Page 1280 – RTO Insider

February 10, 2019

Stakeholders Seek Slowdown on MISO RAN Project

By Amanda Durish Cook

CARMEL, Ind. — Stakeholders are urging MISO to slow down on bigger ideas to address its disjointed resource availability and need (RAN) until it can measure the effects of three smaller related filings pending before FERC.

For the remainder of this year and through 2020, MISO’s Market Subcommittee and Resource Adequacy Subcommittee will discuss long-term methods of shoring up resource availability as reserve margins decline.

Speaking at a Feb. 5 RASC meeting, MISO Director of Resource Adequacy Coordination Laura Rauch said most of the discussions will take place independently, though the RTO may schedule joint MSC and RASC meetings on the topic.

MISO recently filed new near-term rules for load-modifying resources (LMRs) and planned outages to buy time for more comprehensive solutions. Up to the filings, stakeholders had also urged a slower approach to developing those rules. (See MISO Files New Planned Outage Rules.)

Nearly a month later, MISO is ready to take on the broader proposals, which may include changes to the annual capacity auction, loss-of-load expectation study and capacity accreditations. It said the second and third phases of the project will address “gaps in the efficient conversion of committed capacity to energy.”

So far, a number of stakeholders maintain that MISO’s timeline on the multifaceted project is too aggressive, with some saying that it should evaluate the effects of its LMR and outage filings before it moves on to long-term remedies.

“A lot of comments focused on that we’re moving too fast; the two phases are being rushed. … We do plan on working through the stakeholder process over the next few months to make sure that any solution is vetted,” MISO planning adviser Davey Lopez told stakeholders at a Feb. 6 RASC meeting.

MISO Executive Director of Market Development Jeff Bladen said the RTO is starting conversations now with an eye on recommending long-term solutions within a year and a half.

“This is a marathon, not a sprint,” Bladen said.

“At what point does MISO declare victory? Is there some point where there’s enough of a buffer that MISO stops making changes?” asked Bill Booth, consultant to the Mississippi Public Service Commission, adding, “We’re moving at warp speed.”

Rauch said the RTO will continue determining whether improvements are enough to maintain reliability by gauging whether increasingly frequent maximum generation events are more accurately predicted and managed.

“The goal is not to eliminate all emergency conditions. That’s part of our normal operations,” Rauch added.

Lopez said MISO plans to analyze the impacts of the LMR and outage filings and compare upcoming capacity auction results with prior year auctions before it proposes any changes to capacity accreditation. MISO has said it will investigate adjusting capacity accreditation “based on the ability to resolve resource risk.”

Seasonal LOLE?

Lopez asked for stakeholders’ written feedback on the usefulness of a seasonal capacity construct, an idea long pondered in MISO. The RTO last proposed a two-season capacity auction in mid-2016 before talks stalled, and stakeholder appetite for a revised proposal resurfaced last year.

Some stakeholders said MISO’s loss-of-load expectation (LOLE) study could use improvement if the RTO moves to a capacity auction structure based on either two or four seasons.

Multiple stakeholders said MISO should first examine possible technical changes to the LOLE study — which is based on an annual summer peak — in light of moving to a one-day-in-10-year reliability standard based on seasons.

“Without basic technical LOLE work, I don’t know if we can start the discussion. … I think that needs to be upfront before we can even start on the policy of this,” Minnesota Public Utilities Commission staff member Hwikwon Ham said. “Software can spit out any number you want to. That doesn’t mean you’re getting the right result on your statistical theory.”

Rauch said MISO would have to conduct research to determine which LOLE inputs and calculations would be appropriate.

Jeff Bladen answers stakeholder questions from the audience | © *RTO Insider*

A seasonal construct also raises the question of whether interconnection service should be divided by seasonal availability, Lopez said. He also said stakeholders should consider whether they prefer a single annual action with seasonal offers or multiple separate seasonal auctions.

Independent Market Monitor staff Michael Chiasson said a seasonal auction would satisfy some IMM recommendations, particularly its longstanding recommendation that resources be accredited according to their ability to deliver across varying conditions.

A day later at a Feb. 7 Market Subcommittee meeting, Bladen insisted that MISO doesn’t currently have a load forecasting problem, but an uncertain resource availability problem.

“It’s not the uncertainty itself that’s increasing. It’s the nominal impact of that uncertainty that’s increasing,” Bladen said.

Beyond LMRs

Stakeholders also asked if MISO will begin focusing on other resources besides LMRs, inquiring about possible changes to the modeling or accreditation of baseload or intermittent resources.

MISO staff said a wide array of changes are on the table and that the RTO might also consider incentives for LMRs with shorter lead times.

“We’re going to let the advice from this committee guide us,” Bladen told the RASC. He later added that while stakeholders and MISO may not have the time to examine upwards of 30 solutions, there’s still a “veritable menu” of options.

MISO said stakeholders may want the RTO to further incentivize economic demand response and improve its scarcity price formation. It also said it could reduce capacity accreditation for long-lead resources.

MISO plans to continue the RAN discussion at the March RASC and MSC meetings.

February 10, 2019

MISO Preliminary PRA Data up Slightly from Early Prediction

By Amanda Durish Cook

CARMEL, Ind. — MISO’s recent resource adequacy filings with FERC will affect the timeline of an otherwise unremarkable capacity auction in terms of load forecasts, stakeholders learned last week.

MISO staff confirmed the 2019/20 Planning Resource Auction numbers haven’t moved much from the previous planning year, in line with estimates made last month. (See Early MISO PRA Data Show Little Change.)

The RTO predicted systemwide coincident peak load will be about 122 GW for the period, up from the 121.6-GW prediction made in January for the planning year. The RTO’s total zonal coincident peak now stands at 125.6 GW, up from an earlier 125.3-GW prediction.

