Page 1326 – RTO Insider

September 28, 2018May 8, 2025

Appeals Court Upholds NY Nuclear Subsidies

By Rich Heidorn Jr.

The 2nd U.S. Circuit Court of Appeals on Thursday upheld New York’s zero-emission credits (ZEC) for nuclear generation, rejecting claims they intrude on FERC jurisdiction (17 ‐26 5 4 ‐cv).

“We conclude that the ZEC program is not field preempted, because plaintiffs have failed to identify an impermissible ‘tether’ under Hughes v. Talen Energy Marketing between the ZEC program and wholesale market participation; that the ZEC program is not conflict preempted, because plaintiffs have failed to identify any clear damage to federal goals; and that plaintiffs lack Article III standing as to the dormant Commerce Clause claim.”

In upholding a district court’s dismissal of the complaint by the Electric Power Supply Association and others, the appellate court said its finding was “consistent” with the 7th Circuit’s Sept. 13 ruling upholding Illinois’ own ZEC program. (See 7th Circ u it Upholds Ill. ZEC Program.)

EPSA on Thursday as k e d the 7^th Circuit to rehear its ruling, alleging the court had made legal and factual errors. “The panel overlooked or misapprehended three key legal arguments under which appellants would prevail,” EPSA said.

Threading the Needle

The New York Public Service Commission created the ZEC program in August 2016 as part of its Clean Energy Standard (CES), which set a goal of reducing greenhouse gas emissions by 40% by 2030. The PSC said it crafted the program to avoid the issues behind the Supreme Court’s April 2016 ruling in Hughes v. Talen, which voided Maryland regulators’ contract with a natural gas plant as an intrusion into federal jurisdiction over wholesale power markets. (See NY Attempts t o Thread Legal Needle with Clean Energy Standard, Nuke Incentives.)

The court said that ZECs, like renewable energy credits (RECs), are certifications of an energy attribute separate from the purchase or sale of wholesale energy. Although the ZEC program “exerts downward pressure on wholesale electricity rates, that incidental effect is insufficient to state a claim for field preemption under the FPA [Federal Power Act],” the court said.

The court said the PSC avoided the defects of the Maryland contract for differences, which required the generator to participate in PJM’s capacity market.

“Plaintiffs point to nothing in the CES Order that requires the ZEC plants to participate in the wholesale market,” the court said. “ … As the district court concluded, a generator’s decision to sell power into the wholesale markets is a business decision that does not give rise to preemption concerns.”

“Until 2019, the ZEC price cannot vary from the social cost of carbon, as determined by a federal interagency workgroup. After 2019, the ZEC price is fixed for two‐year periods, and does not fluctuate during those periods to match the wholesale clearing price,” the court said.

The court also said the ZEC program was permissible under the dual federal/state regulatory system over electricity because it “does not cause clear damage to federal goals.”

The PSC approved the program to prevent the premature retirements of three New York nuclear power plants, Exelon’s FitzPatrick, Ginna and Nine Mile Point.

Nine Mile Point Nuclear Plant | Constellation Energy Nuclear Group

EPSA and the other plaintiffs — the Coalition for Competitive Electricity, Dynegy, Eastern Generation, NRG Energy, Roseton Generating and Selkirk Cogen Partners — claimed they were harmed because the ZEC program allows “favored New York power plants to prevail in interstate competition against” their generation by underbidding them in the wholesale electricity markets.

“If the PSC awarded ZECs in a non‐discriminatory manner to out‐of‐state nuclear plants (as it may do in the future under the terms of the CES order), there would be no abatement in the injury plaintiffs claim to suffer from the general market‐distorting effects of the ZEC program. In short, plaintiffs’ injuries ‘would continue to exist even if the [legislation] were cured’ of the alleged discrimination,” the court said. “Because plaintiffs’ asserted injuries are not traceable to the alleged discrimination against out‐of‐state entities, but (rather) arise from their production of energy using fuels that New York disfavors, they lack Article III standing to challenge the ZEC program.”

Win for RECs?

“The decision is a win for both ongoing state efforts to preserve existing nuclear plants — New Jersey regulators expect to finalize a ZEC program by the end of the year — and long-standing renewable energy policies,” said Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School. “The panel held that renewable energy credits (RECs), instruments that are used for compliance with renewable portfolio standards, are legally indistinguishable from ZECs. Today’s decision thus implicitly concludes that RECs are not preempted under the FPA, an issue which no court has ever squarely addressed.”

