November 1, 2024

NYISO Management Committee Briefs

RENSSELAER, N.Y. — NYISO and adjacent grids will likely be able to serve load throughout summer based on historical performance of generation and transmission infrastructure, the ISO reported last week.

However, an unlikely scenario of extreme heat could pose challenges for system capacity reserves, if not the system itself, according to the ISO’s Summer 2017 Capacity Assessment.

Under a baseline scenario in which this summer’s load peaks at 33,178 MW, NYISO expects to have a capacity margin of 386 MW, down 746 MW from the 2016 baseline forecast. The positive margin represents the amount of surplus generation available after factoring in peak load plus a required 2,620 MW of operating reserves.

Under extreme weather conditions — the 90th percentile forecast — the ISO predicts a capacity shortfall of 1,924 MW, compared with a 1,191-MW shortfall in last summer’s forecast.

“That’s taking the 90th percentile peak forecast, which is a very large peak, adding 2,620 of reserve requirement, saying that’s the requirement on a day-ahead basis, and then comparing it to that available capacity,” Wes Yeomans, NYISO vice president of operations, said during a May 31 meeting of the Management Committee.

Despite the expected deficiency under those conditions, the ISO expects it could avoid involuntary load curtailments by relying on up to 3,083 MW of demand resources available under emergency procedures.

NYISO activated demand response during its all-time summer peak of 33,956 MW in July 2013, which would have hit 34,900 MW without DR, Yeomans said.

NYISO Management Committee regulated transmission
| NYISO

Yeomans explained that the 90th percentile projection slightly exceeds NYISO’s all-time high. For an extreme heatwave, the capacity requirement would reach 38,000 MW.

“If we compare that against the capacity resources assuming 4,800 MW of derates — and we may or may not have that amount in a very hot heatwave — on paper we would be short on capacity by about 1,900 MW … but we have at least 3,000 MW of emergency operating procedures we would activate to make up that difference,” he said. (See New York Geared for 2017 Summer Load.)

MC Approves Funding 2nd PAR at Ramapo

The Management Committee approved a Tariff modification to fund Consolidated Edison’s replacement and operation of the Ramapo 3500 phase angle regulator, destroyed in a fire last June, as well as the operating expenses for the existing PAR at the substation close to the New Jersey border. The estimated $5.5 million in annual costs will be allocated statewide across all New York load-serving entities, but they would be reimbursed with any monies eventually paid by PJM, PJM transmission owners or refunded by Con Ed.

Mark Younger of Hudson Energy Economics asked for a definite commitment from either Con Ed or NYISO on the timeline for installation.

Jane Quinn of Con Ed said that upon an affirmative vote, the company will begin moving the PAR into place, which should take three to four weeks. Installation should take an additional eight to 10 weeks.

“We anticipate having the PAR, absent contingencies, in place on or around September 15,” Quinn said. (See “Con Edison Gets Approval to Install 2nd PAR at Ramapo,” NYISO Business Issues Committee Briefs.)

Market Participants to Review Monitor’s Performance

Shaun Johnson, NYISO director of market mitigation, asked market participants to join in an annual review of the Market Monitoring Unit’s performance.

NYISO last year signed a three-year contract with Potomac Economics to perform monitoring functions through March 31, 2019. The MMU’s duties include ensuring that the markets administered by NYISO function efficiently and appropriately, as well as identifying market violations, market design flaws and market power abuses. The Monitor also produces annual and quarterly State of the Market reports assessing the performance of the New York electrical markets.

The budget for the MMU for 2017 is $3.5 million, up $400,000 over last year. Most of the additional costs cover additional work related to cybersecurity and new requirements mandated by reliability-must-run and FERC Order 1000 filings.

One participant said that Potomac sometimes shows up at FERC and protests what NYISO is doing.

“Something just seems at odds there, that we’re paying a company $3.5 million a year and we’re fighting with them at FERC,” he said.

Such action is part of the duties of an MMU, according to NYISO, and one thing FERC cited in a recent review of the SPP Monitor was the lack of reporting on disagreements with the grid operator.

Tariff Changes on Tx Cost Recovery

The Management Committee approved proposed Tariff revisions to add a mechanism to recover and remit costs associated with regulated transmission projects eligible under the ISO’s Congestion Assessment and Resource Integration Study or the public policy transmission planning process. Following board approval in July, the revisions to the cost recovery mechanism for regulated transmission projects under Rate Schedule 10 — and related amendments to the Tariff’s Attachment Y — would be filed with FERC under Section 205 of the Federal Power Act.

The Rate Schedule 10 revisions establish a new regulated transmission facilities charge (RTFC) to LSEs, with payments allocated to developers of such projects.

John P. Buechler, NYISO regulatory policy adviser, said the revisions do not in any way “affect or change the cost allocation provisions, which, relevant to our transmission planning process, are in Attachment Y, Section 31.5.”

Eligible projects include:

  • Regulated backstop transmission solutions proposed by a responsible transmission owner;
  • An alternative solution NYISO selects as a more efficient or cost-effective solution to a reliability need;
  • A regulated transmission gap solution proposed by a responsible TO;
  • An alternative regulated transmission gap solution determined by an appropriate state regulatory agency;
  • An approved regulated economic transmission project;
  • A public policy transmission project selected by NYISO;
  • Costs incurred by a developer in preparing a proposed transmission solution in response to a request by the Public Service Commission or Long Island Power Authority; and
  • The portion of an interregional transmission project selected by NYISO in the Comprehensive System Planning Process that is allocated to the NYISO region.