MISO now estimates an almost 135-GW planning reserve margin requirement, also up from the earlier 134.4-GW estimate. Similarly, combined local resource requirements are up slightly from 152.6 GW to nearly 153 GW.

“A lot of the data is pretty close to the data we presented in January,” Tim Bachus, MISO capacity market administration analyst, said during a Feb. 6 Resource Adequacy Subcommittee meeting.

Final preliminary data will be presented during the March RASC meeting. MISO will conduct its seventh annual PRA during the second week of April.

In some cases, PRA data deadlines have already passed for resources hoping to participate in the auction — particularly load-modifying resources. Generation owners were also expected to provide the Independent Market Monitor with data to calculate reference levels by Feb. 12, while load-serving entities have until Feb. 15 to request revisions to their coincident peak demand figures.

LMR Registration Confusion

Existing and new LMR registrations, usually due Feb. 1 and Feb. 15 respectively, will be due March 1 only if FERC approves a Tariff filing meant to ensure LMRs are available as promised. MISO said it expects FERC to rule on the matter by Feb. 20, and a more detailed LMR registration survey under the RTO’s proposal is available now.

If the filing is approved, MISO will ask some LMRs with a lead time greater than two hours and that are available fewer than nine months out of the year to submit their monthly megawatt availability and a documented required notification time necessary to begin generating. (See MISO Moves to Examine Long-term Supply Measures.) MISO will allow LMR owners that have already registered their asset according to the current Tariff to amend their registration surveys.

If FERC rejects the filing, MISO will revert to its current LMR registration process, with LMRs not already registered disqualified from auction participation.

Some stakeholders said the competing timelines are creating confusion. Others pointed out that several LMRs have already submitted registration in accordance with MISO’s current Tariff. MISO staff said it would reopen registrations to make sure the new data requirements are met if approved.

Manager of Capacity Market Administration Eric Thoms reassured stakeholders that, should FERC reject the filing, the RTO would not use LMRs’ additional data, and the current process would stand without change.

Stakeholders asked if MISO was satisfied with this year’s load forecast data supplied by LSEs.

“There are always a few numbers that might be outside the curve,” Bachus said, adding that MISO determined there were good reasons for the discrepancies after reaching out to LSEs.

“In the end, there were no concerns about any numbers that may have seemed out of line,” Bachus said.

As in years past, stakeholders continued to question why MISO combines the forecast data for Iowa and Missouri in Local Resource Zones 3 and 5 and all of MISO South. The RTO has long combined PRA data in zones where pivotal suppliers are sparse and their private information could be revealed. Stakeholders again asked MISO to separate the data by zone to provide a clearer picture of resource adequacy.

Meanwhile, MISO will on March 25 send out its annual resource adequacy survey in cooperation with the Organization of MISO States. Completed surveys are due from LSEs and independent power producers by April 15. The RTO will present results in June and July.

February 10, 2019

MISO Details ‘Uncertainty’ Behind Winter Max Gen Event

By Amanda Durish Cook

CARMEL, Ind. — MISO proactively managed its eighth maximum generation event in six years last month despite the difficulty of pulling together the forecast leading up to the episode, RTO staff reported last week.

Ron Arness, MISO director of Central Region operations, said “a significant amount of uncertainty” characterized the Jan. 30-31 event, spurred by a polar vortex bringing record cold conditions.

High load, fuel supply issues and the possibility of equipment failure coupled with substantial voluntary load management, such as school and business closings, made load profiles uncertain over the period, Arness said. MISO called the maximum generation event beginning 2:38 a.m. ET on Jan. 30 and terminated it at 11 a.m. the following day.

“We had some extreme temperatures … and because of the actions of you as members and MISO took, we reliably maintained service. It was essential because public safety was critical at that time,” Arness told stakeholders at a Feb. 7 Market Subcommittee meeting.

MISO originally forecasted a 104-GW peak load on Jan. 30, though the actual peak clocked in at 101 GW as temperatures sunk to -30 degrees Fahrenheit in some parts of the balancing area.

“We thought we were going to be short, and then we weren’t,” Arness said. “Even though temperatures were colder than we predicted, this voluntary load curtailment” scaled down load.

To produce its regional weather forecasts, MISO uses two separate third-party weather forecasters, both of which rely on multiple weather models.

MISO said that for much of the event, it experienced increased imports in response to its emergency conditions pricing. On Jan. 30, spot natural gas prices nearly doubled to $7.42/MMBtu and the average real-time LMP quadrupled to about $108/MWh. By Jan. 31, the real-time LMP dropped to about $49/MWh, still about double the energy price two days prior.

The RTO entered a cold weather alert on Jan. 25, an important and proactive step, Arness said. (See MISO Maintains Reliability Through Arctic Midwest Temps.)

“Really the intent of that cold weather alert is so members can update their offers and unit availability,” Arness said, stressing that MISO is better able to manage the market with the most accurate offer and commitment information.

“Thank you to all your companies that worked so hard to keep the lights on,” Chris Miller, of FERC’s Office of Energy Market Regulation, told members.

Winter Winds, but Few to Harness

MISO operators were further stymied by lower wind generation than expected during the arctic blast.

Wind output during the morning peak Jan. 30 was about 4 GW below forecast as the worst of the cold struck the Midwest. Wind output averaged 4.3 GW and 4.7 GW on Jan. 30 and 31, respectively, compared with about 13 GW for the two days prior to the event.

“It was cold and the wind was blowing, but we suspect that there were significant cold weather cutoffs. We did expect some cutoffs due to the cold — about 1 GW — but we didn’t expect this magnitude,” Arness said.

“This is something we have not seen since MISO has been in existence,” he added.

