Page 1085 – RTO Insider

June 11, 2020

Coal Groups Fear Accelerating Retirements

Coal industry groups have asked NERC to update its 2018 generation retirement scenario, saying declining power demand and low natural gas prices will likely force the shuttering of more than 30 GW of coal capacity in the next three years.

NERC’s December 2018 special reliability assessment re p ort warned that “significant reliability problems could occur” if retirements occurred faster than the grid could respond to with replacement generation and needed transmission.
The report, which NERC called a “stress test,” used data from NERC’s 2017 Long-Term Reliability Assessment (LTRA), which identified 18 GW of confirmed coal retirements from 2017 through 2022. (See NE R C Releases ‘Stress Test’ Analysis of Gen Retirements.)

The National Mining Association, Lignite Energy Council and ACCCE (formerly the American Coalition for Clean Coal Electricity) told NERC in a let t er June 2 that a study by Energy Ventures Analysis (EVA) indicates that 38.5 to 83 GW of coal-fired generation is at risk of retirement by January 2023 because of falling coal capacity factors resulting from low gas prices, increasing renewable penetration and reduced power demand from the coronavirus pandemic.

The Sierra Club’s Beyond Coal campaign told ERO Insider it agrees that coal retirements are likely to accelerate due to the pressures cited by EVA. “However, we have not modeled these effects on our targets — nor do we have enough data over the past three months to assess a solid trend,” said Beyond Coal spokeswoman Marta Stoepker.

The coal groups told NERC that coal-fired generation in PJM, MISO and SPP — which represents 60% of the remaining coal fleet — fell by 45% in March and April, compared to the same two-month period in prior years. “Low capacity factors mean the fixed costs of operating coal-fueled units are spread over fewer megawatt-hours, making it even more challenging for coal units to recover their costs in the electricity markets and continue operating,” they said.

The groups cited Energy Information Administration data that show coal’s share of electricity generation dropped to 24% in 2019 from 31% in 2017, while natural gas’ share increased from 31% to 37% and wind and solar grew from 8% to almost 9.5%.

“The share of electricity supplied by coal is likely to fall even more during 2020, to be replaced primarily by natural gas,” the groups said. “This trend has left the grid even more vulnerable to problems associated with natural gas than it was during the 2014 polar vortex and the 2017/18 bomb cyclone, when coal was called on to meet increased load and replace power from natural gas units that experienced fuel shortages. (Coal provided more than 60% of the increased demand for power during the Bomb Cyclone.) The natural gas system is unlikely to be significantly more reliable now than it was when the SRA expressed concerns about electric sector dependence on natural gas.”

NERC Assessments

Asked whether NERC had plans to update the 2018 Special Reliability Assessment or if the data provided by the coal groups was causing it to consider an update, spokeswoman Kimberly Mielcarek told ERO Insider that NERC’s 2018 assessment was based on information available at the time, including projected retirements.

“As we do other assessments, we take any new information into account,” she said. ” … Our 2020 Long-Term Reliability Assessment, done annually and expected to be released in December, will have a ten-year outlook on expected generation retirements.”

NERC’s 2019 L T RA projected the elimination of 19 GW of coal by 2029 — just half the 38 GW forecast by EVA by 2023 in its “low retirement” scenario — dropping coal’s generation market share from 20% to 16%. The NERC report noted, however, that its projections “are based on committed retirements known to date and [are] expected to increase as the time horizon progresses.”

EVA’s April 2020 s t udy noted that while coal plant retirements have averaged more than 14 GW annually from 2014 to 2019, only about 14.7 GW of retirements have been announced for the three years ending in January 2023.

coal retirements — Energy Ventures Analysis estimates that 38.5 to 83 GW of coal-fired generation is at risk of retirement by Jan. 2023 because of falling coal capacity factors resulting from low gas prices, increasing renewable penetration and reduced power demand from the coronavirus pandemic. | *Energy Ventures Analysis*

But it said retirements are likely to increase because of “intensified … pressure” on coal plants. “In the first quarter of 2020, coal generation across the lower 48 states fell by about 31% from the prior year,” EVA said.

Two Scenarios

EVA looked at two scenarios, a low retirement case that could more than double announced retirements to almost 38.5 GW and a high retirement case that would more than quintuple retirements to 83 GW. “The acceleration of coal retirements is more likely in the merchant power markets of PJM and ERCOT where coal capacity could fall by 50% or more,” EVA said.

The low retirement case assumed the following plants to be at risk for early retirement:

Utility plants with announced retirement dates from 2023 to 2026, which EVA said are likely to be accelerated due worsening conditions in 2020;
Utility plants listed for retirement under the “final scenarios” of the most recent integrated resource plans (IRP) but for which no final decision has been reached; and
Merchant and utility plants with capacity factors below 20% in 2019.

The high retirement case assumed the following plants at risk:

Utility plants with announced retirement dates in the period from 2026 to 2028, which EVA said could be accelerated due worsening conditions;
Utility and merchant plants with capacity factors below 40% in 2019;
Merchant plants in Pennsylvania, which have an increased risk of early retirement after PJM’s 2022 capacity auction because the state may join the Regional Greenhouse Gas Initiative (RGGI), increasing coal plants’ dispatch costs; and
Merchant plants in ERCOT with capacity factors below 60%, which are at an increased risk due to the lack of a capacity market and high fixed costs.