September 28, 2018

CAISO Seeks to Extend Aliso Canyon Rules

By Hudson Sangree

CAISO is seeking to extend measures for another year that deal with the continuing threat to electrical reliability posed by limited operations at the Aliso Canyon natural gas storage facility, where a massive release of methane occurred in October 2015.

CAISO is seeking expedited approval from FERC to renew the temporary tariff provisions, which were first put in place in June 2016 and then subsequently refined and extended. (See CAISO Board Aliso Canyon Rules Package.)

CAISO is seeking to extend for another year interim market measures designed to deal with gas supply restrictions at the damaged Aliso Canyon facility. | *California Governor’s Office of Emergency Services*

“Our hope is to be able to keep these measures in place for another 12 months,” Anna McKenna, an assistant general counsel for the ISO, said in a conference call with stakeholders Tuesday.

The provisions include a measure allowing the ISO to enforce constraints on the maximum amount of natural gas that can be burned by gas-fired plants in the areas served by the Southern California Gas and San Diego Gas & Electric. The constraints would be based on limited supply anticipated by CAISO during specific hours.

The provisions also allow CAISO to suspend or limit the ability of scheduling coordinators to submit virtual bids if it’s determined virtual bidding could undermine reliability or grid operations.

Similar provisions have been in place for the past two years to prevent blackouts or grid disruptions caused by the natural gas supply in Southern California being over-taxed.

The current proposal, called Phase 4, would extend the temporary provisions now in place for another year beyond Nov. 30 and Dec. 16, when they are set to expire.

CAISO planned to file its proposal with FERC by Thursday and ask for a 60-day turnaround so the new restrictions are in place when the first set of rules expires at the end of November.

Before the 2015 blowout, Aliso Canyon was the state’s largest natural gas reservoir, and its damaged status poses challenges to generators and regulators alike.

Despite objections from local residents and Los Angeles County officials, SoCalGas resumed injections into the facility in July 2017 to comply with a state directive to maintain sufficient gas inventories to support reliability on the region’s gas and electric systems. (See CPUC OKs Temporary Increase in Aliso Canyon Injections.)

September 27, 2018

Illinois: End PJM Capacity Market?

By Rory D. Sweeney

Illinois regulators last week suggested PJM consider ending its capacity market if it continues supporting policies that the state believes discount its generation preferences. [Editor’s Note: An earlier version of this story incorrectly stated that regulators had threatened to leave the RTO.]

The Illinois Commerce Commission convened a Sept. 20 hearing on PJM’s capacity market three weeks before a deadline to respond to a FERC order that rejected both of the RTO’s proposals for revising its capacity market, which sparked a rush to develop alternatives. (See FERC Orders PJM Capacity Market Revamp.)

Panelists speak at the Illinois Commerce Commission’s hearing on PJM’s capacity market last week. | © *RTO Insider*

While several proposals emerged, including one supported by the Illinois Citizens Utility Board, PJM has maintained support for its own plan, which would pair an expanded minimum offer price rule (MOPR) with a two-stage auction that removes subsidized resources and reprices the results.

Already well aware of Illinois’ grievances, PJM staff attending the hearing attempted to explain the RTO’s position.

“We are really trying to make this work,” PJM’s Darlene Phillips said. “We recognize that Illinois and other states have the right to make decisions. We are not trying to fight against those decisions. We are trying to make sure that, at the end of the day, our markets work for the entire region. There are other states that aren’t making those decisions … [and their generators] don’t have the luxury of getting an out-of-market payment.”

Another Way?

PJM’s assurances didn’t sway either the ICC commissioners or the other panelists, largely made up of either environmental advocates or representatives of Exelon, which has two nuclear facilities in Illinois benefiting from a 2016 state law that subsidizes the units with state-funded zero-emission credits. The 7th U.S. Circuit Court of Appeals recently upheld the state’s right to provide the funding.

“What if we throw this capacity market out?” ICC Commissioner John Rosales asked, noting that FERC had already ruled the market unjust. “There’s some rationale we can do it another way.”

PJM MOPR capacity market Illinois Commerce Commission — Panelists speak at the Illinois Commerce Commission’s hearing on PJM’s capacity market last week. | © *RTO Insider*

He pointed to ERCOT, which doesn’t have a capacity market.

“Is that an option? … Is there something else that we can do? Because the amount of money is uneconomical,” he said. “That’s a lot of money that’s invested in a reserve market that doesn’t seem to be needed most of the periods throughout the year,” Rosales continued. “Understand, there’s times that we’re going to need some help, but you get that [help] from others.”

Jen Tribulski, a PJM attorney, suggested that FERC didn’t intend to do away with PJM’s “capacity market as a whole,” but sought to improve how the market deals with out-of-market payments.