Arness said MISO staff will continue to investigate the drop in wind output, as well as other factors during the event. The RTO will review wind generator availability during cold temperatures, including maintaining a list of wind generators that have cold weather shutoffs installed, he said.

“What we’re looking for is lessons learned and to enhance our preparedness for future events,” Arness said.

LMR Data Forthcoming

All told, MISO requested about 2,500 MW worth of load-modifying resources during the event. LMR performance reports are expected later.

Stakeholders asked if MISO would consider decoupling its LMR dispatch from its emergency operating procedures so LMRs can be used outside of a declared emergency. Under MISO’s emergency procedures, LMRs are classified as emergency-only resources, requiring the RTO to declare an emergency before dispatching them.

Executive Director of Market Operations Shawn McFarlane said a December Tariff filing would allow MISO to issue scheduling instructions for LMRs as early as 12 hours ahead of a called emergency, allowing the resources to activate and be ready to deploy during an emergency.

Stakeholders questioned whether MISO remains confident about in that approach.

“We can’t deploy emergency resources when it’s not an emergency,” Executive Director of Market Development Jeff Bladen said.

Arness said MISO will continue to dissect the event with stakeholders in public meetings later in February and March.

Customized Energy Solutions’ David Sapper asked for a pricing analysis around the event, given that average energy prices two days before the event hovered around the usual $26/MWh and $27/MWh, even as temperatures ranged from -20 to 2 F.

MISO staff promised to return with more pricing information.

February 10, 2019

CAISO Raises Stakes for Intertie Non-delivery

By Hudson Sangree

FOLSOM, Calif. — CAISO’s Board of Governors unanimously approved a proposal Thursday meant to ensure that bidders from outside the ISO deliver electricity as promised or face more stringent financial penalties.

The Board of Governors met Thursday at CAISO headquarters in Folsom, Calif. | © *RTO Insider*

“The existing charge [for non-delivery] is relatively ineffective,” Brad Cooper, CAISO’s manager of market design policy, told the board in his presen t ation. That’s because participants rarely exceed a 10% monthly threshold when the charge kicks in. The new policy does away with that threshold.

Currently, “if intertie declines are less than 10% of total transactions, no charge applies,” the ISO wrote in an Aug. 15 issu e paper. Anything more than a 10% failure-to-deliver rate can result in a charge of up to $10/MWh.

The lack of a financial incentive to follow through on bids can cause headaches, CAISO said in the paper.

“When an intertie resource receives a market award to import energy into the balancing authority area but does not deliver the awarded energy, the grid operator must maintain system balance by increasing internal supply or finding another intertie resource to import from,” it said.

Brad Cooper, CAISO’s manager of market design policy, briefs governors on a plan to raise the stakes for bidders that don’t deliver on intertie bids. | © *RTO Insider*

Grid reliability and stable pricing depend on expectations being met, Cooper said at Thursday’s board meeting.

“When exports don’t deliver, they can cause intertie congestion,” he said. And “undelivered imports in a critical hour can have a big effect.”

The revised policy is also meant to curb speculative bidding — when a market participant submits a bid and doesn’t deliver because it can’t find the energy it promised or can’t find it at the right price.

When the 10% threshold was enacted in 2007, ISO computers couldn’t distinguish between an intertie “decline” and a reliability curtailment, officials said. That meant that reliability curtailments, which weren’t the fault of the market participant, could still count toward the decline charge.

The bar was set high at 10% to avoid penalizing participants who were unable to deliver because of unforeseeable problems.

Now the ISO’s system can distinguish between curtailments and non-deliveries, meaning the 10% threshold can be eliminated. Instead, non-delivery charges will be assessed in 15-minute intervals and “non-delivery will be subject to a charge equal to 50% of the maximum of the 15-min market or the five-minute real-time dispatch LMP, with a $10/MWh minimum, plus any imbalance energy,” according to the ISO.

Cooper said most stakeholders supported the plan as a way to reduce speculative bidding and to enhance reliability.

Recently appointed CAISO Governors Mary Leslie and Severin Borenstein attended their first board meeting Thursday. | © *RTO Insider*

Severin Borenstein, a University of California Berkeley pro f essor attending his first meeting as a newly appointed CAISO governor, asked planners to clarify why the charge applies to interties but not inside the ISO’s system.

Keith Casey, CAISO’s vice president for market and infrastructure development, explained that if an intertie bid — always scheduled an hour ahead of delivery — doesn’t materialize, the ISO can’t clear additional intertie energy until the next hour, but internally it can resort to the five-minute market to cover the shortfall.

February 10, 2019

NYPSC Approves $32 Million for EV Fast Chargers

By Michael Kuser

The New York Public Service Commission on Thursday authorized utilities to spend $31.6 million to build up to 1,075 fast-charging electric vehicle stations and recover costs from ratepayers over seven years (18-E-0138).

The program is intended to help spur sales of EVs by reducing people’s “range anxiety” — the fear of running out of juice on the road — and to achieve Gov. Andrew Cuomo’s Charge NY goal of 10,000 EV charging stations by the end of 2021 and 800,000 zero-emission vehicles by 2025.

The commission’s Feb. 8 order outlines a flow of actions, including annual reviews, that “are smart and timely steps to enable new and needed infrastructure at sensible budgets and at sensible payment structures,” PSC Chairman John B. Rhodes said. “It puts a wide range of partners in a position to invest their money in our agenda for the benefit of all New Yorkers.”

The PSC last April approved a seven-year tariff for Consolidated Edison’s quick-charging station program (17-E-0814). (See NYPSC OKs Con Ed EV Charging Program, REV Initiatives.)