‘Aggressive, but not Impossible’

The Sierra Club’s Beyond Coal campaign is projecting 21 GW of retirements between January 2020 and January 2023 based on announced retirements, with an additional 30 GW expected to retire by January 2031.

Stoepker said EVA’s retirement projections are “an aggressive, but not impossible, outcome.”

“2015 is when we saw the greatest drop in coal energy generation (21 GW). If we matched that rate in 2020/22, we’d have 63 GW retire (i.e., 42 GW beyond currently announced retirements).”

EVA projects PJM’s coal fleet would be reduced from the current 52.7 GW to 37 GW in its low retirement scenario (–30%) and to 19 GW (–64%) in its high retirement scenario.

PJM offered no comment in response to EVA’s estimates but pointed to its 2018 Fuel Security St u dy, which found that under two “escalated” retirement scenarios, combined with extreme winter load, “the system may be at risk for emergency procedures and load loss.”

One of the scenarios modeled retirements of 32.2 GW by 2023, with 16.8 GW of replacement capacity added to meet the installed reserve margin requirement of 15.8%. A second one assumed 15.6 GW of retirements, with no replacements.

Public Service Company of Oklahoma notified ERCOT in January it will retire the 650-MW coal-fired Oklaunion Power Station in the Texas Panhandle by Oct. 1. | *AEP*

Combining the extreme load, escalated retirements and pipeline outages resulted in numerous scenarios with voltage reductions, reserve shortages and load sheds of as much as 83 hours — about 3.5 days.

PJM described the analysis as a “stress test … intended to discover the tipping point when the PJM system begins to be impacted.” Some critics said the escalated retirement scenarios were unrealistic because they assumed no more than half of such retired capacity would be replaced. (See PJM Begins Campaign for ‘Fuel Security’ Pay m ents.)

EVA sees ERCOT’s fleet dropping from the current 14.2 GW to 11.2 GW under the low retirement scenario (–21%) and 7.5 GW in the high retirement model (–47%).

Asked to comment on the projections, ERCOT spokeswoman Lindsey Hughes said the latest Capacity, Demand and Reserves report issue d in May listed only one planned coal retirement, the 650-MW Oklaunion Unit 1 plant, which is expected to be shuttered by Oct. 1. The report said a “reliability analysis study determined the unit is not required to support ERCOT system reliability.” (See PSO Officially R e tires Oklaunion Coal Plant.)

June 11, 2020

FERC Rejects Challenge to CIP Standards

FERC on Tuesday rejected a complaint by security gadfly Michael Mabee alleging that NERC’s physical security standard is ineffectual and unenforced (EL2 0 -21).

Mabee’s complaint alleged that reliability standard CIP-0 1 4-2 is “inadequate” and that enforcement “seems nonexistent” because few violations have been cited since it took effect in 2015.

The standard, prompted by the 2013 sniper attack on Pacific Gas and Electric’s Metcalf substation, requires the protection of transmission stations, substations and control centers that “if rendered inoperable or damaged as a result of a physical attack could result in instability, uncontrolled separation or cascading within an interconnection.”

The commission said it had already rejected many of the arguments Mabee made in Order 802, its 2014 ruling approving the first version of the physical security standard (CIP-014-1) and in its 2015 order denying rehearing. The complaint’s new arguments “are either unsupported or misapprehend the requirements” of the standard, FERC said.

Few Violations

Mabee contended that there had been only four violations cited while 245 physical attacks have been reported to the Department of Energy through its Form OE-417 Electric Emergency Incident and Disturbance Reports since the standard took effect.

The commission denied that the small number of violations is proof the standard is not being enforced, saying “it is equally plausible that the small number of violations could be attributed to industry compliance.”

It said the higher number of Form OE-417 filings was not persuasive because “there is no evidence how many of these attacks, if any, were against critical facilities” subject to the standard.

“NERC’s comments also indicate that, as of January 31, 2020, there have been 16 (not four) instances of noncompliance … and that NERC and the regional entities are currently reviewing other instances.”

Coordinated Attacks, Generation

Mabee said the standard is lacking because it does not require registered entities to identify critical facilities based on a coordinated attack of multiple facilities and does not apply to generator owners and operators or smaller transmission lines.

In its order denying rehearing, the commission said by “protecting individual critical facilities, responsible entities will necessarily protect critical facilities against simultaneous attacks.”

Regarding suggestions to expand the scope of covered facilities to include those not individually critical, FERC said, “We are not prepared to do so at this early stage of industry experience with the new requirements.”

The commission said Mabee’s complaint “does not provide any new basis for expanding the scope.”

cip standards — Transmission line near Calvert Cliffs nuclear power plant | © *ERO Insider*

FERC previously had rejected calls to include generator owners and operators under the standard, saying “a generation facility does not have the same critical functionality as certain transmission stations and transmission substations due to the limited size of generating plants, the availability of other generation capacity connected to the grid and planned resilience of the transmission system to react to the loss of a generation facility.”