The disagreement came over what is considered a subsidy. Phillips said that “we have to draw a line somewhere. This is not easy.”

However, opponents argued PJM has larger market distortions to address.

“Regulated utilities have the ability to subsidize all of their generation with ratepayer funding, so if you’re going to talk about a market without subsidies, you’ve got to really relook at the whole market. It’s the single biggest market distortion that there is,” said Rob Kelter of the Environmental Law & Policy Center. “When you consider the cost of energy and you don’t consider the cost of environmental externalities, you are creating the biggest distortion you could possibly create. Coal and natural gas pollute.”

“Right now, the proposal on the table is to artificially raise the prices that consumers would be paying to preserve the supremacy of the capacity market,” said Andrew Barbeau of The Accelerate Group. “There’s a certain fealty to the capacity market that we’ve seen in recent years … to use the capacity market to start serving other purposes. It’s always been there to serve as this insurance product. Consumers are paying more and we’re getting less for it, and it’s kind of violating what residents of the state have been pretty consistently demanding, which is that the power be cheaper and cleaner.”

‘Fundamental Disconnect’

Phillips said the market “is doing what it was meant to do when it was put in place” to produce “reliability at the least cost,” but that it didn’t contemplate environmental concerns. She added that she was “not saying there’s not room for improvement.”

“That’s something that states can get together and have a discussion about” in creating a market-based proposal, she said. “You’re getting reliability. You’re getting assurances, not insurance, [but] assurances that three years from our market, three years forward, that we have enough capacity online to make sure the energy needs during that period are met.”

ICC Chairman Brien Sheahan said there is a “fundamental disconnect in PJM’s conception of what ‘accommodate’ is and what ‘mitigate’ is.”

PJM says its proposal accommodates states’ policy decisions, but states argue it instead mitigates their efforts to sponsor preferred technologies.

“You can’t just start doing this kind of line drawing,” he said. “And the end result, I predict, will be if they don’t accommodate, then the states are going to find alternatives. … Legislatures and governors in states that care about climate change and care about environmental policy are not going to bow to how [PJM thinks] they should work.”

ICC Manager Randy Rismiller suggested moving away from capacity markets altogether.

“Energy and ancillary services markets historically have worked quite well. They haven’t been as contentious as capacity markets. This sort of gradual gravitation away from capacity might be a way out of these constant conundrums,” he said.

CUB’s Kristin Munsch urged PJM to “stop trying to separate us, but integrate our preferences into the market.”

“I think PJM in recent years has begun to adjust the construct, a market that we thought was working well, to one that’s no longer reflecting what I think consumers are looking for,” she said.

September 27, 2018

CAISO Finalizes Draft TAC Proposal

By Hudson Sangree

CAISO moved closer this week to updating its transmission access charge (TAC) structure to include new rules about how to measure transmission usage.

Stakeholders discussed the final draft proposal Monday at CAISO headquarters in Folsom, Calif., with participants also joining by telephone.

The proposed rules are intended to more accurately allocate transmission costs based on current grid conditions to achieve greater efficiency and cost-effectiveness, the ISO contends.

Power lines in Contra Costa County, California | *USDA*

In particular, the rules would change the current volumetric TAC to a hybrid one that uses historic peak demand data instead of forecasted data.

“It’s kind of a balance we’re trying to strike here,” Chris Devon, CAISO market and infrastructure policy developer, told stakeholders.

The volumetric-only approach is no longer appropriate because of a changing grid, most notably the rise of distributed generation and other distributed energy resources, the ISO and many stakeholders contend. The hybrid approach would help adjust for this new reality so that transmission owners can better recover the costs of building, maintaining and operating transmission facilities, proponents said.

“The proposed hybrid approach is an improvement over the current TAC structure,” the ISO said in its presentation Monday. “[It] captures both volumetric and peak demand functions and reliability benefits provided by the system.”

Planning for the revisions started in April 2017 and has included several stakeholder meetings. The initial straw proposal went through two revisions, with some of the more controversial proposals modified or rejected.

CAISO recently backed off a proposed provision that would have moved the point of measurement for transmission usage away from the end-use customer’s meter to the interface between the transmission and distribution systems to better reflect increased customer reliance on resources directly connected to the distribution network, such as rooftop solar.

“The ISO is willing to revisit the point-of-measurement issue — for purposes of prospectively allocating the costs of future transmission facilities — if state policymakers and regulatory authorities, after careful consideration of the merits and implementation issues, support retail rate changes that provide a transmission cost credit (i.e., relief from retail rate charges for certain new transmission facilities) to load-serving entities that have procured distributed generation resources,” the ISO wrote in the proposal.

