency … because the proposed tariff revisions do not detail the specific technical screens or analyses and the specific thresholds or criteria that [they] will use as part of its method to identify contingent facilities” — unbuilt interconnection facilities and network upgrades on which the interconnection request’s costs, timing and study findings are dependent.

“Without this information, an interconnection customer will not understand how [they] will evaluate potential contingent facilities to determine their relationship to an individual interconnection request,” FERC said in nearly all the orders, adding that such criteria will ensure that interconnection customers are treated equally.

Contingent facility descriptions presented a challenge in an earlier round of 845 approvals. (See FERC Finds Partial Compliance on Order 845.)

Surplus Service

Revisions related to surplus interconnection service were also a stumbling block for many of the entities.

FERC said CAISO and Deseret failed to include tariff revisions that explicitly require that the transmission provider, original interconnection customer and surplus interconnection service customer file a surplus interconnection service agreement with the commission that outlines the terms and conditions of the service.

FERC Order 845 — Wind farm near Palm Springs | © *RTO Insider*

The commission directed LG&E/KU to remove a provision that it will not allow surplus interconnection service if the system impact study identifies a need for new interconnection facilities or network upgrades. FERC said while Order 845 does restrict surplus service when network upgrades are needed, it does not “restrict the construction of new interconnection facilities necessary to accommodate surplus interconnection service.”

El Paso Electric must also revise its tariff to explicitly state that surplus interconnection service requests will be processed outside the non-surplus interconnection queue.

Cube Yadkin’s surplus interconnection service provisions also missed the mark, FERC said. The subsidiary of North Carolina hydroelectric company Cube Carolina proposed that “any change made to the existing interconnection service will be treated as a new interconnection request.” FERC said that while Order 845 allows a transmission provider to deny surplus interconnection service if it requires network upgrades, it’s “not for the reasons that Cube Yadkin proposes.”

CAISO

CAISO has the most alterations ahead of it to fully comply with Order 845.

FERC said the ISO’s existing limited operation study — used when an interconnection customer requests service below its full generating facility capacity — missed the aims of Order 845 because the study places restrictions on when a customer may request provisional interconnection service. The limited operation study can only be performed when a transmission owner’s interconnection facilities or network upgrades “are not reasonably expected to be completed” before the generator’s commercial operation date, according to CAISO.

The ISO also must research its Tariff to find evidence that area delivery network upgrades can be cost-capped in the same manner as reliability network upgrades and local delivery network upgrades. FERC said it couldn’t accept some of CAISO’s Tariff language without proof that the practice was already in place. The ISO had said costs for area delivery network upgrades above caps identified in interconnection studies must be financed by the TO.

CAISO also went off-script in its pro forma large generator interconnection procedures when it proposed potential penalties for generators that exceed their level of interconnection service capacity. The commission explicitly decided against penalties for over-generation in Order 845, FERC said, adding that the ISO must make a separate filing to propose over-generation penalties.

Technological Advancements and Provisional Service

FERC also said that CAISO, Cube Yadkin and Deseret failed to mention their requisite 30-day deadline to determine whether a proposed technological advancement to a generation project amounts to a material modification. Additionally, the commission said APS and LG&E/KU didn’t describe studies used to determine whether generators’ technological advancement requests constitute material modifications.

Spotty language around provisional interconnection service was also an impediment to full Order 845 compliance for NYISO and El Paso Electric.

FERC said the ISO’s pro forma large generator interconnection agreement should specify the “frequency with which NYISO will study and update the maximum output of a generating facility” with provisional interconnection service.

The commission also said El Paso Electric’s pledge to update its provisional interconnection studies “whenever changes experienced or projected to occur on the system warrant re-evaluation of the maximum permissible output” was too vague.

February 23, 2020

MISO Steering Committee Briefs: Feb. 19, 2020

Stakeholders will keep a close eye on MISO’s attempt to improve a customer market portal, the RTO’s Steering Committee decided during a Wednesday conference call.