Mabee said the standard’s requirement that registered entities obtain third-party verification of their protections could allow collusion. A transmission owner performing a third-party review could “go easy” on another TO in return for reciprocal treatment, he alleged.

“But the complaint offers no evidence that registered entities have engaged, or intend to engage, in bad faith,” FERC said. “We find no reason to conclude that registered entities will abuse this process. Moreover, a sham verification would not benefit the registered entity because … even if a registered entity’s list of critical facilities is verified by a third-party,” the entities could face penalties from NERC for noncompliance.

“While registered entities must address third-party recommendations, Order No. 802 made clear that regional entities, NERC and the commission retain regulatory oversight.”

Effectiveness of Protections

Mabee’s complaint contended that the standard does not require that physical security plans be effective or spell out what the plans should include. The commission said the claim ignores Requirement R5, “which identifies mandatory attributes that must be present in physical security plans” and says that physical security plans must have “[r]esiliency or security measures designed collectively to deter, detect, delay, assess, communicate and respond to potential physical threats and vulnerabilities identified” by the entity’s security evaluation.

He also contended that it does not require updates to vulnerability evaluations and security plans. FERC said although the standard doesn’t require updates to the threat and vulnerability evaluations on a periodic basis, it does require entities “to evaluate evolving physical threats.”

The Edison Electric Institute, National Rural Electric Cooperative Association (NRECA), American Public Power Association (APPA), Transmission Access Policy Study Group (TAPS) and Large Public Power Council (LPPC) were among those who opposed the complaint.

Mabee was supported by several individuals, the Secure the Grid Coalition, the Task Force on National and Homeland Security, the Town of Mount Vernon and the Foundation for Resilient Societies.

June 11, 2020

Public Policy Challenges Top NYISO Grid Plans

NYISO on Wednesday released its annual Power Trends report, this year focusing on how the grid is being shaped by public policy – amid a global pandemic in which New York was the epicenter for COVID-19 cases in the United States.

“Obviously, the COVID-19 pandemic has altered significantly the way that people work and live their lives, and as a result the challenges and changes to the electric sector,” CEO Rich Dewey said in a press conference.

The economic shutdown has reduced load levels statewide by an average of 8%, and a return to pre-pandemic demand will depend on how quickly the economy rebounds, he said.

2020 Gold Book Baseline Summer and Winter Peak Forecasts. | *NYISO*

The ISO will continue “to keep our eyes on some of those demand patterns and how they might influence the way markets work,” Dewey said.

Though the study found that increasing electrification will likely flip the peak from summer to winter by 2050, the ISO still plans for reliability based on the current summer peak, when air-conditioning use spikes demand, he said.

“The electrification of transportation and building heating systems will certainly change the demand patterns that we need to manage,” said Executive Vice President Emilie Nelson.

Studying these trends “will allow us to develop the market design and further the planning processes necessary to support this transition,” Nelson said. “The ISO hopes to integrate renewable resources like wind and solar not only operationally but also in terms of planning.”

The ISO in December published a 122-page “Grid in Transition” report and in January decided to devote at least one day a month in 2020 to discussing how to meet the clean energy goals set by last year’s Climate Leadership and Community Protection Act (A8429). The law mandates that the state get 70% of electricity from renewable energy resources by 2030 and reach 100% carbon-free electricity by 2040. (See NYISO Focus Turns to Grid ‘Transition’.)

Transmission Buildout

“New technologies are impacting the industry at large, so it’s a very exciting time in the utility industry, whether it’s new renewable projects, whether it’s wind or solar, distributed energy resources, it’s really changing the way energy is produced and how it’s moved and used,” Dewey said.

New York State proposed generation by fuel type in (MW) as of March 1, 2020. | *NYISO*

The state’s Siting Board earlier in June approved a 340-MW wind project south of Buffalo, to date the largest wind farm to pass Article 10 review in New York (17-F-0282). (See NY Regulators Approve 340-MW Alle-Catt Wind Farm.)

In addition to the increasing influence of public policy decisions on the ISO, infrastructure is becoming more important, he said.

“Specific to the infrastructure of transmission, we remain very, very bullish on the need to build out the infrastructure, and transmission is going to be a very important part,” Dewey said. “We continue to study and promote the notion that we need additional infrastructure.”

The state’s recently enacted Accelerated Renewable Energy Growth and Community Protection Act addresses transmission constraints directly by providing for expedited transmission upgrades. (See NY Renewable Supporters Push for New Siting Agency.)

The ISO is mindful of the economic impact from the pandemic and as always is “committed to looking at the most cost-effective way of being able to both hit the goals and to deliver power to consumers,” Dewey said.

The study also considers the transmission implications of developing 9 GW of offshore wind in New York by 2035. The New York Public Service Commission in April granted a state agency permission to solicit up to 2,500 MW of offshore wind energy this year. (See NYPSC Greenlights 2,500-MW Offshore Wind RFP.)