The TAC plan still has a way to go before it could be implemented.

A final proposal will likely be submitted to the ISO Board of Governors in the first half of 2019, with board approval coming later next year.

It would then have to be submitted to FERC, with implementation occurring no sooner than 2021 or 2022, according to CAISO planners.

The grid operator previously developed a proposal to allocate transmission costs over an expanded balancing area if the ISO integrates new members from other areas of the West. (See CAISO Floats Latest Cost Allocation Plan for Expanded Balancing Area.) That proposal has been shelved until CAISO expands into other regions.

September 26, 2018

New England Senators Urge FERC to End Press Ban

Six New England senators urged FERC Tuesday to end the New England Power Pool’s ban on public and press attendance at stakeholder meetings.

U.S. Sens. Sheldon Whitehouse (D-R.I.), Jack Reed (D-R.I.), Ed Markey (D-Mass.), Elizabeth Warren (D-Mass.) and Jeanne Shaheen (D-N.H.) joined Sen. Richard Blumenthal (D-Conn.) in a letter urging FERC to reject NEPOOL’s proposal to codify its longstanding closed door policy (ER18-2208).

NEPOOL FERC Order 719 press ban — Richard Blumenthal | *Richard Blumenthal*

“Residents of New England pay some of the highest electricity rates across the country,” the senators said. “Consumers deserve to be aware of the important decisions that are made that affect their household energy bills and the environment. Such decisions should be transparent and subject to public scrutiny.”

The senators dismissed NEPOOL’s argument that allowing press access would hurt the ability of NEPOOL members to talk candidly, calling it “a claim that is neither supported nor justified. In New England and around the country, it is essential that the deliberation process be kept open to all who are affected by these decisions.”

New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.

“Although NEPOOL does publicly release documents, including meeting minutes and official records, both in advance and after meetings take place, this cannot be considered a substitute for membership,” the senators said.

They warned that approval of NEPOOL’s proposal “could have significant impact on and set precedent for stakeholder participation in electricity market entities, and not only in New England. Formal exclusion of stakeholders from decision-making in NEPOOL would be in stark contrast to FERC Order 719, which sought to increase and not hinder responsiveness to stakeholders across all RTOs.”

FERC NEPOOL press ban order 719 — FERC commissioners testifying before the Senate Energy and Natural Resources Committee in June. | © *RTO Insider*

On Sept. 18, a dozen members of the House of Representatives also called on the commission to open the meetings.

Their letter was signed by Rep. Frank Pallone (D-N.J.), the ranking member of the House Energy and Commerce Committee; Rep. Fred Upton (R-Mich.), the chairman of the committee’s Subcommittee on Energy; Rep. Bobby Rush (D-Ill.), the ranking member on the subcommittee; seven of nine members from Massachusetts’ delegation; and one representative each from Rhode Island and Vermont.

Last week, NEPOOL filed a motion to dismiss RTO Insider’s protest seeking to open the meetings, saying FERC lacks jurisdiction to force changes (EL18-196). Other intervenors supported RTO Insider’s request that FERC either force a NEPOOL rule change or strip it of its role as ISO-NE’s stakeholder body. (See NEPOOL: FERC Can’t Change Press, Public Ban.)

— Rich Heidorn Jr.

September 26, 2018

ERCOT: Market Performed ‘as Expected’ During Summer Heat

By Tom Kleckner

ERCOT said an “exceptional” response by generators and a lack of extreme temperatures helped it meet record demand this summer without issuing alerts or calling for conservation measures.

ERCOT’s summer performance review said the wholesale market “performed as expected,” with generators responding to higher price signals and making their units available during peak demand periods. It noted the market “is designed to provide financial incentives to encourage market participants to respond appropriately” under tight operating conditions.

The ISO, which manages 90% of the state’s grid, set a new system demand peak of 73.3 GW on July 19, more than 2 GW higher than the previous record set in August 2016. The record high was one of 14 set during the lone period of extreme heat this summer (July 18-23).

Hourly Average Demand, Capacity, and Reserves on 7/19/2018 | *Ercot*

ERCOT also set a new weekend peak demand of 71.4 GW on July 22.

The summer — which ends Sept. 30 for ERCOT — was the fifth hottest on record across Texas. However, high temperatures were “not as significant or as sustained” as they were during the 2011 record-setter, the ISO said. Temperatures averaged 86.7 degrees F during the summer, with Austin recording 90 days over 100 and Dallas 71 (including 40 consecutive).