NYISO will calculate and bill an RTFC separately for each eligible project.

NYISO to Enhance Buyer-side Mitigation

The committee approved proposed Market Services Tariff changes to improve inflation forecasting and how mothballed units are treated in the capacity and energy forecast used to make buyer-side mitigation determinations.

The committee recommended that the Board of Directors authorize revisions to buyer-side mitigation rules in the Market Services Tariff, which would then be filed with FERC under Section 205 of the Federal Power Act.

In FERC docket ER13-1380, filed in 2013 to create NYISO’s G-J locality, the commission determined that such an enhancement was outside the scope of the docket but encouraged the ISO to work with stakeholders on the issue.

NYISO analyst Lorenzo Seirup presented the rationale for mitigation enhancements and said that, since the topic first arose in 2013, “we discussed this ad nauseam and also had a vote that failed and then a vote that passed — that’s the 30-second highlights.”

The proposal would include in the forecasts existing units as well as additional units, “which is the more complicated” category, Seirup said. Units that would be excluded are those transferring their capacity resource interconnection service (CRIS) or that have expired CRIS.

Additional units include mothballed facilities, units under forced outages, retired units and those in similar condition with unforced capacity deliverability rights. These additional units either must have CRIS or show positive indicators of repair or have a new present value greater than $0 in the “inclusion test” performed for resources that have the ability to re-enter the market under more favorable conditions.

The Tariff changes on inflation would call for use of the most recently published 10-year inflation projections from the Survey of Professional Forecasters, or if no longer available, a similar source to identify net cost of new entry projected for the mitigation study period, and the price on the installed capacity demand curve projected for such a period.

Michael Kuser

SPP Advances KCPL Cost Shift Proposal

By Tom Kleckner

DALLAS — SPP’s Strategic Planning Committee last week ended more than nine months of discussion on cost shifts within existing transmission pricing zones, agreeing unanimously to let the Markets and Operations Policy Committee take up the issue when it meets in July.

The agreement represented a victory of sorts for Kansas City Power & Light’s Denise Buffington, who has drafted a revision request that would create a process for choosing the zone for a new SPP transmission owner’s facilities, and how to submit the TO’s annual transmission revenue requirement (ATRR) or formula rate to FERC for inclusion in the Tariff.

RR172 has been sidelined since October, when it was pulled from the Regional Tariff Working Group (RTWG) and placed on the SPC’s agenda for discussion. (See SPP Moves to Head off KCP&L Measure on Tx Cost Shifts.)

While Buffington will get her long-awaited up-or-down vote on the measure, she told RTO Insider she was still disappointed RR172 had been delayed and that KCP&L’s concerns about “unnecessary and unfair” cost shifts to existing TOs were not addressed.

“I expect a robust debate at MOPC,” she said. “But I expect the ultimate resolution will need to be addressed by FERC and, potentially, the courts.”

The committee, meeting at American Electric Power’s Dallas office, accepted a motion from Heather Starnes, legal counsel for the Missouri Joint Municipal Electric Utility Commission, to conclude the discussion as it became apparent stakeholders would not agree on anything beyond directing staff to use a process document to codify previously approved steps for notifying affected parties of zonal placement decisions. The communications process was approved when the SPC last met in April. (See No Consensus for SPP on Zonal Price Shifts.)

“It’s clear there are issues we can agree upon and issues we can’t agree upon,” Starnes said, reminding the committee that KCP&L’s proposal is still “technically” on the RTWG’s agenda. “Ending discussions of those issues allows RR172 to move directly to MOPC.”

SPP COO Carl Monroe stressed the need to provide a structure for the MOPC to debate KCP&L’s request, suggesting bringing the request up through the stakeholder process and the RTWG. Among Monroe’s concerns were having the MOPC vote on Tariff language that had not already cleared a working group.

Buffington noted RR172 includes proposed Tariff language that she said would be revised to include the discussions before the SPC.

“MOPC can vote on the Tariff language,” she said. “RR172 includes not just the policy issue, but Tariff language that solves the policy problem.”

American Electric Power’s Richard Ross, who seconded Starnes’ motion, pointed out SPP’s working groups don’t decide policy but recommend it.

“There’s only one group that decides policy. It stops at the board, or it goes all the way to FERC,” he said. “I’m all for letting KCP&L have their shot at the process. … Kansas City or John Doe or whoever submits a revision request has their right … to put it through the stakeholder process. They shouldn’t be put in limbo indefinitely. If KCP&L doesn’t get their way at MOPC, they can appeal it to the board.”

“It seems like a member has been allowed to bring an issue directly to MOPC before when a working group failed to approve a request,” said the Nebraska Public Power District’s Paul Malone, who also chairs the MOPC. “I would think that’s the case here too.”

Larry Altenbaumer, one of three SPP directors present at the meeting, weighed in on the issue as well. He advocated having RR172 presented to the MOPC, “where there’s better representation and broader membership.”

“MOPC can decide where it goes,” Altenbaumer said. “I don’t think sticking it in some working group is the right answer.”

“I want a policy decision from MOPC and the board,” Buffington said. “I want an up-and-down vote, where all members have an opportunity to vote on it. If the board ultimately approves it, or through modifications, my expectation is SPP will file it at FERC. … I would ask this group complete its work so I can move forward with my proposal.”

By codifying SPP’s zonal selection criteria in the Tariff, KCP&L says RR172 strikes a balance between attracting new transmission-owning customers to SPP and eliminating the ability for them to shift costs to existing members. The revision is intended to establish a bright line between the costs of legacy transmission and new facilities planned by SPP.