New York Control Area Summer 2020 Installed Capacity (MW) by fuel source, upstate and downstate. | *NYISO*

Dewey was asked why the ISO includes the controversial 1,000-MW Champlain Hudson Power Express (CHPE) project in its trend forecasts. FE FERC OKs Negotiated Rates for Champlain Hudson Project.)

Dewey said that the project is in the interconnection queue and that the ISO’s use of it in planning does not signify endorsement of it.

Nonetheless, he added, “the project that can deliver low-carbon power down to New York City, that’s something that’s probably got to be seriously considered from a policy standpoint.”

Carbon Pricing Still Tops

“First and foremost of the ISO’s initiatives is our proposal to implement carbon pricing,” Dewey said. “We look at this as the most effective, viable means to attract the right kind of investment for renewables that is going to be so important for New York State to achieve its clean energy goals.”

Additions, uprates and deactivations (Nameplate Capacity). | *NYISO*

Speaking at an industry forum in March, NYISO Principal Economist Nicole Bouchez said the ISO determined its carbon price should be incorporated into the energy rather than capacity market because of transmission constraints that prevent upstate New York, which has 87% zero-emission generation, from delivering it to downstate, where only 27% of the mix is renewable. (See Carbon Pricing Gains Popularity — and Doubts.)

“We remain committed to promoting carbon pricing,” Dewey said. “We think using a social cost of carbon embedded in the markets is going to be the most effective and cost-efficient means to be able to hit those goals.”

June 11, 2020

PG&E Names New Board of Directors

PG&E Corp. named a nearly new board of directors Wednesday to guide the troubled utility after it emerges from bankruptcy, probably later this month.

Eleven new board members will join three current members. The boards of parent PG&E Corp. and utility subsidiary Pacific Gas and Electric will be largely the same, PG&E said in a new s release.

PG&E Board of Directors — PG&E is headquartered in San Francisco’s downtown financial district.

The new board members include Mike Niggli, a 13-year veteran of Sempra Energy, who served as president of San Diego Gas & Electric from 2010 to 2013; Craig Fugate, the administrator of the Federal Emergency Management Agency (FEMA) from 2009 to 2017; and retired Admiral Mark Ferguson, former commander of U.S. Navy forces in Europe and Africa.

Former FERC Commissioner and PG&E Corp. Chair Nora Mead Brownell is among those who will leave the board. | *PG&E*

Among those departing will be PG&E Chair Nora Mead Brownell, a former FERC commissioner and Pennsylvania utility regulator. Kristine Schmidt, a former member of CAISO’s Western Energy Imbalance Market Governing Body, who was an adviser to Brownell at FERC, will also be leaving.

The board shakeup is intended to meet the demands of Gov. Gavin Newsom and California Public Utilities Commission President Marybel Batjer to appoint a board of directors with more Californians and greater safety expertise. (See PG&E Tri e s to Appease Governor with New Plan.)

“Putting in place a new board is a critical component of PG&E’s plan to emerge from bankruptcy as a reimagined utility — one that is in touch with its customers and communities and is safe, reliable, financially stable and capable of helping California meet its energy goals,” Brownell said in a statement.

Bill Smith will remain on the board and serve as interim CEO after Bill Johnson’s departure on June 30. | *PG&E*

PG&E CEO Bill Johnson previously announced he’ll retire June 30 — the deadline for PG&E to exit bankruptcy and participate in a state wildfire insurance fund. Remaining board member Bill Smith will serve as acting CEO until Johnson’s replacement is named.

Liabilities from two years of massive wildfires sparked by its equipment drove PG&E to seek bankruptcy protection in January 2019.

The utility’s lawyers made their closing arguments in the bankruptcy case Monday, and U.S. Bankruptcy Judge Dennis Montali is expected soon to rule on whether to accept or reject PG&E’s Chapter 11 reorganization plan. (See La w yers Close PG&E Bankruptcy Case.)

June 11, 2020

Calif. Energy Commission OKs Electrification Rules

Two San Francisco Bay Area cities will join a growing list of communities in California with building electrification ordinances, following the California Energy Commission’s approval Wednesday.

The CEC unanimously accepted ordinances passed by the city councils of Richmond and Hayward, Calif. The new rules needed commission approval because they exceed the efficiency requirements of the state’s 2019 energy code.

Richmond’s ordinance requires new residential buildings to be mainly electric with gas allowed for cooking and fireplaces. It requires new high-rise buildings, both residential and nonresidential, to be all-electric.

Richmond, Calif., home to a Chevron refinery, will join the growing list of cities with building electrification requirements.

In Hayward, new low-rise housing must be all-electric.

“The city of Hayward was one of the first California cities to adopt a climate action plan in 2009, and sustainability remains a top priority,” the city’s mayor, Barbara Halliday, told the commissioners. The city, popular with Silicon Valley workers, is expected to add 2,000 housing units in the next ten years, she said.

There are now 25 cities with CEC-approved electrification ordinances, according to commission staff, including San Jose, Santa Rosa and Berkeley. Some require types of new construction to be fully electrified while others have less-stringent rules. The city of Los Altos Hills, for example, requires new homes to have electric space and water heating.