Real-time system-wide wholesale prices ranged from $33/MWh to $47/MWh between June and August, with a high of $3,125/MWh on June 5. The highest system-wide price for a single settlement interval during July’s extreme weather came on July 18, when prices hit $2,169/MWh.

The highest system-wide day-ahead price was $2,062/MWh on July 23.

The ISO had fewer reliability unit commitments in 2018 compared to last year because market participants made their units available during tight system conditions, according to the review.

Generation outages were also half of what was projected in ERCOT’s final seasonal assessment in April, the grid operator said. (See ERCOT Gains Additional Capacity to Meet Summer Demand.) Outages and de-rates totaled a little over 2 GW during the July 19 peak.

ERCOT entered the summer with a planning reserve margin of 11%, almost half of that in previous years. The tightest operating conditions came on Aug. 18, when two large generators tripped, one just before the day’s peak. The ISO relied on operating reserves to meet demand “with no reliability concerns.”

ERCOT filed the report and accompanying data on Monday afternoon with the Texas Public Utility Commission, which has opened a docket on the summer’s market performance (Project 48511).

The ISO’s staff will also share their findings with stakeholders during the Technical Advisory Committee on Wednesday and the Board of Directors on Oct. 9.

September 24, 2018

MISO Board of Directors Briefs: Sept. 20, 2018

CARMEL, Ind. — MISO will next week begin conducting the election for three open seats on its Board of Directors.

miso nominating committee budget — Nancy Lange | © *RTO Insider*

The RTO’s Nominating Committee has settled on incumbents Phyllis Currie and Mark Johnson along with Minnesota Public Utilities Commission Chair Nancy Lange. If Lange earns enough of the vote, she will replace outgoing Chairman Michael Curran, who has reached the three-term limit.

Before being formally selected by MISO’s Nominating Committee, Currie was elected as chair for 2019. (See MISO Board Selects Currie as New Chair.)

Madison Gas and Electric’s Megan Wisersky, who holds one of two stakeholder seats on the Nominating Committee, said the committee narrowed a pool of about 30 candidates to two candidates for each of the three open seats, including those held by Currie and Johnson. MISO turned to management firm Russell Reynolds for help assembling a candidate pool.

“The quality of the candidates was exceptional,” Nominating Committee member and Director Baljit Dail said.

“We look forward to another newbie,” Curran added.

MISO Senior Vice President and Secretary Stephen Kozey said polls will be open Sept. 27 to Nov. 2, with a quorum representing 25% of MISO voting members (at least 35 members). Candidates must receive a majority of member support after quorum to be placed on the board. For each candidate listed on the ballot, MISO members can vote “for,” “against” or “withhold.”

“Should a member fail to collect a majority of the voting, the Nominating Committee process would begin all over again,” Kozey said.

MISO membership will also vote during that time on whether to increase the board’s compensation beginning in 2019. The board, after consulting with Russell Reynolds, voted to give itself a $7,000 raise for all directors, raising the current base retainer from $89,000 to $96,000 per year. Currently, directors are paid $116,000, committee chairs get $124,000 and the board chair gets $131,000. The last director pay increase took place in 2016. (See Board OKs Pay Hike, Change to Independence Rules.) The board also voted to increase the chairman’s stipend from $15,000 to $20,000 in 2019.

Curran said increases to director compensation would be frozen for two years should the increase take effect.

Kozey said under MISO’s Transmission Owners Agreement and bylaws, it would take at least two-thirds of the quorum of voting RTO members to reject the compensation increase.

Board election and compensation results will be announced at the Dec. 6 board meeting in Carmel, Ind.

MISO Spending Closely Tracks 2018 Limit; RTO Ups 2019 Budget

After earlier forecasts of a small year-end overage, MISO is now on track to be $1.2 million under its $265 million expected budget in December.

MISO Chief Financial Officer Melissa Brown said the savings are primarily attributed to delays in planned investments.

The RTO is likewise expected to come in under its capital expense budget, likely spending $28.8 million of the allotted $29.6 million. The decrease comes from deferring some vendor work on its market platform replacement and reclassifying other capital expenses as operating expenses.

MISO staff are proposing a $269.6 million operating budget for 2019, a $4.7 million increase over last year. The RTO, however, is planning for a smaller capital budget, at $27.2 million.

The 2019 budgets include $81.2 million in both operating and capital spending on technology.

The total 2019 budget includes $20.5 million of spending on MISO’s market platform replacement project, broken down into $10.7 million in capital expenses, $4.2 million in operating expenses and $5.6 million dedicated to the salaries and benefits of staff working on the project.