In a related case (18-E-0206), the PSC in November rejected tariff filings for residential EV charging from all the major utilities in the state and ordered them to file revisions that implement time-of-use rates equal to the traditional residential customer charge. (See NYPSC OKs CCA, Rejects Residential EV Charging Tariffs.)

The new proceeding grew out of a joint petition last April by the New York Power Authority, along with the state’s Department of Environmental Conservation, Department of Transportation and Thruway Authority, seeking rate relief for DC fast-charging (DCFC) facilities for EVs.

The state’s Department of Public Service held a technical conference on the issue last summer, and in November the utilities joined the state agencies in filing a consensus proposal for the program.

Rate Design

Mary Ann Sorrentino, chief of electric rates and tariffs for the DPS, testified that rate design was the PSC’s main concern.

“To capture cost savings from potential technology cost declines, the draft order requires that initial incentive amounts be tied to the year in which the station qualifies for the program,” she said.

Sorrentino said plugs must have a 50-kW minimum charging capability to qualify for the program and that higher incentives will be provided to plugs with a minimum simultaneous charging capability of 75 kW.

Within 90 days of Thursday’s order, the New York State Energy Research and Development Authority must disburse the $31.6 million in unencumbered legacy system benefits charge (SBC) funds to the state’s six regulated utilities in the following amounts: Con Ed ($6.4 million); Orange and Rockland Utilities ($1.66 million); Central Hudson Gas & Electric ($4.4 million); Niagara Mohawk Power ($9 million); New York State Electric and Gas ($5.1 million); and Rochester Gas & Electric ($5 million).

The SBC provides funding for NYSERDA programs targeting energy efficiency, research and development and the low-income sector.

Commissioner Diane Burman brought up the $128 million New York received as its share of Volkswagen’s national settlement for flagrant emissions standards violations, which the state has earmarked for clean transportation measures such as promoting EV use.

“I understand there’s a separate track for that; I’m not looking to get involved in stuff that’s outside our jurisdiction,” Burman said. “To the extent that it complements us … it is extremely important that we are complementing each other in a way that makes sense. Here we’re talking about taking unencumbered legacy funds that seem to never, ever be ending over at NYSERDA, and utilizing them now for part of this.”

The state estimates EV sales were up 50% last year from 2017, with more than 43,000 EVs on the road by October, one-third of them battery electric and the rest plug-in hybrids.

“EVs, as is well known, have a chicken-and-egg problem,” Commissioner Gregg C. Sayre said. “Chargers aren’t being built because there aren’t enough EVs, and EVs aren’t being bought because there aren’t enough chargers. This item helps us get out of that cycle.”

Notable Differences

The PSC decided to minimize some of the “notable differences” contained in the consensus proposal.

“For example, pursuant to the consensus proposal, the Con Ed and Orange and Rockland per-plug incentives were to provide a combined benefit in conjunction with delivery rate discounts offered under the Business Incentive Rate [BIR] and Economic Development Rate, respectively, whereas the other utilities’ per-plug incentives were designed assuming that DCFC stations will not receive other delivery rate discounts,” Sorrentino said.

The Con Ed and O&R proposals were also unique in that they contained a separate load-factor incentive whereby station owners would earn a $500 incentive annually for achieving a 5% load factor, and $1,500 annually for achieving a 10% load factor, she said.

The commission found “the load-factor incentive to be unnecessary at this time, as station owners have a natural incentive to maximize station utilization,” Sorrentino said.

Under Con Ed’s tariff, the BIR was available to owners of EV quick-charging stations with a minimum aggregate charging capacity of 100 kW and a maximum aggregate demand of 2,000 kW in New York City and Westchester County.

“This BIR has been open to electric vehicle quick-charging station developers since April, and that market has not materialized,” testified Bridget Woebbe, assistant counsel for the DPS. “Removing the restrictions really allows site hosts that are providing a direct capital investment by building the critical infrastructure to receive the appropriate incentive to deliver the public good of the DCFC.”

February 10, 2019February 5, 2025

NERC Member Representatives Committee Briefs: Feb. 6, 2019

MANHATTAN BEACH, Calif. — NERC stakeholders last week got a first look at a draft report on supply chain risks as part of a FERC directive to develop a standard addressing risk management of the industry’s vendors.

Roy Thilly, chairman of NERC’s Board of Trustees, called the initiative a “very important undertaking,” but he also cautioned that it is not a “silver bullet.”

Supply chain risk management “requires a practical, effective, measured response,” he said during the NERC Member Representative Committee’s Feb. 6 meeting.

MRC Vice Chair Jennifer Sterling and Chair Greg Ford | © RTO Insider

NERC staff have been working with the Electric Power Research Institute to assess the bulk electric system’s (BES) product and manufacturer types, analyze BES cyber assets, and gather best practices and standards used by other industries to mitigate supply chain risks.

At the board’s request, the North American Transmission and Generator Forums and other industry groups have developed white papers, which can be found on the initiative’s website.

The report suggests applying industry practices to third-party accreditation processes; ensuring that hardware and software are protected during physical transport; processes to mitigate risks from unsupported or open-sourced technology components; and using supply chain controls to address common-mode vulnerabilities.

Staff are recommending the standards include electronic access and physical access controls for medium- and high-impact BES cyber systems, and to collecting more data on low-impact BES cyber systems. They also plan to monitor emerging technologies for new risks.

Howard Gugel, NERC’s senior director of engineering and standards, said the industry’s reliance on technology and the use of single platforms to host multiple applications has increased the risk of access through “the back door.”

Despite that, he said he would be reluctant to endorsing a particular methodology for certifying third parties.

“I’m not sure we as the reliability regulator would want to get into any sort of third-party endorser of people selling in the market,” Gugel said. “However, if there are third-party options for providing that, we’d certainly like to be involved with it.”