The CEC and the California Public Utilities Commission have prioritized the switch to electric appliances, including heat-pump water heaters and HVAC units, and away from methane-emitting gas appliances. The state legislature devoted $200 million to jump-start the electrification effort in 2018, with grants administered by the CEC. (See California Travels d own Electrification Road.)

On Wednesday, the CEC awarded more than $4.3 million in grants to the Association for Energy Affordability, a group that advocates for energy efficient buildings. The grants were for two programs to advance “next-generation heating, cooling and water heating systems,” including a pilot project to install central heat-pump water-heating systems in apartment buildings in low-income communities.

The CEC also awarded more than $8 million in grants to lower greenhouse gas emissions from healthcare facilities and large commercial buildings. The awards to five entities included nearly $1.5 million to Southern California Gas Co. (SoCalGas) to demonstrate “an emerging and replicable gas heat pump technology that can reduce natural gas consumption for hot water heating by at least 35% in large commercial buildings.”

June 11, 2020

TOs Vote to File End-of-life Rules with FERC

PJM Transmission Owners voted Wednesday to seek FERC approval for Tariff amendments governing end-of-life (EOL) projects.

Jeff Stuchell, manager of FERC & transmission technical support for FirstEnergy and chairman of the PJM Transmission Owners Agreement-Administrative Committee (TOA-AC), said the committee approved a Federal Power Act Section 205 filing of the Attachment M-3 amendments following the consultation and voting procedures detailed in the Consolidated Transmission Owners Agreement (CTOA).

[UPDATE: The amendments were filed with FERC on Friday (ER20-2046).]

Wednesday’s vote came a little more than a week after stakeholders challenged the TOs’ amendments during a special session of the TOA-AC on June 1 and two weeks after a vote at the May 28 Markets and Reliability Committee meeting in which a “joint stakeholders” propo s al from American Municipal Power (AMP), Old Dominion Electric Cooperative (ODEC) and others regarding EOL projects was narrowly defeated. (See PJM TOs Outline End-of-life T ariff Amendments.)

The joint stakeholders will try again to win approval of their plan at the June 18 Members Committee meeting.

Concern Addressed

One revis i on was made to the TOs’ amendments after a stakeholder raised a concern that EOL projects could potentially remove FERC Form 715 planning criteria from PJM planning under Schedule 6 of the Operating Agreement and cause them to be planned by the TOs under Attachment M-3.

To address those concerns, TOs added to the definition of “Attachment M-3 Project,” revising it with the following clause: “‘Attachment M-3 Project’ does not include a project to address Form No. 715 EOL Planning Criteria.”

“This addition should put to rest the concern that the proposed Attachment M-3 amendments change the responsibility for planning Form No. 715 transmission projects,” the TOs wrote.

Stakeholder Responses

Leading up to Wednesday’s vote, the TOs solicited stakeholders’ comments on the proposed amendments.

The Organization of PJM States (OPSI) proposed several edi t s, including requiring the TOs to provide annual EOL project lists to OPSI and PJM.

The Joint Consumer Advocates wro t e that the proposed amendments are “unjust, unreasonable and otherwise not permissible on procedural and substantive grounds,” saying a May 8 notice filed by the TOs did not comply with provisions of the CTOA. The advocates took exception to new definitions in the amendments and what they said was an improper “expansion and reliance on inapplicable FERC precedent regarding asset management.”

“The PJM TOs, and PJM, have a responsibility to work constructively with all stakeholders to endeavor to develop proposals that are broadly supported and meet FERC standards for an open and transparent planning process,” the advocates wrote.

In joint com m ents, Old Dominion Electric Cooperative (ODEC), American Municipal Power (AMP), LS Power and the PJM Industrial Customer Coalition (ICC) echoed the Advocates’ remarks, saying the proposed revisions are not supported by a majority of PJM members. The stakeholders encouraged the TOs to continue discussions with members to ensure that EOL planning is conducted by PJM.

Ed Tatum of AMP said he was discouraged by Wednesday’s vote, saying it was a “subset” of the TOs in the TOA-AC who decided to draft the amendments. “I’m disappointed the TOs would take this action,” he said.

June 11, 2020

MISO Solar Dispatch a Go, FERC Says

MISO can begin requiring new solar generation in its footprint to become dispatchable by early 2022, FERC ruled Tuesday.

The commission’s order approves a MISO Tariff change requiring all solar resources that achieve commercial operation on or after March 15, 2020, to register as dispatchable intermittent resources (DIRs) and become dispatchable by March 15, 2022 (ER20-595). The RTO is using a ruleset nearly identical to the one that brought wind resources under dispatch in 2011. (See “Solar Dispatch Imminent,” MISO Market Subcommittee Briefs: Dec. 3, 2019.)

MISO has about 46 GW of solar generation pending in its interconnection queue.

“We expect solar to grow 10 to 20 times. It’s small now; we’d like to get ahead of it,” MISO Executive Director of Market Strategy and Design Scott Wright said during the RTO’s December Board Week.

MISO solar dispatch — | *Entergy New Orleans*

In its ruling, FERC said MISO satisfactorily cleared up the commission’s earlier confusion about whether the generator interconnection agreement (GIA) or commercial operation date will determine the 2022 deadline to register. (See FERC Seeks Info on MISO Dispatchable Solar Push.)