MISO leadership said it will reveal in late 2019 its chosen vendor to construct the new platform. In June, the RTO said preliminary vendor General Electric was months behind schedule on developing the platform, especially on the complex software needed to clear the day-ahead market. (See MISO Platform Replacement Risks Delay, Budget Overrun.)

Curran asked that MISO provide the board updates on its preferred vendor and reasoning before releasing the information next year.

MISO Reviewing FTR Process

After PJM experienced a major default in its financial transmission rights market, MISO is ramping up an ongoing review of its own FTR market.

Officials said they began the review in 2017 and will continue to look for any weaknesses in its process. The evaluation is expected to extend into next year, and MISO said it plans to bring results of the evaluation to stakeholders.

Brown said staff are looking at other RTOs’ practices to identify the best combination of procedures.

FERC filings indicate PJM’s financial fallout from the incident that began with GreenHat Energy’s $1.2 million FTR default might become as high as $110 million. (See PJM Reeling from Major FTR Default.)

But MISO last week said its FTR market differs from PJM’s in one key way that may protect it against a significant default: MISO does not net auction bid prices with estimated congestion credit value. MISO said the netting difference results in a conservative credit calculation and higher collateral, preventing “thinly capitalized” parties from buying large portfolios.

“We believe this is a key component for minimizing the magnitude of a default,” MISO said.

Brown said bid prices in MISO are required to be collateralized.

“So you’ve got to bring the cash to play the game,” she told the board.

MISO also said it limits FTR terms to one year, while PJM allows rights for up to four years. It additionally pointed out that it estimates the value of transmission congestion more frequently than PJM, updating congestion estimates monthly rather than once per year.

In response to a question from Director Barbara Krumsiek about whether GreenHat could resurface to apply to operate in MISO, Brown said the screening process for credit worthiness would most likely exclude it early in the process.

Directors asked if there was a downside to being more conservative in its FTR market requirements.

Brown said MISO’s collateral requirment protects the membership class, not MISO, because the costs of a default would be passed on to members.

“I’m on the conservative side, just so we’re clear,” Director Currie said.

Director Thomas Rainwater said it appeared that MISO’s credit policy hasn’t diminished “robust” FTR market activity.

— Amanda Durish Cook

September 24, 2018

ISO-NE Asks FERC to End Clear River CSO

By Michael Kuser

ISO-NE on Thursday asked FERC to terminate the capacity supply obligation of Invenergy’s delayed 485-MW Clear River Energy Center Unit 1 combined cycle plant in Burrillville, R.I. (ER18-2457).

The RTO said it was exercising its right to terminate the CSO because the plant will not be operating in time for the beginning of the capacity commitment year beginning June 1, 2019.

iso ne cso invenergy clear river energy center unit 1 — Clear River Energy Center Rendering | *Invenergy*

Unit 1 obtained the CSO in Forward Capacity Auction 10, held in February 2016, but its commercial operation date is now scheduled later than June 1, 2021. Invenergy has covered the plant’s CSO for the capacity commitment periods beginning in 2019 and 2020.

Chicago-based Invenergy has been attempting since 2015 to get a construction permit for the plant from the Rhode Island Energy Facilities Siting Board (Docket No. SB-2015-06), a process delayed by opposition to the plant itself, the environmental sensitivity of the proposed site and the developer’s plans to secure extra water for operations.

On Sept. 21, the town of Burrillville asked the siting board to reject the advisory opinion submitted by the state’s Public Utilities Commission in favor of the project. Town Manager Michael C. Wood posted news of the RTO’s termination filing on the town’s website: “No doubt this is a big setback for Invenergy. Burrillville will thoroughly evaluate this action by ISO-NE, but we are not underestimating Invenergy.”

Last November, ISO-NE barred Unit 2 from offering into February 2018’s FCA 12 because of the permitting delays. (See ISO-NE Bars Invenergy Plant from FCA 12.)

If the commission accepts ISO-NE’s filing, the RTO said it “will terminate the CSO, draw down the financial assurance that Invenergy provided for Clear River Unit 1’s CSO and will remove the resource’s qualified capacity, which will render it ineligible to participate in the upcoming FCA 13 to be held in February 2019.”

FERC in January accepted an unexecuted large generator interconnection agreement filed by ISO-NE and National Grid for Clear River. (See FERC Accepts Disputed GIA for Rhode Island Generator.)

The RTO asked the commission to issue an order within 60 days of its filing, arguing that the grid operator and market participants “need certainty on the status of this resource” prior to FCA 13.