The SPC’s eventual agreement helped short-circuit a series of examples for how staff would handle zonal cost shifts under various scenarios. Staff’s suggestion that there was value in walking through six more examples following a lunch break left one stakeholder wide-eyed and slack-jawed in apparent horror.

Staff has proposed zonal-placement criteria that included:

      • Whether the facilities’ ATRR is less than the minimum zonal ATRR;
      • The extent to which the facilities substantively increase the SPP footprint; and
      • The extent to which the load served by the transferring facilities received network or long-term, firm point-to-point (PTP) service within existing zones before the transfer.

If not placed in a new zone, the facilities would be placed in an integration zone according to:

      • The extent to which the facilities are embedded within an existing zone;
      • The extent to which the facilities are already integrated with an existing zone; and
      • The extent to which the load served by the transferring facilities received network or long-term, firm PTP service within each existing zone prior to the transfer.

Staff will continue working on assessments to determine whether a new member’s facilities meet minimum system reliability requirements, and whether they are similar in design to the integration zone’s facilities and are eligible for inclusion in the existing zonal TO’s ATRR.

MISO Asks FERC for Pseudo-Tie Technical Conference

By Amanda Durish Cook

CARMEL, Ind. — MISO is asking FERC to schedule a technical conference to clarify the rules governing the implementation and use of pseudo-ties.

The RTO made the request in a May 26 filing under two dockets: PJM’s proposal to apply more stringent requirements on external capacity resources (ER17-1138) and MISO’s proposed pro forma pseudo-tie agreement (ER17-1061). FERC sent deficiency notices seeking more information in response to both initiatives.

MISO said a technical conference could “provide a foundational understanding of pseudo-ties, their application, and the challenges they pose” and help FERC “better understand the benefits of pseudo-ties, the potential impacts pseudo-ties have on reliability and efficiency of market operations, and the current status of coordination between neighboring RTOs.”

pro forma pseudo-tie agreement miso ferc
Zwergel | © RTO Insider

“We talked about these things for two years now, and there are still questions,” MISO Senior Director of Regional Operations David Zwergel said at a June 1 Reliability Subcommittee meeting.

MISO’s Independent Market Monitor, who wants FERC to eliminate PJM’s requirement that external resources be pseudo-tied, joined in the call for a technical conference. “What we would like the technical conference to make clear is … there are potential alternatives that should be considered to pseudo-ties. What we hope comes out of this conference is a full hearing of the cost and the benefits,” said Michael Wander of IMM Potomac Economics.

The request comes as PJM and MISO are still working on draft joint operating agreement changes to create a standard pseudo-tie definition and rule set. (See MISO, PJM to Try Again on FERC Pseudo-Tie Filings.)

The joint language, which has not been released to stakeholders, will remove the need for MISO to sign off on PJM’s proposed pro forma pseudo-tie agreement. Late last year, MISO staff said there was no need to write standardized pseudo-tie definitions into the RTOs’ JOA; by early spring, the RTOs had agreed to add coordinated pseudo-tie policies to their JOA.

Zwergel said MISO is hoping to file the JOA in the next few months. “Good progress has been made,” he said.

While it awaits FERC’s decision on a technical conference, MISO will respond to the deficiency letter on its pro forma filing by June 12, he said.

NESCOE Defends Role in Identifying Public Policy Tx Needs

By Michael Kuser

State officials in New England said last week that only they should have the ability to identify public policy-driven transmission needs for evaluation by ISO-NE.

“The plain language of [ISO-NE’s Tariff] designates NESCOE as the entity that identifies whether there are state or federal public policies driving transmission needs and, in turn, whether a public policy transmission study should be commenced to evaluate potential solutions,” the New England States Committee on Electricity said in a June 1 rebuttal to the Conservation Law Foundation.

CLF Senior Attorney David Ismay asked ISO-NE on May 16 to conduct a study to determine public policy transmission needs despite NESCOE’s contention that there are currently no such needs. (See CLF to ISO-NE: Override States, Order Public Policy Tx Study.)

Ismay said a D.C. Circuit Court of Appeals ruling in April confirmed the responsibility of ISO-NE, “not the states, to evaluate transmission needs and potential solutions as part of its Regional System Plan process, regardless of whether those transmission needs arise from state public policy requirements or any other source” (Emera Maine v. FERC, No. 15-1139). (See Court Rebuffs New England TOs, Upholds FERC ROFR Order.)

Misreading of Order 1000

| Massachusetts Clean Energy Center

NESCOE responded that “CLF misunderstands the Order 1000 process … and has conflated the process for evaluating solutions to policy-driven transmission needs with the process of identifying if there are any needs in the first place. Emera imposes no requirements on ISO-NE to determine public policy requirements driving transmission needs and directed no changes to the [Open Access Transmission Tariff].

“CLF mistakenly claims that Emera requires ‘ISO-NE to make its own determination … regarding the existence of [public policy requirements] that are driving, or may drive, transmission needs relating to the New England transmission system.’”

NESCOE said that ISO-NE’s rules on the identification of policy needs have never been in controversy, were not before the court and that FERC itself had affirmed to the court NESCOE’s role in that process. “If anything … Emera affirms the process reflected in the current OATT whereby NESCOE must first identify a state policy driving a transmission need before ISO-NE begins expending consumer dollars on evaluating a need. As Emera plainly states, ‘ISO-NE has no role in setting public policy for the states.’”

The organization closed its response by bemoaning CLF’s request as “precisely the kind of after-the-fact market participant action that causes the states serious pause in using a FERC-jurisdictional tariff to achieve their clean energy requirements.”