The committee instructed the Market Subcommittee to monitor the RTO’s progress on using more up-to-date information in the Customer Connectivity Environment (CCE).

The nonpublic CCE provides MISO members access to the day-ahead and real-time market user interface, meter data upload applications, and the financial transmission rights and auction revenue rights system.

DTE Energy submitted a complaint on connectivity issues and the state of the data upkeep in the CCE, saying database updates are not being performed regularly.

DTE Manager of Wholesale Market Development Nick Griffin said market participants and MISO software vendors “unnecessarily waste time and resources” during new software testing, “facing extended testing times and elevated costs for software implementations.”

Griffin said during MISO’s rollout of five-minute market settlements in 2018, a “lack of relevant meter data, awards, offers, dispatch instructions, etc.” resulted in a less-than-ideal member testing of the new settlement system.

“We have experienced ongoing production-submission incidents, including unit offers, demand bids and meter data submissions,” DTE said, adding that the problems “reduce confidence in CCE.”

DTE said the problem requires “immediate attention,” especially considering that MISO is refreshing its IT systems as part of its ongoing market platform replacement.

MISO’s Jim Kaminski said staff are aware of the problem and “actively working on the issue.”

“This is quite an issue that we need to take a look at,” SC Chair Tia Elliott said.

SC Mulls Consultant Transparency

The SC may also delve into how forthcoming consultants should be about who they represent during MISO committee meetings.

At the beginning of the year, committee leaders began enforcing a rule that all stakeholders making comments during meetings first identify themselves and who they’re representing before speaking.

The Planning Advisory Committee has reported that some consultants participating in meetings are reluctant to reveal their clients before offering comments or criticisms on MISO presentations.

“There are some individuals in some meetings that are making some rather large requests of MISO. … It would be nice to know who they’re making those requests on behalf of. I think that’s something important to know,” WEC Energy Group’s Chris Plante said.

“I think MISO’s meetings need to be open and fair. And this kind of behavior might not result in fair meetings because of hidden clients … trying to influence the process,” Minnesota Public Utilities Commission staff member Hwikwon Ham said. “I am biased towards the state regulatory sectors and the Minnesota commission. I do not deny this. I want the same of others so I can interpret their opinion in certain matters.”

Elliott said consultants could be bound to nondisclosure agreements. Such consultants also could be representing just one MISO stakeholder or several, she said.

The committee would schedule time at its March 25 meeting during MISO Board Week in New Orleans for a deeper discussion on the issue, Elliott said.

— Amanda Durish Cook

February 23, 2020

Study Gauges Reliability Benefits of EIM Day-ahead

By Robert Mullin

SEATTLE — Preliminary findings from a Western Electricity Coordinating Council study indicate that inclusion of day-ahead trading in the Energy Imbalance Market will yield reliability benefits that outweigh any expected risks for the Western Interconnection.

Among the benefits: increased coordination across a broader geographic area; uniform application of advanced scheduling processes over multiple balancing authority areas; and improved positioning of resources for real-time operations.

The working group developing the study shared its initial impressions Wednesday at a meeting of WECC’s Market Interface Committee (MIC).

Working group member Alaine Ginocchio, a policy analyst with the Western Interstate Energy Board, explained the report will be tightly focused on providing a “qualitative” assessment of the reliability impact of incorporating CAISO’s proposed extended day-ahead market (EDAM) into the EIM. It will not examine potential economic benefits or cost savings from the change, she said.

“We’re going to describe changes in the day-ahead processes and the potential impact those processes could have on reliability,” Ginocchio said. The group is examining reliability impacts through the lens of operations; ancillary services; resource sufficiency; transmission and seams operations; and congestion management.

EIM day-ahead — More than 30 people attended the WECC Market Interface Committee’s Feb. 19 meeting in Seattle. | © *RTO Insider*

The report’s analysis assumes that existing BAA boundaries and NERC-related responsibilities will remain intact and that CAISO will not take control of transmission facilities. It also assumes that integrated resource planning, resource adequacy procurement, and transmission planning and investment decisions will continue to fall to individual BAAs and their state and local regulators.