September 24, 2018

Overheard at ISO-NE Consumer Liaison Group Meeting

By Michael Kuser

WINDSOR LOCKS, Conn. — Climate change and the key role of heating and cooling improvements for energy efficiency were the hot topics of discussion among consumer advocates, state regulators and industry professionals attending a meeting of ISO-NE’s Consumer Liaison Group on Thursday.

iso ne consumer liaison group climate change — Attendees at the ISO-NE CLG | © *RTO Insider*

Combined residential, commercial and industrial building heating accounts for about 40% of CO₂ emissions in New England, followed by transportation at about 35% and the electric sector at 23%.

“Those are the big three wedges when you want to actually achieve the economy-wide greenhouse gas goals that we now have in statute,” said Commissioner Robert Klee of Connecticut’s Department of Energy and Environmental Protection.

The state’s Global Warming Solutions Act calls for reducing GHG emissions to 10% below 1990 levels by January 2020 and 80% below 2001 levels by 2050, and it was recently amended to reduce emissions to 45% below 2001 levels by 2030.

The state’s renewable portfolio standard and the Regional Greenhouse Gas Initiative have driven down emissions, “and Connecticut has just doubled down on that with legislation to make our RPS 40% Class I renewables by 2030,” Klee said.

The “new normal” of stronger and more frequent storms is also a challenge for planners and predictors, Klee said. “Those storms would normally happen years or decades apart, but Eversource [Energy] reported in a period of 16 months having four of the company’s 10 most devastating storms ever … [which] translates into [affecting] our rates and how much we’re all going to be paying for this.”

Heating and Cooling

Joseph Rosenthal, principal attorney for Connecticut’s Office of Consumer Counsel, moderated a panel on electrification of heating.

From 2013 to 2015, the state was promoting the use of natural gas “to find the right parameters to give consumers choice about whether to stay with oil or switch to natural gas and what kind of subsidization we would offer for that,” Rosenthal said.

Now Connecticut is moving into a new phase, talking about electrifying of the heating sector, he said.

DEEP Deputy Commissioner for Energy Mary Sotos said climate change drives the move to electrify heating to reduce GHG emissions, but the use of lower carbon content biofuels also provides opportunities to improve energy efficiency.

“One limitation on reaching the state’s GHG emissions target is how we measure biofuel,” Sotos said, noting that the advantages of biofuel lie in reduced emissions over the lifecycle, while the EPA tools her state uses only reduce emissions at the point of combustion.

“In the near term, unless we change those methodologies significantly, we wouldn’t necessarily get to claim credit for any changes made there,” she said.

Sotos’ remarks set the table for Chris Herb, president of the Connecticut Energy Marketers Association, a statewide group of fuel oil dealers, who said, “Forget everything you think you know about heating oil.”

On July 1, all New England states mandated the use of ultra-low sulfur heating oil, with a maximum sulfur content of 15 ppm, a 97% reduction from the previous standard, he said. The new fuels, mixed with 7% biodiesel on average, mean particulate emissions are reduced by 80%, nitrous oxide by 10% and CO₂ by 2%.

With biodiesel added, heating oil is no longer the fuel that people are used to, Herb said.

“It’s cleaner than natural gas,” Herb said, showing a slide comparing the 20-year atmospheric lifecycles of natural gas versus ultra-low sulfur heating oil, which his trade group is trying to rebrand as “Bioheat.”

Heat Pumps

Ronald Araujo, energy efficiency manager for Eversource, said heat pumps provide excellent benefits, given the right situation.

“Ground source heat pumps are very efficient,” Araujo said. “It doesn’t generate heat — it moves heat from place to place — but one disadvantage is it needs some external source to work with.”

Ground source heat pumps are more efficient than air source heat pumps because the temperature of the ground is relatively stable (about 50 degrees Fahrenheit), while the air temperature in New England can range from below zero to 100 with high humidity, either of which compromise efficiency.

“The reason heat pumps are so important is that they reduce emissions. They reduce emissions today, and they will also do it as the electricity sector continues to get cleaner,” said Emily Lewis O’Brien, Acadia Center senior policy analyst. “This is an important part of the equation … but you can’t do it with heat pumps alone.”

O’Brien emphasized that in order to meet renewable energy goals, it would be relatively “simple” to bring all six states in New England, plus New York, into matching best practices in every area, from electric vehicle promotion, to solar development, to heating electrification and energy efficiency.

“And it’s important to align state incentive programs across the region, to make sure we’re all swimming in the same direction,” O’Brien said.