FERC ordered NERC in 2016 to draft a “new or modified” standard addressing supply chain risk management for industrial control system hardware, software, and computing and network services associated with the BES. (See FERC Orders NERC to Develop ‘Flexible’ Supply Chain Standard.)

NERC responded with three supply chain standards — CIP-005-6, CIP-010-3 and CIP-013-1 — which FERC approved in October 2018. (See FERC Finalizes Supply Chain Standards.)

Staff are still accepting comment on the report. A final draft will be presented to the board in May.

Members Elect 4 Trustees to Board

The MRC elected the board’s class of 2022, filling a vacancy created to add a Canadian trustee and re-electing three incumbents to three-year terms.

Colleen Sidford will step into the Canadian vacancy. She spent 10 years with Ontario Power Generation in various financial positions, following a career in international banking.

NERC is required to have two Canadian trustees. It has three with Sidford’s election, but it is expected to reduce the number to two when Fred Gorbet’s term expires next year. That will also leave NERC with 11 trustees.

Re-elected to three-year terms were:

Robert Clarke, who has served on the board since 2013. He chairs the Corporate Governance and Human Resources committees and serves on the Enterprise-wide Risk and Nominating committees.
Ken DeFontes, a trustee since 2016. He is the liaison to the Standards Committee and serves on the Compliance and Technology and Security committees.
David Goulding, who was first elected to the board in 2010. He chairs the Enterprise-wide Risk Committee and serves on the Finance and Audit Committee.

NERC’s trustee succession policy provides that no independent trustee may be re-nominated or re-elected if he or she has served 12 consecutive years.

Ford, Sterling Step into New Leadership Positions

The meeting marked Greg Ford’s first as MRC chair. Ford, CEO of Georgia System Operations Corp., replaces Wabash Valley Power Association’s Jason Marshall, who cycled off the committee.

Jennifer Sterling, vice president of NERC compliance and security for Exelon, is serving as vice chair.

MRC Vice Chair Jennifer Sterling and Chair Greg Ford | © RTO Insider

NERC Develops Participant Conduct Policy

NERC General Counsel Charles Berardesco shared with the MRC the organization’s Participant Conduct P ol i cy, which is applicable to participants in all organization activities. The policy was based on similar rules for the NERC Operating Committee and standards development process.

However, the policy doesn’t apply to the MRC itself, Ford said. “The MRC is a creature of the bylaws,” he explained.

Berardesco said the policy will create a professional environment for all participants supporting NERC’s mission, including standing committee members and observers, drafting team members and observers, and other stakeholder volunteers that participate in the organization’s activities or groups.

The policy calls for those it covers to conduct themselves in a professional manner, not to use NERC activities for commercial or private purposes, and not to distribute confidential information or certain work products.

— Tom Kleckner

February 8, 2019October 30, 2023

Conn. Lawmakers Get, Give 2019 Energy Issues Rundown

By Michael Kuser

HARTFORD, Conn. — With fewer than four months to go in this year’s session of the Connecticut General Assembly, state regulators made their cases short and sharp Tuesday when briefing legislators on the Energy and Technology Committee.

Dan Dolan, president of the New England Power Generators Association, addresses the legislator panel at the CPES dinner in Hartford on Feb. 5. | © RTO Insider

“One of the big challenges that we face is that our wholesale electricity market is governed by FERC, and at the federal level, there has been no recognition of the need to address climate change and reduce carbon emissions through the design of the wholesale electricity market,” said Katie Dykes, commissioner-designate of the Department of Energy and Environmental Protection and chair of the Public Utilities Regulatory Authority.

Dykes, nominated to be DEEP commissioner by new Gov. Ned Lamont last month, made her remarks in a presentation to committee members and the public at an informational forum held in the Legislative Office Building.

She said that the state has had to work by itself over the past several years to ensure that an increasing volume of power is being sourced from zero-carbon and renewable resources, mainly through utility-backed contracts and state procurements.

Katie Dykes | © RTO Insider

“The challenge, though, is that in our wholesale market, we are not always getting credit for what we are procuring in these contracts and in these different mechanisms that the state has had to establish in order to correct for the failure of the wholesale markets to ensure investment in those types of resources,” Dykes said.

The urgency of climate change requires a speedy transition to a zero-carbon electric grid, while at the same time retaining units such as Dominion Energy’s Millstone nuclear plant in Waterford, which supplies a “significant share” of the region’s carbon-free generation, she said.

In December, the 2,111-MW plant was one of the winning bidders in a state solicitation for nearly 12 million MWh of zero-carbon energy, securing purchase of about half its output for 10 years. (See Conn. Zero-Carbon Awards Include Nukes, OSW, Solar.) The PURA deemed Millstone at risk for retirement without ratepayer support, which allowed its bids to be considered in terms of environmental and grid reliability benefits, as well as price.

Dykes pointed to another challenge for New England: fuel security. The region sits at the end of the U.S. natural gas pipeline system, and while the wholesale market has driven investment into natural gas-fired power plants, it has not provided the infrastructure needed to supply those plants, she said.

“So this challenge of fuel security, a very gas-dependent wholesale electricity market that is not achieving carbon reductions, has also reached a tipping point where the ISO New England is not confident … that they can maintain the reliability of that electric grid in the near term if certain units that do not run on natural gas were to retire,” Dykes said.

“Just to be explicit,” she said, ISO-NE concluded it can’t run the grid without the Millstone units, the largest power plant in the region.

The RTO’s fuel security analysis released last year actually showed the New England grid would become extremely stressed if the Millstone units were lost under a scenario of maximum retirements of coal- and oil-fired generators.

Dykes also cited a state report from a year ago that projected regional CO2 emissions would increase by 25% if Millstone retired.