Ginocchio said the intended audience for the report is state policymakers, utility regulators and WECC’s Board of Directors. “You are not our target audience,” she told MIC members.

And she offered one important caveat: The report will be released before the conclusion of CAISO’s EDAM stakeholder initiative, which will not even produce a straw proposal until late March.

“We’re out ahead of the market design here,” Ginocchio said, clarifying that the working group has no special insights into what the ISO will produce from the EDAM initiative.

“We didn’t want there to be confusion as we go through this that somehow we have some inside information about what the potential design is and that’s what we’re analyzing. We do feel like there’s enough public information right now to make some high-level assumptions about this market framework,” she said.

Those assumptions include:

Participation in the day-ahead market will be voluntary for EIM participants.
The market will rely on security-constrained unit commitment, a full network model and LMPs.
Ancillary services will be offered in the market along with energy.
A resource sufficiency evaluation will be required before trading in the market, although the report will make no assumptions about the design of the test.
The EDAM will operate alongside the existing bilateral day-ahead market.
CAISO will not be offering a centralized capacity market.

Paradigm Shift

Jason Smith, senior manager of operations at Xcel Energy and a participant in the study, told the MIC the WECC report will go into “good detail” about the three trading “paradigms” currently in play in the West: a highly centralized CAISO, EIM BAAs and non-EIM BAAs.

“The things that the three types of BAAs are doing [before real-time commitment] are really the same process at a high level,” Smith said.

Before committing units, he said, “you’ve got to assess the situation depending on what your constraints are going to be,” including transmission limits, ancillary service obligations, load, and physical requirements for firming up variable energy resources.

A number of factors go into the decisions, including the cost of buying power in the market versus self-supply, opportunities to sell and market positioning.

“And we don’t just make those decisions in the day-ahead and send those guys home. It’s fully reoptimized in any of those scenarios all the way up until real time,” Smith said.

CAISO’s centralized market provides the benefit of coordinated submission of unit data and a single decision-maker dispatching across a wide area. And the ISO requires a lot more unit-specific data compared with the bilateral market, including resource commitment details and transmission availability. “All that information has to come into the market operator in sufficiently advanced time so those decisions can be made,” Smith said.

“There’s a lot of scrutiny on the data when we make it financially binding. I’ve always said, once you make the data financially impactful, the data seems to get better really quickly,” he said.

Smith said the working group had some difficulty in pinpointing the EDAM’s potential reliability benefits around transmission coordination.

“In going through this report, we found it was very, very difficult to carve reliability versus economic benefits.

“We would discuss that what are we doing in the day-ahead [is] … reducing [commitment] down to an efficient level,” he said. “Efficient means less resources online, so is that an economic benefit or a reliability benefit?”

But some reliability benefits are readily apparent, including better positioning for real time and improved visibility across the system, helping BAAs avoid “committing their own resources in a vacuum.”

An EIM day-ahead market could also reduce the region’s deployment of flexible resources needed to firm up the output from variable renewable resources.

“We use a phrase: ‘complementary diversity.’ That’s just reflecting solar decreasing in the afternoon as wind is starting to increase,” Smith said.

Risk/Benefit Trade-off?

But the study also points to possible risks, including the development of new seams between different market footprints. That could lead to a breakdown in communication and coordination as utilities inside and outside the EIM unknowingly vie for the same resources.

“We can’t have two entities looking at the same transmission capability and deciding that it’s available for use in the day-ahead. That has to be coordinated,” Smith said. “And congestion management is going to fall out of that. That has to be managed between and across seams.”

Smith also pointed to the working group’s concern about how EIM day-ahead scheduling will allow participating transmission operators to push transmission lines to the edge of their capacity.

“There are probably going to be parts of the transmission system that are run all the way up to their limits. Depending on your point of view, do you consider that a benefit or a risk?” Smith asked. “I mean, we’re more fully utilizing it, but yet we’re staying below any reliability considerations. Economically, that’s pretty apparent, but on the reliability side, it can get a little more gray.”