Fuel Security

Anne George, ISO-NE vice president for external affairs, highlighted recent developments at the RTO, particularly regarding fuel security and the issue of the difficulty of obtaining natural gas supplies during the region’s winter peak.

FERC in July tentatively accepted a cost-of-service agreement between ISO-NE and Exelon for Mystic Generating Station Units 8 and 9, ordering an expedited hearing process on unresolved issues related to cost justification (ER18-1639). The agreement would allow the gas-fired units in Massachusetts an annual fixed revenue requirement of almost $219 million for capacity commitment period 2022/23 and nearly $187 million for 2023/24. (See FERC Advances Mystic Cost-of-Service Agreement.)

“They did agree with how we were approaching the fuel security risk analysis, but they did not go along with us doing this outside of our typical Tariff language,” George said.

Elizabeth Mahony, of the Massachusetts attorney general’s office, spoke for her boss, Deputy Chief of the Energy and Environment Bureau — and CLG Coordinating Committee Chair — Rebecca Tepper, who was busy dealing with issues related to the multiple gas line explosions in the Merrimack Valley near Boston the previous week.

Mahony highlighted the election of a new Coordinating Committee at the next CLG meeting, to be held in Boston on Dec. 6. “Any CLG member who is an electricity end user, or directly represents ratepayers, or is a member of a consumer organization, or is a government consumer or ratepayer advocate is eligible to serve on the Coordinating Committee,” she said.

September 24, 2018

FERC Tells LEAPS to Get in Line

By Hudson Sangree

FERC on Thursday rejected a request by developers of a proposed $2 billion pumped storage project for a declaratory order entitling it to cost-based rate recovery as a transmission asset in CAISO.

The commission sided with CAISO and the California Public Utilities Commission, which had argued that Nevada Hydro’s petition for its Lake Elsinore Advanced Pumped Storage (LEAPS) project was an end run around the ISO’s transmission planning process (TPP) (EL18-131).

ferc caiso pumped hydro leaps — Lake Elsinore | *City of Lake Elsinore*

“We dismiss Nevada Hydro’s petition and find that a request to designate LEAPS as a transmission facility is premature at this time,” FERC wrote. “LEAPS has not been studied in the CAISO TPP to determine whether it addresses a transmission need identified through that process, and, if such a need were met, how the facility would be operated. Absent such information, the commission cannot make a reasoned decision on whether LEAPS is a transmission project and thus eligible for cost recovery under the [transmission access charge].”

CAISO said FERC should not accept Nevada Hydro’s analysis that LEAPS is a cost-effective solution to transmission planning needs, noting that the company’s benefits study relied heavily on revenues from market-based services such as energy market sales, regulation, load following, capacity, spinning and ramping. The CPUC said it is unlikely that pumped storage will be the most cost-efficient means of meeting reliability, grid integration or greenhouse gas reduction targets between now and 2030.

Nevada Hydro cited FERC’s Western Grid ruling and its 2017 policy statement in seeking the project’s classification as a transmission asset. (See Storage Can Earn Cost- and Market-Based Rates, FERC Says.)

The $2 billion LEAPS project, which entered CAISO’s interconnection queue in 2005, has had a long and controversial history, with local governments and many residents opposed to its construction on the natural 3,000-acre Lake Elsinore, adjacent to the Cleveland National Forest in Southern California’s Riverside County.

This is the second time Nevada Hydro has failed to obtain FERC approval to advance the project. In the 2008 Nevada Hydro case, the commission rejected a request that CAISO assume operational control over the facility and found that the developers failed to show why it should be treated differently from other pumped hydro facilities that had not been granted rolled-in transmission pricing.

In seeking the declaratory order, Nevada Hydro said it, not CAISO, would maintain operational responsibility for LEAPS.

But the commission said that change did not entitle the project to circumvent the ISO’s planning process.

“Requiring LEAPS to be reviewed through the CAISO TPP is consistent with the commission’s policy that regional transmission planning processes should identify transmission needs and solutions in a coordinated, nondiscriminatory process that is open to all interested stakeholders,” the commission said. “We note that CAISO has committed to studying LEAPS as a transmission proposal, both as a means to address reliability needs (if it is submitted in an appropriate request window of CAISO’s TPP and if the proposal specifies the CAISO-identified reliability constraints the project could mitigate), and as an economic planning study request.”

The project would include 500-MW of pumped storage, the Talega-Escondido/Valley-Serrano 500-kV Interconnect and a 30-mile line to transmission systems owned by Southern California Edison and San Diego Gas & Electric. Its hydroelectric license application is pending before FERC (P-14227-003).