ISO-NE Director of Transmission Planning Brent Oberlin had told the Interregional Planning Stakeholder Advisory Committee for New England, NYISO and PJM on May 19 that if the RTO decides to conduct a public policy transmission study, it will need to provide a scope to stakeholders by Sept. 1.

California Senate Passes Bill Mandating 100% RPS

By Robert Mullin

California has moved a step closer to adopting a 100% clean energy standard.

The State Senate on Wednesday passed a bill that would require California load-serving entities to obtain all of their electricity deliveries from renewable resources by 2045 (SB 100).

california renewable portfolio standard rps
de León

Sponsored by Senate President pro Tempore Kevin de León, a Los Angeles Democrat, the bill passed 25-13 along party lines. It now moves to the State Assembly.

“When it comes to our clean air and climate change, we are not backing down,” de León said in a statement. “Today, we passed the most ambitious target in the world to expand clean energy and put Californians to work.”

De León said it is now critical for California to “double down on climate leadership” given President Trump’s announcement today that the U.S. would withdraw from the Paris Agreement on climate change. (See related story, Trump Pulling U.S. Out of Paris Climate Accord.)

“We are sending a clear message to the rest of the world that no president, no matter how desperately they try to ignore reality, can halt our progress,” he said.

The new bill would accelerate the timeline for California’s current 50% RPS from 2030 to 2026, with an interim 45% goal put in place for 2023. The 2030 requirement would increase to 60%, and the bill gives the California Energy Commission discretion to establish “appropriate” three-year compliance periods subsequent to 2030.

The bill also directs state agencies to incorporate the planning goal into any energy and climate programs subject to their jurisdiction, which would include the utility integrated resource plans administered by the PUC.

Passage of the bill got expected support from environmental groups and advocates for renewable energy.

“Getting 100% renewable is 100% possible and 200% necessary,” said Kathryn Phillips, director of Sierra Club California. “SB 100 responds to what survey after survey shows that Californians want: clean energy, clean air and a future for the next generation.”

Strela Cervas, co-director of the California Environmental Justice Alliance, said the proposed law would move California away from fossil fuels that that have a disproportionate impact on disadvantaged communities and communities of color.

“The bill charts a pathway for the public health and economic benefits of local renewable energy to reach communities that need it the most,” Cervas said.

“Transitioning to a 100% carbon-free future in an economy the size of California’s requires persistence, commitment and vision,” said Bernadette Del Chiaro, executive director of the California Solar Energy Industries Association.

renewable portfolio standard
Solar Field | Sunworks

In urging his colleagues to vote against the bill, Republican Sen. Jeff Stone warned that the state might be getting ahead of its ability to actually implement a 100% RPS.

“If we don’t have the science to back up the methodology to get to 2030 with 60% coming from renewables, then it’s going to increase costs for our constituents,” Stone said. “We need to let the technology drive the innovations in alternative energy and not put mandates out there that may be unachievable.”

If it becomes law, the bill would make California the second state after Hawaii to require LSEs to rely on 100% renewables by 2045.

Los Angeles Dept. of Water Power Signs Pact to Join EIM

By Jason Fordney

The Los Angeles Department of Water and Power (LADWP) on Thursday agreed to join the Western Energy Imbalance Market (EIM), adding the country’s largest municipal utility to the growing electricity market.

LADWP is the 11th utility to announce plans to participate in the CAISO-run market, which is designed to better balance supply and demand across the region by making more electricity resources available in real time.

LADWP General Manager David Wright touted the benefits of joining with other utilities across the western U.S. to more reliably integrate renewable energy resources.

“We are pleased to enter the EIM in what will be a solid step forward in partnering with our neighbors to find benefits for the City of Los Angeles,” Wright said in a statement.

While LADWP expects to begin participating in the market in April 2019, that timeline could be extended an additional year to accommodate the utility’s unique configuration and required upgrades. A separate agreement will have to be made once the LADWP system is integrated into the EIM.

Total implementation costs are estimated at $15 million to $20 million, and recurring expenses are projected at about $2.3 million per year. Third-party analysis pegged annual savings for ratepayers at $2 million to $5 million.

About 40% of LADWP’s 7,600 MW of capacity is coal-fired, 20% renewable, 22% natural gas-fired, 9% nuclear and 7% classified as “other.” The municipal utility began distributing electricity in 1917 and serves about 4 million customers.

The utility also individually or jointly controls about 4,600 miles of transmission, which includes the Pacific DC Intertie connecting Southern California with the Bonneville Power Administration system in the Northwest and the Intermountain DC system that carries output from coal-fired generation in Utah.

LADWP EIM CAISO
| CAISO

Already participating in the EIM are PacifiCorp, NV Energy, Puget Sound Energy and Arizona Public Service. Portland General Electric is due to join in October; Idaho Power in April 2018; Seattle City Light and Balancing Authority of Northern California/Sacramento Municipal Utility District in April 2019; and Salt River Project in April 2020.

Vancouver-based Powerex earlier this week became the first non-U.S. entity to announce its intention to join the market starting next spring. (See Powerex Slated to Become First Non-US EIM Member.)

The EIM began operating in November 2014 and now includes participants in Arizona, California, Idaho, Nevada, Oregon, Utah, Washington and Wyoming. CAISO estimates the market has so far produced approximately $173 million in gross benefits for its members.