Unfortunately, Dykes said, the wholesale market is not designed to value carbon reduction and fuel security benefits, which leaves the responsibility to the state.

While Connecticut has been able to procure power at good prices, “the challenges now are in respect to ISO New England, whether its leadership is acknowledging where this future is heading us … and whether they have the ability to adapt their market design to accept and help to achieve the carbon emission goals of the states and to address in a proactive manner the fuel security needs of our grid, or whether they’re going to continue to adopt a reactive posture to the states’ leadership role,” Dykes said.

CPES Hears from Legislative Leaders

Later that day, the Connecticut Power and Energy Society (CPES) partnered with the state’s bar association to host a panel discussion with the leaders of the Energy and Technology Committee at the University of Connecticut.

Day Pitney attorney Sebastian Lombardi, who represents the New England Power Pool, moderated the panel of Rep. Charles Ferraro and Sen. Paul Formica, the ranking Republican members, and Rep. David Arconti and Sen. Norm Needleman, the Democratic co-chairs.

“We need to make sure that our public utilities are accountable,” Needleman said. “We are trying to move to renewables and at the same time trying to manage rates, which seem to be pretty high in Connecticut. I have some pretty well-known issues with management decisions that Eversource [Energy] has made, but I’m going to put those on the shelf, to some extent.”

Day Pitney attorney Sebastian Lombardi moderates the panel of leaders of the Connecticut General Assembly’s Energy and Technology Committee (left to right): Rep. Charles Ferraro and Sen. Paul Formica, the ranking Republican members; and Rep. David Arconti and Sen. Norm Needleman, the Democratic co-chairs. | © RTO Insider

Needleman last month criticized the utility for asking the state to allow it to charge ratepayers an extra $150 million to recover storm-repair costs incurred over the past two years.

A local news source, CT News Junkie, quoted him saying: “If Eversource had invested in effective weather responses in the past, instead of reducing staff and equipment to save money, they wouldn’t need to ask for $150 million in repairs.”

“My priority is to not allow one bill or issue suck up all the oxygen in the room,” Arconti said, adding that technology could be a big part of the committee’s agenda given the IT background of Gov. Lamont, who has yet to announce his legislative program.

Ferraro said it was important “to keep ratepayer rates as low as possible, but still keep opportunities open for procurement of renewable energy sources and letting them come to bear by also limiting the effect of subsidies that we add on the ratepayer, because if you subsidize renewable energy, eventually somebody’s going to pay for it.”

Lombardi said it seemed legislators were striving to find a balance between protecting ratepayers and increasing investments in procurements like offshore wind, fuel cells and grid-scale solar.

Dan Dolan, president of the New England Power Generators Association, said one of the challenges is balancing how the market is structured.

“Over the years, my organization has raised a lot of concerns about carving out more and more of the market to individual resource types,” Dolan said. “How do you folks think about trying to integrate some of these different attributes within the market and be able to move away from a long-term contracting structure?” He added that NEPGA is specifically “looking at putting a more meaningful price on carbon emissions” beyond the Regional Greenhouse Gas Initiative.

“I think working with our colleagues at PURA and with DEEP … is going to be a big focus point for me,” Arconti said. “They just have way more institutional knowledge at this point when it comes to striking those balances.”

Needleman said he thought the idea of a carbon tax was more of a national issue and that he wouldn’t know how to implement it in Connecticut without making the state less competitive, “but I would certainly support it in a broad way.”

Needleman also expanded on Arconti’s point of consulting with state agencies.

“Meeting Commissioner Dykes today and listening to her blew my socks off,” he said. “She’s very knowledgeable, and I think [Arconti] is right that we have to follow the institutional knowledge. In some of the presentations we’re hearing about offshore wind, they’re comparing it to other forms of generation and emphasizing that we are a coastline state and that we have the perfect area to launch a lot of work and reap the benefits.”

Offshore Wind Base

Asked what single issue he would focus on more than any other, Formica replied that he would try to make the Port of New London part of the supply chain for the growing offshore wind industry in the Northeast.

“With no overhead obstructions, it puts itself in good position to be a base of operations for offshore wind,” Formica said. He recounted how years ago he had served “on a regional rail committee that created a freight line from that pier moving north” through the state and all the way to Montreal.

“There’s going to be $30 million to $50 million invested in the New London pier specifically to accommodate wind,” and if the state can establish some assembly or manufacturing plants for turbine components up north it could take advantage of the economic opportunities in renewables, he said.

Ferraro said people talk about New London, but “we also have offshore wind capability in Bridgeport. … Once those industries are up and running, it’s going to make sense to have the large components — the wind turbines — made right here in Connecticut in the ports, instead of shipping them from a place like Denmark, which would bring jobs and economic development to our state.”

February 8, 2019

Federal Judge to Review PG&E’s Wildfire Plan

By Hudson Sangree

California’s investor-owned utilities submitted enhanced wildfire mitigation plans to the Public Utilities Commission on Wednesday, as required by last year’s sweeping fire safety law, SB 901.

A federal judge said last week he’ll review Pacific Gas and Electric’s plan before deciding whether to impose more stringent probation requirements on the utility, which was convicted of six felonies stemming from a gas line explosion in 2010. (See Judge Postpones Strict Probation Conditions for PG&E.)

The utility filed for Chapter 11 bankruptcy reorganization last month, citing the more than $30 billion in claims it faces for Northern California’s disastrous wildfires in 2017 and 2018. (See Bankruptcy Only Viable Option for PG&E, Lawyer says.)

The PUC will review the IOUs’ plans and hold an all-day workshop on Feb. 13 — the start of a six-we e k process of weighing and instituting measures to prevent the type of devastating fires the state has experienced in the past two years.