MISO said it will exempt the DIR registration requirement for all solar resources in commercial operation prior to March 15, 2020. However, resources that have GIAs executed by March 15, 2020, but are not yet in commercial operation must plan to register and respond to MISO dispatch signals.

MISO said at least one solar developer with a project lined up to come online this summer will have to push back its commercial operation date in order to install the proper communication equipment needed to receive the RTO’s dispatch instructions.

Entergy opposed MISO’s grandfathering plan, saying solar projects that had a GIA executed by mid-March should also be exempted from the DIR registration requirement. The utility will soon either own or purchase output from six solar facilities currently under development. Entergy said the late-stage alterations needed for the solar facilities at their “advanced stage of development” would place an undue burden on the utility.

“MISO’s proposal would unfairly change a Tariff rule that Entergy and other generation developers may have relied upon when planning and making arrangements pertaining to such facilities,” Entergy said.

But FERC disagreed, concluding that facilities with GIAs are not the same as units already in service. The commission also said MISO’s two-year transition period is a reasonable amount of time to purchase and install communication equipment for the solar facilities.

“MISO states that, even if there were no imminent reliability threat, MISO’s proposal follows NERC’s suggestions for how MISO as a transmission provider should dispatch inverter-based resource,” FERC pointed out.

The commission also said MISO doesn’t need to be in the thick of a solar generation boom before it proposes new dispatch rules.

“We also find that it is reasonable for MISO to propose these revisions without waiting until solar penetration has reached a point when its lack of dispatchability may significantly affect reliability,” it said.

June 11, 2020

‘Plan B’ for PG&E Takeover Moves Forward

SACRAMENTO, Calif. — California lawmakers advanced a measure Tuesday that would let the state appoint a receiver or take over Pacific Gas and Electric if the utility fails to provide safe and reliable service after it leaves bankruptcy.

Senate Bill 350, called the Golden State Energy Act, cleared the state Assembly’s Utilities and Energy Committee on Tuesday by a vote of 12-2.

PG&E takeover — Sen. Jerry Hill addressed the Assembly’s Utilities and Energy Committee on Tuesday. | *California Assembly*

In his remar k s to the committee Tuesday, bill author Sen. Jerry Hill (D-San Mateo) said the measure is a “plan B” if PG&E doesn’t undergo the safety transformation it has promised.

“As much as we push forward with that change, we must also be prepared to step in should the company not meet its obligations or commitments in the future,” Hill said. “SB 350 is our preparation. I hope it’s unnecessary and that it’s never triggered. But we owe this preparation to the residents of San Bruno and Santa Rosa and Napa and Butte County and Paradise” — communities devastated by PG&E-caused catastrophes in the past decade.

It is unlikely the state will try to seize PG&E anytime soon, especially with its budget in shambles from the COVID-19 shutdown. The purchase of PG&E would cost tens of billions of dollars and saddle the state with the task of performing the estimated $40 billion in upgrades that PG&E’s aging infrastructure requires.

State investigators, for example, blamed a poorly maintained 100-year-old PG&E power line for starting the November 2018 Camp Fire, the state’s deadliest and most destructive wildland blaze. The Camp Fire and a series of conflagrations in 2017 caused PG&E to file for bankruptcy in January 2019. The utility is expected to emerge from its Chapter 11 reorganization later this month.

As PG&E has been trying to leave bankruptcy, state officials have been putting mechanisms in place to allow for a takeover of the utility if needed.

The California Public Utilities Commission recently approved PG&E’s reorganization plan, along with a process of enhanced oversight and escalating enforcement that could lead to the CPUC revoking PG&E’s certificate of public convenience and necessity (CPCN), its license to operate as a monopoly utility in central and Northern California. (See CPUC App r oves PG&E Bankruptcy Plan.)

In a May 28 meeting, CPUC Commissioner Martha Guzman Aceves said her vote for PG&E’s bankruptcy plan was bolstered by the likely passage of SB 350. The bill would authorize the CPUC to ask a court to appoint a receiver for PG&E or to revoke its CPCN. The bill allows the governor to establish a nonprofit public-benefit corporation called Golden State Energy to take over PG&E’s assets and operations.

“This bill will give ratepayers a genuine alternative,” Guzman Aceves said. “If PG&E fails to provide safe, reliable and affordable energy service, then the commission could petition the court to appoint a receiver or revoke PG&E’s CPCN.”

The bill next faces a vote on the Assembly floor and a concurrence vote by the Senate on Assembly amendments. After that it could go to Newsom for his signature. The governor has indicated he supports the measure.

June 11, 2020February 19, 2025

BOEM Issues Revised EIS for Vineyard Wind

Offshore wind advocates said Wednesday they were encouraged by the U.S. Bureau of Ocean Energy Management’s release of its supplemental environmental impact study (SEIS) on the 800-MW Vineyard Wind project, raising hopes that developers could begin construction as soon as next year.

| Vinyard Wind

BOEM had issued its draft EIS in December 2018, leading to expectations that the agency would issue a record of decision approving the project in 2019. But last August, BOEM said it would not issue the final EIS until it completed a supplemental report looking at the cumulative impacts of Vineyard Wind and other offshore wind proposals in development.