The same goes for changes that will tighten up the resource commitment process.

“You [currently] have a bunch of entities committing inefficiently, which may lead to excess capacity on the system at a given time,” Smith said. “How much reliability benefit has that given us? How much cushion has that been giving us that we’re going to decide — on an economic basis — to kind of give away?”

MIC member Raj Hundal, market policy and practices manager with Powerex, asked Smith to elaborate on the benefit of improved positioning in unit commitment. “Is that not occurring with the [reliability coordinators] right now? Are they not positioning themselves, or are they not seeing something there that’s going to be different?” he asked.

Smith said the role of the RCs is to keep BAAs “between the digits so you can get out of a problem,” not to minimize the system cost impacts of congestion. “They’re just there to ensure that the congestion can be resolved,” whereas an EIM day-ahead process will position the system so that the operator will have to mover fewer units “out of the way” in real time, he said.

“When we say better positioning in the real-time, there is definitely an economic aspect to that,” he said.

Illiquidity Trap

The study points to another likely risk: reduced liquidity in the region’s bilateral day-ahead market. A similar development has already occurred in the real-time bilateral market as more Western BAAs have joined the EIM, compelling others to sign up. (See EIM Entrants Cite Changing West as Motivation for Joining.)

Andrew Meyers, a public utility specialist on the Bonneville Power Administration’s trading floor, said the study assumes that EIM day-ahead market participants will turn over the day-ahead unit commitments to CAISO.

“As a result of that, we believe you’ll see a natural reduction in day-ahead, physical, bilateral activity as entities join the EIM plus [day-ahead],” creating “different pools of liquidity in the day-ahead arena” and leaving non-EIM entities to trade only among themselves.

And while Meyers said it would be “premature” to say what type of resource sufficiency test CAISO will perform to prevent EIM entities from leaning on each other in the day-ahead market, the working group anticipates there will be some sort of sufficiency check.

“We think entities failing resource sufficiency would be seeking supply to become resource sufficient … by going out to that bilateral pool. If that’s only a few folks or a small number, it may be more challenging for folks to be successful for grabbing the energy that they were hoping to locate,” Meyers said.

“As a part of a BA, and somebody without a huge amount of resources ourselves … I think it would be a problem for us, especially in a day-ahead market when we may have limits to the contracts we have now,” said MIC member Mike Shapley, a short-term power trader with Snohomish Public Utility District, which sits within the BPA BAA.

“I believe you have valid concerns,” said working group member Robert Follini, manager of preschedule and real-time trading at Avista. “It’s going to be something you’re going to have to go to your company with and see how you will position yourself.”

Ginocchio said the working group plans to post a draft of the EDAM report to the WECC website in mid-March. The final report should be released in late May.

February 21, 2020

NERC Plans to Expand GADS to Solar

By Holden Mann

NERC’s Performance Analysis Subcommittee (PAS) is preparing a data request to expand the Generating Availability Data System (GADS) to cover solar generation facilities, in addition to increasing the range of data that the system collects from wind and conventional generators.

Solar facilities of 20 MW or greater will be asked to provide plant configuration, connected energy storage, performance and event reporting, and equipment outage details under a new GADS-PV system.

Wind facilities of 75 MW or greater, which report under GADS-W, will be asked for size and other configuration data on connected energy storage.

Conventional facilities of at least 20 MW, which report to GADS, will be asked for common attributes for all unit types plus additional unit-specific characteristics. Both wind and conventional generators will also be required to provide event reporting data for the first time. The new requirements for wind and conventional facilities would take effect on July 1, 2021.

NERC GADS — Solar plants would be covered under new GADS reporting standards. | *Consumers Energy*

Presenting the proposal at this week’s PAS meeting, Margaret Pate, reliability risk control program liaison for NERC, said solar facilities would be phased into GADS in order to give generation operators time to adapt their protocols. Voluntary reporting would begin on July 1, 2021, and run through the end of the year. Mandatory reporting for solar facilities of 50 MW or greater would begin on Jan. 1, 2022, and would be extended to facilities of 20 MW or greater the following year.