Waiting on FERC, SPP Members Cut Reserve Margin

By Tom Kleckner

SPP stakeholders approved a revision request Tuesday that allows the RTO to lower its planning reserve margin as it waits on a quorum-less FERC to act on a proposed Tariff change.

The Markets and Operations Policy Committee approved RR230 during a special conference call, changing SPP’s criteria to allow it to reduce the planning reserve margin to 12% from 13.6% effective June 1.

The new reserve margin was included in SPP’s March filing asking FERC to approve the changes effective June 1 (ER17-1098). SPP COO Carl Monroe said the RTO had yet to hear from the commission, necessitating a vote on an interim solution.

“We don’t know why they haven’t acted … we assume because of a lack of quorum,” Monroe said during the hour-long conference call.

On Wednesday, FERC responded by saying SPP’s resource-adequacy requirement filing was deficient and that additional information is required to process the request. The commission listed 18 questions to be addressed related to:

  • SPP’s firm power, firm capacity and net peak demand requirements.
  • How market participants may assign their obligations and responsibilities to other market participants.
  • The RTO’s annual deliverability study that determines the load a resource may deliver to the balancing authority area without effecting reliability or requiring additional transmission upgrades.
  • Deficiency payments and distributions of revenues.

FERC has been operating with only two commissioners since February, when former Chairman Norman Bay resigned and left the commission with three vacancies. The Trump administration only recently nominated two commissioners, who went through confirmation hearings last week. (See No Fireworks for FERC Nominees at Senate Hearing.)

SPP stakeholders resisted staff’s initial request to approve RR230 by an email vote, made when it became likely FERC was not going to act by the effective date. American Electric Power, Westar Energy, Kansas City Power & Light, Oklahoma Gas & Electric and Duke Energy were among those requesting further discussion.

Westar Energy’s Murray Gill Energy Center near Wichita, Kansas | Westar

“I feel like we’re pushing something through that would be better in a thought-out process,” Westar’s John Olsen said. “It’s a little item, but I don’t know what the unintended consequences are. If FERC doesn’t approve [the proposed Tariff] language, then where are we at?”

“Had this been advanced as an issue by OGE rather than staff … I would have worked with [OGE] beforehand,” AEP’s Richard Ross said.

As it was, Ross worked with OGE Energy’s Greg McAuley, Omaha Public Power District’s Joe Lang and Midwest Energy’s Bill Dowling to hammer out the final motion’s language. A key addition was language making RR230 effective for only 10 business days after FERC rules on SPP’s filing.

Members overwhelmingly approved the motion, with only five opposing votes and two abstentions.

RR230 earlier cleared the Supply Adequacy, Transmission, and Regional Compliance working groups with two opposing votes and three abstentions.

SPP’s filing came after the MOPC and the Board of Directors in January approved a package of policies that included the 12% planning reserve margin, which translates to a 10.7% capacity margin.

A task force spent two years on that package, which it says will reduce the RTO’s capacity needs by about 900 MW and save members $1.35 billion over 40 years. (See “Stakeholders Endorse 12% Planning Reserve Margin, Policies,” SPP Markets and Operations Policy Committee Briefs.)

The original revision request incorporated previously approved policies defining a resource adequacy requirement, identifying who is responsible for resource adequacy, and how and when the requirement should be met. The policies are to become effective this summer, with the exception of an assurance policy requiring entities short on their planning reserve margins to make payments to entities with excess capacity, based on forecasted information.

Members agreed to use 2017 as a “dry run” for the resource adequacy process.

Updated: Trump Pulling U.S. Out of Paris Climate Accord

By Rich Heidorn Jr.

WASHINGTON — President Trump followed through on his campaign pledge to withdraw the U.S. from the Paris Agreement on climate change Thursday, a victory for economic nationalists and conservatives that prompted howls of outrage from other signatories, environmentalists and corporate leaders.

President Trump Paris Climate Accord
Trump | © RTO Insider

“I was elected to represent the citizens of Pittsburgh, not Paris,” said Trump, who complained the agreement would do little to combat global warming but would cost the U.S. millions of jobs and leave the nation unable to produce enough power to support economic growth of “3 to 4%” — a pace the country has rarely seen.

“At 3 or 4% economic growth — which I expect — we need all forms of American energy,” he said.

The U.S., the No. 2 producer of greenhouse gases after China, joins Syria and Nicaragua as the only countries not party to the 2015 agreement, which was largely brokered by the Obama administration and has been signed by more than 190 countries. The U.S. agreed to a nonbinding goal of cutting carbon emissions by at least 26% below 2005 levels by 2025.

Trump, who has previously called global warming a “hoax,” did not address climate science, instead saying the U.S. would remain the “cleanest, most environmentally friendly” nation in the world and would seek to negotiate a new deal that doesn’t penalize it. “We’ll see if we can make a deal that’s fair,” he said.

Trump said the Paris Agreement would hamstring the U.S. economy while allowing India and China to increase emissions for years. “China can do whatever they want for 13 years,” he said. “India can double its coal production. We’re supposed to get rid of ours.”

In rejecting the agreement, Trump said he was reasserting American sovereignty and undoing a “self-inflicted wound.”

“This agreement is less about the climate and more about other countries gaining a financial advantage over the United States. The rest of the world applauded when we signed the Paris Agreement. They went wild, they were so happy. For the simple reason that it put our country … in a very, very bad economic disadvantage.”

Speaking after the president, EPA Administrator Scott Pruitt praised what he called “an historic restoration of American economic independence.”