The new report, issued June 9, considers 22 GW of Atlantic Ocean OSW projects from New England to Virginia.

The report found that the cumulative effect of the projects could have major impacts on navigation and vessel traffic, commercial fisheries and military and national security uses.

The report reflects changes to the project since the draft EIS — replacing 10-MW turbines, 696-feet tall with 14-MW turbines, 837-feet tall.

It also includes a new alternative proposed by the Responsible Offshore Development Association (RODA), a fishing industry group, calling for “transit lanes” at least 4-nautical-miles wide. The proposed transit corridor proposed for the Vineyard project would provide a path for vessels traveling from New Bedford, Mass., and other southern New England ports to fishing grounds on Georges Bank.

Alternative F—Vessel Transit Lane Alternative | BOEM

A Vineyard spokesman said the developers were still reviewing the 420-page report. “We’re pleased that BOEM has published the draft SEIS and look forward to engaging with the agency and the many different stakeholders as we continue to make our way through this important public process,” he said.

“BOEM has taken the first in a series of important steps in finally unlocking the enormous potential for offshore wind,” said Tom Kiernan, CEO of the American Wind Energy Association. “The offshore wind industry is committed to working closely with other ocean users and remains confident that the deployment of offshore wind is compatible with commercial fishing and safe navigation, as has been demonstrated for years in other countries.”

Liz Burdock, CEO of the Business Network for Offshore Wind, praised BOEM for “staying on time and on target” in issuing its report.

“The final approval of [the] supplemental EIS this fall will have a domino effect leading to the construction of 9,000 MW by the end of 2030. It will also kickstart a decade that will see the creation of a multi-trillion U.S. blue economy employing thousands,” she said.

ClearView Energy Partners was bullish on the project’s chances of approval. “While President Donald Trump has occasionally criticized offshore wind, we think approving the project would align with the president’s `energy dominance’ agenda,” the firm wrote in a note to clients. Trump issued an executive order in 2017 promoting the development of domestic energy resources, including renewable energy.

Scope for Future Possible Development of Offshore Wind | BOEM

ClearView also said the report “could reduce judicial review risk for other offshore wind projects, particularly if those projects are able to incorporate vessel transit corridors and share a regional transmission system or cable corridor.”

BOEM noted that it has received comments requesting that it mandate the use of a regional transmission cable system for the project but said it was “unfeasible primarily because such a system does not yet exist, and BOEM has issued no right-of-way (ROW) for such a system.”

Anbaric Development Partners has submitted proposals to BOEM to develop two open access offshore transmission systems, one for New York and New Jersey and one for Southern New England that could connect to Vineyard.

BOEM said there is no proposed timeline for the projects nor a plan for who would pay for transmission capacity exceeding Vineyard’s needs. “The proposed project timeline would be substantially delayed by the time needed to properly plan a regional transmission network that would not reduce system resiliency or pose capacity issues for onshore substations,” BOEM said.

“The routes for these proposed regional cables have not been determined at this time and are not considered reasonably foreseeable, but BOEM assumes that if future offshore wind projects utilize one of these open-access transmission systems, the impacts associated with new cable emplacement and maintenance activities would be less than if each individual project installed its own cable,” it said.

The agency will accept comments for 45 days after the SEIS is published in the Federal Register, keeping BOEM on schedule for publishing a final EIS in November and issuing a final decision by December. That would allow Vineyard Wind to begin construction in 2021 and begin service in 2022.

June 9, 2020

PJM MIC Briefs: June 3, 2020

The PJM Market Implementation Committee on Wednesday endorsed an initiative to update the RTO’s business rules to accommodate co-located generation and energy storage hybrid resources.

The issue charge passed unanimously by acclamation and is set to be overseen by the proposed Distributed Energy Resource and Inverter-based Resources Subcommittee (DIRS).

Scott Baker, PJM business solutions engineer, provided a first read of the problem statement and issue charge for the effort, which will define how current requirements for solar parks, solar resources, intermittent resources and energy storage resources do and do not apply to generation-battery hybrids.

The focus of discussions will initially be centered on solar-battery resources, which represent more than 95% of the more than 10,000 MW of hybrids in the PJM interconnection queue. But the issue charge allows for investigation of other hybrid resources like wind-battery, gas-battery or any other combination. Baker said that as a result of stakeholder feedback at the Markets and Reliability Committee, the issue charge calls for the subcommittee to begin work in July and report its findings and proposed solutions to the MIC by the end of 2020. (See “Action on Hybrid Resource Initiative Deferred on Venue Question,” PJM MRC Briefs: April 30, 2020.)

Baker said the solar-battery hybrid issue assignment was intentionally left blank because the MIC is also discussing the consolidation and creation of the DIRS. He provided the first read of the charter for the new subcommittee and a proposal to sunset the Intermittent Resources Subcommittee (IRS). The IRS originated as the Intermittent Resources Working Group (IRWG) in 2008 to address issues regarding operations and reliability, energy markets, capacity markets and interconnections.