In response to a question from PAS Chair Maggie Peacock about whether the GADS working group had considered applying the same requirements to all three types of generation, Pate said it had not. “I think the nature of the way that renewable plants are owned and operated is very different from … conventional [plants], from our experience and from what we’ve heard from the industry,” she said.

Reporting Threshold Questioned

Several subcommittee members suggested that the GADS team also consider changing the threshold for reporting generation outages. Under the current proposal, operators of solar facilities would be required to report a loss of capacity of at least 20 MW, lasting 10 minutes or longer — the same requirement that applies to wind. David Penney of Texas Reliability Entity and Joe Eto of the Lawrence Berkeley National Laboratory asked if the threshold could be changed to that required of conventional generators, which are required to report outages of one minute or more.

“My concern was that it’s the short-duration, momentary cessation [events] that have gotten flagged in our State of Reliability Report. … A number of special alerts [have] been issued by NERC around that, and [the Inverter-Based Resource Performance Task Force] is very focused on getting vendors to modify their equipment to prevent that behavior from taking place,” Eto said. “Someone ought to memorialize that we’ve succeeded by measuring when these things happen and that they’re decreasing in frequency and extent.”

Donna Pratt, performance analysis manager for data analytics at NERC, said the threshold was chosen after feedback from industry representatives that meeting the same standard as conventional generators would be “very difficult … because of the nature of the way that wind and solar operate.” The 10-minute time limit would give operators time to address temporary outages that might result from momentary supply disruptions rather than equipment issues.

The GADS working group plans to continue working on its data request after the Planning Committee’s meeting March 3. Depending on when it finishes reviewing the request, the subcommittee will pass it to either the PC or the new Reliability and Security Technical Committee. The PAS hopes to submit the plan for review by NERC’s Board of Trustees at its November meeting.

February 21, 2020

FERC Sets Inquiry on Virtualization, Cloud Services

By Holden Mann

FERC on Thursday issued a Notice of Inquiry seeking industry comments on the “potential benefits and risks” to the bulk electric system posed by virtualization and cloud computing services (RM20-8). Separately, the commission ordered NERC to provide information on two existing draft critical infrastructure protection (CIP) reliability standards relating to the same topics (RD20-2).

The NOI issued at the commission’s open meeting builds off of discussions at the commission’s annual technical conference on reliability last year, as well as a tech conference on security investments for energy infrastructure in March 2019 sponsored by FERC and the Department of Defense. (See Reliability Conference: Deterrence or Collaboration?)

Industry Input Sought on Cloud Services

FERC is requesting comment from industry players on four topics:

The scope of potential use of virtualization and cloud computing services;
Potential benefits and risks associated with these services;
Obstacles to adopting virtualization and cloud computing posed by existing CIP standards; and
Possible uses of new and emerging technologies in the current CIP standards framework.

FERC cloud services — Patricia Eke, Office of Electric Reliability

FERC said comments submitted will inform its decision on whether to direct NERC to modify CIP standards to facilitate the use of virtualization and cloud computing by operators, addressing a key shortcoming identified by commissioners in the existing framework.

“The currently effective CIP reliability standards were developed in an era when registered entities would procure, manage and use their own computing systems to facilitate reliable bulk electric system operations,” Patricia Eke, with the Office of Electric Reliability, said in a presentation to the commission at its open meeting. “Thus, the development of the reliability standards did not contemplate explicitly how such computing systems could be deployed in a cloud computing environment.”

Comments are due 60 days after the NOI’s publication in the Federal Register.

NERC to Provide CIP Standard Updates

In conjunction with the NOI, the commission also directed NERC to make an informational filing describing work on Projects 2016-02 and 2019-02, including their current status, interim target dates and anticipated filing dates for new standards. NERC must submit its informational filing within 30 days of the issuance of the order, with quarterly status updates until new standards are filed.