“We owe no apologies to other nations for environmental stewardship. After all, before the Paris accord was ever signed America had reduced its CO2 footprint to levels of the early 1990s,” he said, citing an 18% reduction in carbon emissions between 2000 and 2014. “This was accomplished not through government mandate but accomplished through the innovation and technology of the American private sector. … Other nations talk a good game. We lead with action, not words.”

Former President Barack Obama issued a statement rejecting Trump’s criticism. “It was steady, principled American leadership on the world stage that made [the agreement] possible. It was bold American ambition that encouraged dozens of other nations to set their sights higher as well. And what made that leadership and ambition possible was America’s private innovation and public investment in growing industries like wind and solar — industries that created some of the fastest new streams of good-paying jobs in recent years, and contributed to the longest streak of job creation in our history.

“The nations that remain in the Paris Agreement will be the nations that reap the benefits in jobs and industries created,” Obama continued. “I believe the United States of America should be at the front of the pack.”

Little Surprise

Although Trump said in November that he had an “open mind” on the subject, his announcement in the White House Rose Garden was not surprising given his campaign pledge and his executive order directing EPA to undo the Clean Power Plan.

The CPP would have required a 32% reduction in power plant CO2 emissions from 2005 levels by 2030. (See Trump Order Begins Perilous Attempt to Undo Clean Power Plan.) The U.S. Energy Information Administration says emissions were 12% below the 2005 level as of 2015.

President Trump Paris Climate Accord
Bannon | © RTO Insider

Opposition to the Paris Agreement was led within the administration by Pruitt and political aide Stephen Bannon, who were in the audience for the announcement along with about 100 Trump supporters, including members of the conservative Heritage Foundation and Competitive Enterprise Institute.

During his trip to Europe last week, Trump was lobbied by European officials and Pope Francis to honor the deal. Others who made their case to Trump for remaining included former Vice President Al Gore and leaders of dozens of Fortune 500 companies.

Thirty top CEOs, including Pacific Gas and Electric’s Geisha Williams, signed an open letter urging Trump to remain in the agreement, which they said would strengthen U.S. competitiveness, benefit American manufacturing and support investment “by setting clear goals which enable long-term planning.”

“It expands global and domestic markets for clean, energy-efficient technologies, which will generate jobs and economic growth. It encourages market-based solutions and innovation to achieve emissions reductions at low cost,” they said.

Also weighing in with support were Trump’s daughter Ivanka and Secretary of State Rex Tillerson, neither of whom attended the announcement.

Trump’s speech started 30 minutes late, leaving the hundreds of reporters, photographers and guests sweltering in the sun as a military band played jazz.

President Trump Paris Climate Accord
Pruitt (R) speaks as Trump listens. | © RTO Insider

Some analysts contend Trump’s decision to abandon the Paris Agreement and the CPP will have limited effect because of decarbonization efforts already adopted by power generators and others. (See EBA Panel: CPP’s Demise not Certain — and it Doesn’t Matter.) Economic consultancy company Rhodium Group estimates the U.S. would reduce carbon emissions by 21% below 2005 levels in 2025 under the CPP but that the reduction would flatten at 14% under Trump’s rollback.

Shortly after Trump’s announcement, Democratic Govs. Jay Inslee (Wash.), Jerry Brown (Calif.) and Andrew Cuomo (N.Y.) announced they had formed the U.S. Climate Alliance, a pact dedicated to upholding the country’s commitments under the agreement. On Monday, the group expanded to include Connecticut, Delaware, Hawaii, Massachusetts, Minnesota, Oregon, Puerto Rico, Rhode Island, Vermont and Virginia.

More than 180 U.S. mayors — including Pittsburgh Mayor Bill Peduto and the chief executives of Los Angeles, Boston, New York, Chicago, Houston, Seattle, Philadelphia and Atlanta — issued a statement saying they would “adopt, honor and uphold the commitments” under the agreement.

The Paris Agreement is intended to prevent the planet’s temperature from increasing by more than 3.6 degrees Fahrenheit, which many experts say would lead to an irreversible future of rising oceans and extreme weather, causing drought, flooding, and food and water shortages.

It will take the U.S. until November 2020 to complete its exit from the agreement.

Reaction

The Business Council for Sustainable Energy, which has been an observer at the United Nations Framework Convention on Climate Change for the past 25 years, was dismayed by the news. “Withdrawing from the Paris Agreement weakens the U.S. government’s ability to protect U.S. commercial interests in these discussions as well as in other important international negotiations,” President Lisa Jacobson said. “This international agreement is an opportunity to bolster American economic development, not a barrier to it.”

Mike Tidwell, director of the Chesapeake Climate Action Network, said Trump’s decision “sealed his reputation as an economic and environmental wrecking ball with few rivals in U.S. history. Locally, his decision to withdraw from the Paris Climate Agreement threatens to reduce jobs and shrink our regional economy. It would do so by embracing fracking and a dying coal industry over the jobs-creating markets for wind and solar power.”

Ebell | © RTO Insider

Myron Ebell, director of the Competitive Enterprise Institute’s Center for Energy and Environment, who attended the announcement, issued a statement saying the decision will lower prices. “The agreement involves enormous costs for zero benefits, and requires member countries to submit new, steeper commitments to reduce emissions every five years,” he said. “Its global energy-rationing regime consigns poor people in developing countries to perpetual energy poverty.”

Heritage Foundation President Ed Feulner said the withdrawal was “a commonsense approach that helps the American people and businesses. … From lost jobs, higher electric bills or more overzealous government regulations, the Paris Agreement was by all accounts a rotten deal.”

Senate Majority Leader Mitch McConnell (R-Ky.) thanked Trump for “dealing yet another significant blow to the Obama administration’s assault on domestic energy production and jobs.”