Those measures include de-energizing power lines in fire-prone areas during high-risk weather conditions, according to the plans submitted by PG&E and Southern California Edison. Both utilities have been blamed for massive, deadly fires in 2017 and 2018. The utilities, in turn, have cited climate change as a major factor in the disasters.

PG&E’s wildfire mitigation plan includes enhanced vegetation management around power lines. | *PG&E*

“Our state is faced with an extended and more dangerous wildfire season that demands urgent action and coordination,” Sumeet Singh, head of PG&E’s Community Wildfire Safety Program, said in a news release Wednesday. “While California’s energy companies have a critical responsibility and role to play in reducing wildfire risk, we must all work together to keep our communities safe.”

The IOUs have had to develop annual wildfire mitigation plans since 2017, but SB 901 required them to provide more detailed safety plans and seek PUC approval for their proposals. (See California Wildfire Bill Goes to Governor.) Under the new law, the PUC has authority to pursue enforcement actions if utilities fail to comply with the plans.

Along with PG&E and SCE, San Diego Gas & Electric, CalPeco Electric, Bear Valley Electric Service and Pacific Power must participate in the PUC process.

Under Scrutiny

In PG&E’s case, Judge William Alsup, of the U.S. District Court for the Northern District of California in San Francisco, said he was considering requiring the utility to inspect its entire grid for safety issues and make repairs prior to the start of the 2019 fire season this summer, a plan he was at least temporarily dissuaded from by opposition from PG&E and federal prosecutors.

Alsup is overseeing PG&E’s probation in the 2010 San Bruno gas line explosion, which killed eight residents of a suburban San Francisco neighborhood. Jurors convicted the utility in 2016 of six felonies for failing to comply with safety regulations and for obstructing a federal investigation.

PG&E was placed on probation for five years. Alsup concluded in late January that it had violated the terms of its probation by failing to report a legal settlement for a 2017 wildfire in Northern California. He criticized the utility for its repeated safety failures and starting fires.

Whether PG&E’s fire mitigation plan will satisfy the judge or result in further probation conditions remains to be seen. Alsup said he’d take up the matter at a future date, still to be determined. The judge gave interested parties until noon on Feb. 20 to file comments with the court regarding PG&E’s fire safety plan.

That plan lays out a strategy of vegetation management, grid hardening and line inspections that goes beyond the measures PG&E began implementing in 2017 and 2018.

The company said it is expanding its power-shutoff program to include 5,500 miles of transmission lines and more than 25,000 miles of distribution lines in extreme-risk fire areas designated on the PUC’s High Fire Threat District Map.

The California Public Utilities Commission adopted its High Fire Threat District Map in January 2018. | *CPUC*

“Proactively turning off power is a highly complex issue with significant public safety risks on both sides — all of which need to be carefully considered and addressed,” Michael Lewis, senior vice president for electric operations at PG&E, said in a news release Wednesday. “We understand and appreciate that turning off the power affects first responders and the operation of critical facilities, communications systems and much more. We will only turn off power for public safety and only as a last resort to keep our customers and communities safe.”

The PUC in December opened a dedicated proceeding to examine the controversial practice of de-energizing transmission lines during high-risk periods, a practice that one commission staffer said raises a “range of concerns” for the public. (See Calif. Regulators to Scrutinize De-energization.)

Other measures proposed by PG&E include installing 600 cameras in high-risk fire areas and adding 1,300 weather stations by 2022.

SDG&E’s extensive use of cameras and weather stations — along with grid hardening and targeted power shutoffs — have helped that utility achieve one of the state’s best fire-safety records in recent years and have been cited by state officials as a model for PG&E to follow.

“SDG&E’s efforts to mitigate the risk of wildfire and enhance grid resilience began over a decade ago after San Diego experienced some of the most destructive wildfires in the county’s history,” the utility said in its wildfire mitigation plan filed Wednesday.

In its plan, PG&E did not say it would inspect its entire grid, as Alsup proposed, but that it would inspect 725,000 electric towers and poles across more than 30,000 miles of transmission and distribution lines in fire-threatened areas.

Disabling automatic reclosers, installing stronger poles and covering power lines — or putting some underground — are among the other measures PG&E submitted to the PUC.

‘Going Far Beyond’

SCE outlined a similar set of measures in its fire mitigation plan. The company proposed removing 7,500 hazardous trees, replacing conductor across 96 circuit miles and installing 7,800 fuses on unfused lines. It too plans to install additional cameras and weather stations as well as deploy “covered conductor in high fire risk areas” and explore “targeted undergrounding” of lines.

“Many of the ignitions associated with utilities are caused by objects that contact distribution power lines or conductor-to-conductor contact,” the utility said in a news release. “Covered conductor has proven to be an effective mitigation measure against these ignition sources.”

“We are going far beyond traditional good utility practices and incorporating advanced mitigation measures deployed in high fire risk regions around the world,” Phil Herrington, SCE’s senior vice president of transmission and distribution, said in a news release.

“This is an aggressive plan to protect public safety,” he said. “We are implementing a variety of additional tools and technologies to advance fire safety even further throughout our system to respond to the ‘new normal’ of year-round wildfire risk.”

February 8, 2019

FERC Declines to Re-examine White Pine SSR Refunds

By Amanda Durish Cook

FERC on Monday denied the Michigan Public Service Commission’s request to reconsider a decision over refunds associated with a two-year system support resource (SSR) agreement for an Upper Peninsula generating plant.

The PSC sought rehearing of a June 2018 order accepting MISO’s compliance filing containing a report setting out refunds for overcharges stemming from the RTO’s SSR agreement with P.M. Power Group’s White Pine natural gas plant. FERC rebuffed the request, saying it fell outside the scope of the compliance proceeding, among other issues (ER15-7 67-004).