Project 2016-02 was started in 2016 in response to a directive in FERC Order 822 relating to the protection of transient electronic devices used in low-impact BES cyber systems. Eke said FERC sought more information on it because “the standard authorization request for the project … includes matters beyond Order 822 directives, including industry-requested revisions to support the use of virtualization technologies by registered entities.”

Project 2019-02 launched last year and is intended to improve BES reliability by providing entities with more options for managing their BES cyber system information. FERC required the informational filing because of its mandate to address third-party storage and analysis systems and clarify protections expected when using such solutions.

“It’s pretty clear from the two technical conferences we’ve had on this issue that this is where the industry is heading: towards more cloud computing, more virtualization. And I think it’s just as important from our perspective to make sure this transition is done in a safe and secure and, obviously, reliable manner,” Commissioner Richard Glick said.

February 21, 2020March 12, 2025

FERC Narrows NYISO Mitigation Exemptions

By Michael Brooks and Michael Kuser

WASHINGTON — FERC on Thursday narrowed the resources exempt from NYISO’s buyer-side market power mitigation (BSM) rules in southeastern New York, ordering the ISO to subject storage and demand response to a minimum offer floor in its capacity market.

In doing so, the commission granted a request for rehearing by the Independent Power Producers of New York, partly reversing its 2017 decision to grant a blanket exemption from the rules for special-case resources (SCRs), a type of DR (EL16-92 , ER17-996). (See ‘Special Case’ DR Exempted from MOPR in NYISO.) FERC ordered that all new SCRs be subject to the rules. It also decided it will evaluate retail-level DR programs on a program-specific basis to determine whether their payments should be excluded from the calculation of SCRs’ offer floors, initiating a paper hearing to gather information on the programs.

The commission also denied a complaint from the New York Public Service Commission and the New York State Energy Research and Development Authority seeking an exemption for electric storage resources (ESRs), ruling that applying “buyer-side market power mitigation to electric storage resources in NYISO appropriately protects the capacity markets from the price-suppressive effects of resources receiving out-of-market support” (EL19-86).

Nine Mile Point nuclear plant in Oswego, N.Y. | Constellation Energy Nuclear Group

FERC also rejected NYISO’s proposed 1,000-MW cap on the exemption for renewable resources and a proposal to allow state entities to be eligible for the exemption for self-supply resources (ER16-1404). The proposals were part of a compliance filing the ISO filed in response to FERC ordering it to exempt a narrowly defined set of renewable and self-supply resources.

“Rather than basing the megawatt cap on the mitigated capacity zones, NYISO proposes a megawatt cap based on historical entry of all resource types across the entire [New York Control Area],” FERC said. “We reiterate that NYISO must develop a megawatt cap narrowly tailored to the mitigated capacity zones that recognizes that only eligible renewable resources entering the mitigated capacity zones are subject to the buyer-side market power mitigation rules and, therefore, are eligible to apply for the renewable resources exemption.”

Commissioner Richard Glick dissented on the three orders and issued a concurrence on a fourth ruling upholding the commission’s rejection of a complaint by IPPNY seeking to apply the rules to existing capacity resources retained pursuant to a reliability support service agreement and those with repowering agreements (EL13-62).

IPPNY had also requested that NYISO’s BSM rules be applied statewide, which the commission also rejected. Only resources in the G-J Locality, consisting of the Lower Hudson Valley (Zones G, H and I) and New York City (J), are subject to the rules.

In announcing the commission’s decisions at its open meeting, Chairman Neil Chatterjee said they “narrow the scope of exemptions from the BSM rules, thereby broadening the market’s protections against price distortion. … Consumers benefit when our organized markets remain competitive and send the right price signals.”

Chatterjee acknowledged the speculation that the commission would be taking the same action as its expansion of PJM’s minimum offer price rule (MOPR) in December. (See “MOPR Contagion?” PJM Seeks to Quell ‘Inflammatory’ Exit Talks.) “These two markets’ footprints and capacity constructs are very different, and our orders today are shaped by the unique issues that arise in New York ISO and the particular complaints brought by parties in these proceedings,” he said. “However, the underlying principles for both actions are similar: We are working to ensure that capacity markets provide accurate price signals to ensure adequate supply where it’s needed.”