Senate Minority Leader Chuck Schumer (D-N.Y.) called the withdrawal “a devastating failure of historic proportions. Future generations will look back on President Trump’s decision as one of the worst policy moves made in the 21st century because of the huge damage to our economy, our environment and our geopolitical standing.”

Corporate, International Responses

Several corporate leaders blasted the move, with Tesla CEO Elon Musk and Walt Disney Co. CEO Bob Iger pledging to quit a White House advisory council. “Leaving Paris is not good for America or the world,” Musk said.

General Electric CEO Jeff Immelt tweeted his disappointment. “Climate change is real. Industry must now lead and not depend on government,” he said.

IBM issued a statement rejecting Trump’s view that the agreement would hurt the economy. “IBM believes that it is easier to lead outcomes by being at the table, as a participant in the agreement, rather than from outside it.”

But Peabody Energy, the largest coal mining company in the U.S., praised the decision. It said it “continues to advocate for greater use of technology to meet the world’s need for energy security, economic growth and energy solutions through high-efficiency, low-emissions, coal-fueled power plants, and research and development funding for carbon capture.”

The decision was not well received in Europe.

“The Paris Agreement provides the right global framework for protecting the prosperity and security of future generations, while keeping energy affordable and secure for our citizens and businesses,” U.K. Prime Minister Theresa May said.

French President Emmanuel Macron rejected Trump’s call for renegotiation. “I tell you firmly tonight: We will not renegotiate a less ambitious accord,” he said. “There is no way. Don’t be mistaken on climate; there is no plan B because there is no planet B.”

Powerex Slated to Become First Non-US EIM Member

By Robert Mullin

Powerex has signed an agreement with CAISO to become the first non-U.S. participant in the Western Energy Imbalance Market (EIM).

Vancouver-based Powerex markets the surplus generation of parent BC Hydro, Canada’s third largest utility. The company’s role is similar to that of U.S. federal power marketing agencies, such as Bonneville Power Administration and the Western Area Power Administration.

CAISO Powerex EIM
Powerex is wholly owned subsidiary of BC Hydro, responsible for marketing the utility’s surplus hydroelectric generation to customers throughout the West. | Kootenay Canal Generating Station image courtesy of BC Hydro

Mexican grid operator El Centro Nacional de Control de Energía (CENACE) last year announced that it was exploring having its Baja California Norte join the market, but it has not yet signed a participation agreement.

Powerex is slated to join the EIM in April 2018, an aggressive timeline compared with other utilities that have signed on to the market. Preparations typically take 18 months or longer, but the company has long experience selling into the ISO’s real-time market.

“Powerex has actively participated in the ISO’s five-minute market since 2005 through a dynamic scheduling arrangement, so joining the EIM is a logical extension of our intra-hour market participation,” Powerex CEO Teresa Conway said in a statement.

Conway noted that Powerex’s participation in the growing EIM footprint will allow the company to engage in sub-hourly transactions across multiple utility service territories, helping to integrate renewables and improve the region’s grid reliability.

With its access to BC Hydro’s ample hydroelectric resources, Powerex is well-positioned to provide EIM participants with the flexible ramping capacity increasingly needed to firm up the growing number of variable renewable resources coming to the region’s grid. That type of resource sharing is touted as a key benefit of the market.

The company also holds transmission rights on lines throughout the West, including the California-Oregon Intertie, a key transfer point between the Pacific Northwest and California. Constraints on that line periodically act as a chokepoint that isolates the PacifiCorp West and Puget Sound Energy balancing authority areas from the rest of the EIM, resulting in prices that diverge from the rest of the market.

Washington’s Puget Sound Energy — whose service area stretches from suburban Seattle to the Canadian border — began transacting in the EIM last October. (See Seattle City Light Signs EIM Membership Agreement.)

Other future participants in the EIM include Portland General Electric (October 2017), Sacramento Municipal Utilities District (April 2019) and Salt River Project (April 2020). CAISO also said that it expects the Los Angeles Department of Water and Power to soon announce a formal agreement to join the market.

Seeking Subsidy, Exelon Threatens to Close Three Mile Island

By Rich Heidorn Jr.

Exelon announced Tuesday that it will retire Three Mile Island Unit 1 in September 2019 “absent needed policy reforms.”

The announcement was not unexpected after the company acknowledged May 24 that the plant had not cleared the PJM capacity auction for delivery year 2020/21, the third year in a row it had come away empty-handed.

In a filing with the U.S. Securities and Exchange Commission, Exelon said the plant has lost money for the last five years as a result of “prolonged periods of low wholesale power prices,” its failure to clear the last three PJM capacity auctions and “the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution while contributing to grid reliability.” As a single-unit plant, TMI also had high operating expenses, the company added.

Exelon TMI Three Mile Island
Three Mile Island | ©  digitalduck / 123RF Stock Photo

The 837-MW reactor near Middletown, Pa., directly employs 675 workers.

“Today is a difficult day, not just for the 675 talented men and women who have dedicated themselves to operating Three Mile Island safely and reliably every day, but also for their families, the communities and customers who depend on this plant to produce clean energy and support local jobs,” CEO Chris Crane said in a statement. “Like New York and Illinois before it, [Pennsylvania] has an opportunity to take a leadership role by implementing a policy solution to preserve its nuclear energy facilities. … We are committed to working with all stakeholders to secure Pennsylvania’s energy future and will do all we can to support the community, the employees and their families during this difficult period.”