The proceeding originated in a 2014 decision in which FERC ordered MISO to scrap its practice of allocating SSR costs on a pro rata basis to all load-serving entities in the American Transmission Co. service territory and instead assign costs to LSEs that required the White Pine, Escanaba and Presque Isle power plants for reliability. Two years later, FERC approved MISO’s plan to refund Wisconsin LSEs overcharged under the original rules of the White Pine SSR agreement. (See FERC Upholds MISO’s White Pine, Escanaba Refunds.)

MISO was authorized to end the White Pine SSR in late 2016 after ATC submitted a transmission reconfiguration plan to split a load pocket, boosting reliability in the area. (See MISO Allowed to End White Pine SSR.)

The PSC argued that MISO’s refund report was problematic on three counts, saying the refunds run “contrary to [FERC] precedent where the commission has traditionally denied refunds in cost allocation cases” and that they amount to “retroactive ratemaking,” which is prohibited under the Federal Power Act. It also contended that MISO’s corrected cost allocation methodology should only be implemented prospectively.

“MISO did not make clear it would seek authorization to impose retroactive surcharges in this proceeding until the filing of the refund report,” the PSC added.

The state regulator further argued that FERC should not have considered the refund report final while a pending appeal of three other Upper Peninsula SSR reallocation cost methodologies was before the D.C. Circuit Court of Appeals. The court has since rejected the appeal.

In denying the PSC’s rehearing request, FERC said the White Pine proceedings weren’t the place to “challenge the commission’s authority to order retroactive surcharges.”

The “Michigan commission’s challenge to the requirement for refunds and surcharges, including its arguments that the refunds and surcharges are contrary to commission precedent, the FPA, the filed rate doctrine and the rule against retroactive ratemaking, are outside the scope of this compliance proceeding and, in any event, have been rejected by the D.C. Circuit,” FERC said.

February 8, 2019

NYISO Ponders Response to Carbon Charge Shortfalls

By Michael Kuser

RENSSELAER, N.Y. — NYISO stakeholders on Monday debated the need to consider the improbable: that a proposed carbon pricing scheme could occasionally leave New York electricity consumers paying into the carbon revenue account rather than drawing from it.

ISO staff prompted the discussion with a proposal for responding to such an event in the wholesale market.

“In the unlikely circumstance the carbon residual is negative, the Tariff will include rules for allocating these carbon residual shortfalls to” load-serving entities, Ethan D. Avallone, NYISO senior energy market design specialist, told the Market Issues Working Group.

The total carbon residual represents carbon charges collected from internal generators plus those collected from imports, minus carbon payments to exports, he said. Wheel-through transactions are netted out of the total. (See NYISO Looks at Carbon Charge Tariff Impacts, Residuals.)

The graph shows how the proportional method (C) of allocating carbon charge residuals results in an equitable impact across load zones without levelizing costs. | *Brattle Group*

A negative residual would occur when carbon payments exceed carbon charge collections, which could arise when an emitting resource is on the margin while much of the energy being delivered is being provided by zero-carbon resources, Avallone said. Dispatching that marginal emitting resource for export would trigger a payment to the resource, but the ISO wouldn’t be collecting charges to cover that payment in the interval.

To ensure that benefits are spread equitably across the state, NYISO has recommended allocating carbon charge residuals proportionally to consumers across all zones, Avallone said. But in instances when it must cover a potential negative balance in the residual account, the ISO is proposing to allocate costs back to load based on load-ratio share.

Avallone said the load-ratio share methodology makes more sense than a proportional one in dealing with negative residuals. It would prevent piling additional costs on load zones with higher locational-based marginal prices and also avoid further cost shifts.

Load in zones with higher prices will already bear a higher impact from the carbon charges in their energy payment. If the proportional carbon allocation were used, those zones would also carry a higher proportional burden for a negative residual, Avallone said.

Statewide Issue

“It’s important to note that any shortfall would be a statewide issue, because the calculation includes both imports and exports,” Avallone said.

NYISO’s principal economist, Nicole Bouchez, explained that renewables tend to be on the margin upstate, but that the negative residual phenomenon would become a statewide issue when no emitting generators are producing, an emitting resource is marginal and exports are occurring, which is unlikely with the current generation fleet.

“Over time, as you get more and more renewables, it might happen more often,” Bouchez said.

Asked if the ISO had done any analysis on the shortfall issue, Avallone replied, “No formal analysis; just the observation that it is possible to be a net exporter today around midnight when you have many renewables on.”

Mark Reeder, representing the Alliance for Clean Energy New York, said the analysis could be done with data from previous multiarea production simulation runs.

“You’d have to have downstate having almost no carbon emissions to have the shortfall situation arise,” Reeder said.

Upon implementation, the ISO would expect the “majority of hours” to see a credit to load, calculated on an hourly basis, Avallone said, but some stakeholders did not like the fuzziness of the term.

Mark Younger of Hudson Energy Economics pointed out that there would be carbon revenues both from emitting resources on the margin and those running at minimum load. He said NYISO had “undersold” the statistical improbability of getting a residual shortfall, which would require payments to exports to exceed the carbon revenues from all resources in the market, an unusual occurrence. The ISO would need to show a hypothetical example of potential negative residuals occurring when exports are coupled with generators running at minimum carbon generation, he said.

NYISO’s schedule for carbon pricing calls for discussing calculating its impact on LBMP and identifying marginal units on Feb. 15, Tariff revisions on Feb. 28 and March 18, and carbon bid adjustment for opportunity cost resources on March 4. Opportunity cost resources represent carbon-free resources able to store energy and structure their bids to achieve delivery schedules during the most economic periods of the day. (See NYISO Plan Revises Treatment of Carbon-Free Resources.)