Commenting on his dissents, Glick said, “It’s comical to suggest that what we’re doing here in New York … has anything to do with buyer-side market power. … Most of the resources affected by today’s orders aren’t even buyers. And those that are, very few of them have actual market power. And yet the commission has decided to subject them all to a mitigation regime that’s going to increase prices and make renewables, demand response and energy storage less likely to clear in the market.”

Glick rejected Chatterjee’s “underlying principles,” instead saying that the orders, as well as the PJM MOPR expansion and ISO-NE’s Competitive Auctions with Sponsored Policy Resources construct, mean the commission wants “to raise prices for existing generators and stunt the development of new clean energy resources, which so many states are eager to promote.”

“The fact is we’ve created one big mess in the Eastern capacity markets, and I don’t think my colleagues have a plan for getting us out of it.”

New York’s only coal-fired plant in service, the 686-MW Somerset plant, is set to close as early as March 2020.

Commissioner Bernard McNamee said in response that “our obligation is not to impose a worldview on those different RTOs or ISOs. Instead, it’s to look at, how are they developed? What are the resources that are available to them? How does their load look? … My goal is not to give some overarching theme, but instead to address the issues that are before us.”

Though FERC did not publish the orders until well after the end of the open meeting, clean energy groups were quick to lambast them.

“FERC does not appear to value the contribution of clean energy resources to fight climate change,” the Alliance for Clean Energy New York said. “The FERC decisions create an unnecessary barrier to entry of new renewable energy resources that are essential to achieving New York state’s Climate Leadership and Community Protection Act goals to address climate change.”

“FERC delivered a new subsidy to the fossil fuel industry today at the unfortunate expense of New York ratepayers,” said Gregory Wetstone, CEO of the American Council on Renewable Energy. “This is an echo of FERC’s so-called ‘MOPR’ decision in December that delivered a Christmas gift to fossil fuels in the PJM capacity market. FERC has once again made a decision that will lead to more pollution and higher electricity rates, this time for New Yorkers.”

The Natural Resources Defense Council said the orders are “the latest attempt by a hyper-politicized Trump FERC to try and pose barriers to states deploying clean energy resources.”

“We are encouraged that FERC’s decisions recognize the NYISO’s markets as a strong platform to address the challenges of a grid in transition,” NYISO CEO Rich Dewey said. “The NYISO is working quickly to develop a compliance plan in response to the FERC decisions that will also help New York meet its aggressive clean energy goals. The NYISO is confident carbon pricing in the wholesale markets can also address the federal, state and stakeholder concerns highlighted in these proceedings.”

The New York PSC has initiated a proceeding on whether NYISO’s capacity market is an effective tool to meet the state’s ambitious clean energy and emission-reduction goals. (See NYPSC Opens Resource Adequacy Proceeding.) Speaking to reporters after the meeting, Chatterjee declined to speculate what the PSC would do in response to FERC’s orders or how they would affect NYISO and the state’s joint effort to price carbon into the markets.

“In my view, today’s orders protect the competitiveness of New York ISO’s capacity market by addressing the price-distorting actions that could have unintended impacts on the future supply of electricity for consumers,” he said. “This is a technology-neutral, fuel-neutral approach to trying to protect the competitiveness of the capacity market.”

February 21, 2020

Feb. ERCOT TAC Meeting now a Webinar

ERCOT’s Technical Advisory Committee for this month will be conducted via a webinar rather than in-person, given the limited number of items to discuss.

TAC Chair Bob Helton has scheduled the online information session for 9:30 a.m. CT on Wednesday.

Committee members will be briefed on a change to the Resource Registration Glossary (RRGRR021) that adds new data requirements for dynamic models in the Transient Security Assessment Tool. The committee will vote by email on the urgent change request.

— Tom Kleckner