A Successful Strategy

In threatening to close the plant, Exelon is repeating the strategy that won approval of zero-emission credits for its troubled nuclear plants in New York and Illinois.

Last June 2, Exelon announced it would close the Clinton and Quad Cities plants in 2017 and 2018, respectively, because of “the lack of progress on Illinois energy legislation.” The company said the plants had lost a combined $800 million over the prior seven years, “despite being two of Exelon’s best-performing plants.”

Six months later, the Illinois legislature approved the ZEC program on the last day of its veto session. Gov. Bruce Rauner signed the bill Dec. 7. Following the passage of the Illinois legislation, Exelon revised the expected economic lives to 2027 for Clinton and 2032 for Quad Cities.

On June 12, Exelon told the New York Public Service Commission it would close its Nine Mile Point Unit 1 nuclear plant in spring 2017 if the state did not guarantee it a financial lifeline by September.

The company had also told regulators in October 2015 that its R.E. Ginna nuclear plant would not be financially viable following the expiration of a reliability support services agreement with Rochester Gas & Electric.

The PSC approved ZECs for Nine Mile Point and Exelon’s R.E. Ginna nuclear plants last Aug. 1. Receiving payments under the program in addition to Ginna and Nine Mile Point is the James A. FitzPatrick plant, which Entergy sold to Exelon in March after saying it would also close.

Next Steps

Exelon said it will send PJM and the Nuclear Regulatory Commission deactivation notices within 30 days. It complained that nuclear generation produces 93% percent of Pennsylvania’s emissions-free power but is not included in Pennsylvania’s Alternative Energy Portfolio Standard, which benefits solar, wind and hydropower.

The Pennsylvania General Assembly’s Nuclear Energy Caucus said in a statement that Exelon’s announcement shows “there are serious and consequential underlying issues in Pennsylvania’s energy sector that must be addressed.”

“As state lawmakers, we take seriously our obligation to set energy policies that help promote Pennsylvania’s economy,” the legislators said. “We equally are concerned about meeting the commonwealth’s environmental goals. The closure of Three Mile Island will make meeting these challenges even more difficult.”

The 79-member caucus has yet to introduce legislation.

Gov. Tom Wolf’s press office released a statement in which it “expressed a willingness to engage in conversations with state lawmakers about possible energy policy reforms.”

“Pennsylvania is a major supplier of energy and we need a diverse energy sector,” Wolf spokesman J.J. Abbott said. “… As we move forward, we expect a robust conversation about the state’s energy sector. Governor Wolf is open to these conversations and looks forward to engaging with the General Assembly about what direction Pennsylvania will go in regards to its energy sector, including the future of nuclear power.”

Legal Challenges

The ZECs in both Illinois and New York are being challenged in the courts and before FERC by plaintiffs including the Electric Power Supply Association, Dynegy, Eastern Generation, NRG Energy and Calpine.

Exelon’s motion to dismiss a federal lawsuit filed last October challenging the New York ZECs was the subject of oral arguments March 29 (U.S. District Court, Southern District of N.Y., 1:16-cv-08164). Thus far, the court has approved Exelon’s request to intervene, as well as requests to file amicus briefs by the Natural Resources Defense Council, the Environmental Defense Fund, PJM Independent Market Monitor Monitoring Analytics and a group including the New York Public Interest Group.

Independent power producers filed suit in February alleging that the law authorizing Illinois’ ZECs violates FERC jurisdiction over the wholesale electricity market (U.S. District Court, Northern District of Illinois,1:17-cv-01164). (See IPPs File Challenge to Illinois Nuclear Subsidies.)

The judge in the case has delayed action on a motion for a preliminary injunction while he receives a full briefing on Exelon’s motion to dismiss the cases. On April 24, the court invited FERC to file an amicus brief on the jurisdictional question.

In February, the IPPs also sought expedited rulings against the ZECs in FERC dockets initiated over earlier disputes.

Docket EL16-49 had been opened in 2016 to challenge subsidies Ohio regulators had awarded to FirstEnergy and American Electric Power fossil fuel generators. In EL13-62, opened in 2013, the IPPs asked FERC to broaden the use of the minimum offer price rule in New York.

FERC has been without a quorum since February and thus unable to take substantive action on the cases.

At a FERC technical conference May 1-2, NYISO CEO Brad Jones told the commission that the ISO is working on a plan that would incorporate the social cost of carbon into generation offers and reflect it in energy clearing prices. Observers differ on whether FERC — expected to have at least two new commissioners nominated by President Trump soon — will approve Tariff changes to implement the initiative. (See Carbon Adder to Test FERC’s Independence, IPPNY Panelists Say.)

TMI’s Place in History

Whether or not Three Mile Island shuts down in 2019, it will occupy a special place in nuclear power history.

The partial meltdown of TMI Unit 2 on March 28, 1979, the most serious accident in U.S. commercial nuclear power history, effectively ended nuclear power construction for decades and resulted in major changes regarding emergency response planning, operator training and radiation protection.

Unit 2, owned by FirstEnergy, never reopened following the accident. Exelon purchased half of Unit 1 in 1999 and became sole owner of the plant in 2003. The plant received a 20-year extension in 2009, allowing it to operate until 2034.

Financial Repercussions

Exelon said it is taking a one-time charge of $65 million to $110 million for 2017, and accelerating approximately $1 billion in depreciation and amortization through the shutdown date, terminating capital investment projects and canceling 2019 fuel purchases and outage planning, impacting about 1,500 outage workers.

It said there could be as much as $25 million in additional charges in each of 2018 and 2019.