Baker said that although DIRS would operate under the MIC, stakeholders requested that the subcommittee also coordinate with the Planning and Operating committees. Baker said many of the issues discussed at DIRS could affect both markets and operations.

PJM will seek endorsement of the new subcommittee at the next MIC meeting on July 8.

PRD Credits Disposition

Sharon Midgley of Exelon provided a first read of the problem statement and issue charge addressing the price-responsive demand (PRD) credits disposition. The issue calls for the MIC to review the market design to determine if the current load-serving entity PRD credits are appropriate and to explore alternative allocations.

PRD providers represent retail customers that have the capability to reduce load in response to prices. Midgley said current PJM settlement rules do not address electric distribution companies (EDCs) or curtailment service providers (CSPs) that do not have direct responsibility for serving retail load but otherwise meet the eligibility requirements of a PRD provider.

All revenues associated with PRD are credited to the LSE for the area, Midgley said, meaning some market participants are paid for PRD service that an EDC or CSP is supplying while performance penalties stay with the PRD provider.

The committee will vote on the issue charge endorsement at its July meeting. The work effort is expected to take six to nine months, with changes implemented in advance of the 2021/22 delivery year.

Performance Assessment Interval Settlements

Danielle Croop of PJM conducted a first read of a problem statement and issue charge to increase transparency in settlement calculations for nonperformance charges, including ancillary service accounting and the determination of scheduled megawatts. It will also include provisions to make language for energy-only and demand response resources parallel with that of generation resources.

In March, PJM released a report on performance assessment interval (PAI) settlements as an addendum to its r eview of the Oct. 1-2, 2019, performance assessment event, when an abnormal heat wave led to emergency procedures and the first call on DR resources in more than five years. (See PJM, Stakeholders Baffled by DR event.)

The incident resulted in $8.2 million in nonperformance charges. Bonus payments averaged $32.89/MW-interval, with the average amount of megawatts eligible for bonuses during the event being 9,706.

In her presentation, Croop said PJM staff found the settlement calculations for the Oct. 1-2 emergency event lacked transparency. A market notice was posted on PJM’s capacity market webpage detailing how the RTO settled the charges and credits.

Croop said the RTO will seek stakeholder input on business rules not described in detail in the governing documents. The initiative will memorialize the business rules in the appropriate agreements and manuals without changing the substance of Capacity Performance rules.

Independent Market Monitor Joe Bowring said he disagreed with some of PJM’s proposed language changes, calling it “subjective” and difficult to interpret. Bowring said some of the proposed rules may not be consistent with CP.

“We want to make sure the end result is that this process works properly,” Bowring said.

The MIC will vote on the issue charge approval at its July meeting.

FERC Transmission Orders

PJM’s Ray Fernandez provided updates at both the MIC and the June 2 Planning Committee meeting on the cost allocation impacts of two recent FERC orders requiring resettlement.

In the first order, FERC ruled that PJM must rebill parties to reverse incorrect cost assignments of Form 715 transmission projects. The costs, which had been allocated 100% to the zone of the host transmission owner, have been spread more widely, reflecting the projects’ regional benefits. (See FERC Stands Firm on Form 715 Assessments.)

PJM found 44 projects impacted by the order, including 33 in the PSEG zone and 11 in the Dominion zone.

Dominion Energy will collect almost $28.5 million in refunds from two dozen other transmission zones, led by American Electric Power and Commonwealth Edison, which will be billed more than $4 million each, according to an estimate posted by PJM on May 27.

Public Service Electric and Gas is owed $53.2 million from five companies, led by Linden VFT ($19 million), Neptune ($15.2 million) and Consolidated Edison ($13.2 million). PJM cautioned that the revised cost assignments could change based on FERC rulings or additional review by the RTO.

In the second order, FERC ruled that two merchant transmission operators in New Jersey are still liable for some cost allocations under PJM’s Regional Transmission Expansion Plan (RTEP) despite converting from firm to non-firm service after the cancellation of the Con Ed-PSEG “wheel” in 2017 (ER18-680). (See FERC Rejects Cost Formula for NJ Merchant Tx.)

Linden and Hudson Transmission Partners (HTP) own merchant transmission facilities that carried power into New York City as part of the wheel, in which 1,000 MW were exported from upstate New York to PJM through PSE&G facilities in northern New Jersey, and then exported to the city. Con Ed and PSE&G canceled the agreement in April 2017, prompting HTP and Linden to convert their firm transmission withdrawal rights (TWRs) to non-firm TWRs.

HTP would be billed $24.1 million and Linden $5.7 million under PJM’s resettlement estimate. PSE&G is the biggest beneficiary, due $22.9 million.

Linden, Long Island Power Authority, Neptune and the New York Power Authority (NYPA) made requests for a rehearing to FERC, Fernandez said. Linden and NYPA also requested settlement relief if FERC does not grant a rehearing request by delaying billing until January 2021 and to allow for a 12-month settlement period in equal installments from Jan. 1, 2021, through Dec. 31, 2021.