Page 1255 – RTO Insider

April 14, 2019

NYISO Draft Gold Book Shows EVs Driving Load Growth

By Michael Kuser

A draft version of NYISO’s annual load and capacity forecast shows electric vehicle usage driving a 66% increase in New York’s projected baseline peak demand growth rate over the next 20 years.

Much of that growth would occur in the second half of the study period, according to the preliminary 2019 Gold Book forecast released Thursday, which projects a cumulative electric load growth of 0.05% from 2019 to 2039, compared with the 0.03% growth from last year’s forecast. The baseline summer peak demand forecast growth rate was relatively unchanged between forecasts.

The new report presents load and capacity data for 2019-2029 and energy and peak forecasts through 2039 on a zonal basis and through 2049 on a system basis.

The baseline forecasts show the expected New York Control Area (NYCA) load, including the impacts of energy efficiency programs, building codes and standards, distributed energy resources, and behind-the-meter energy storage and solar PV.

The topline forecast, formerly referred to as econometric, shows what the expected NYCA load would be if not for these impacts, with the listed impacts added back into the baseline forecast. Both the baseline and the topline forecasts include the expected impacts of EV usage.

NYCA energy production by zone | *NYISO*

Load Reduction

Significant load-reducing impacts occur because of energy efficiency initiatives and the growth of distributed BTM resources. Much of the impact is attributed to the state’s energy policies and programs, including the Clean Energy Standard (CES), the Clean Energy Fund (CEF), the NY-SUN program, the energy storage initiative and other programs developed as part of the Reforming the Energy Vision (REV) proceedings.

NYISO staff employ a multistage process to develop load forecasts for each of the 11 zones within the NYCA. In the first stage, baseline energy and peak models are based on projections of end-use intensities and economic variables. End-use intensities specific to New York are estimated from appliance saturation and efficiency levels in both the residential and commercial sectors.

Since last April, net summer capability has increased 228 MW to 39,294 MW, reflecting 744 MW of new additions, against 373 MW of deactivations and 143 MW in decreased ratings.

Total summer 2019 resource capability in the NYCA is 42,056 MW, a decrease of 201 MW compared to the same assessment last year. The ISO credits the decrease to changes in existing NYCA generating capability, special case resources (SCRs) for demand response and net purchases of capacity from other control areas.

Total resource capability for the year includes generating capability of 39,295 MW; SCRs at 1,309 MW, up from 1,219 MW last year; and net long-term purchases and sales with neighboring control areas at 1,452 MW, down from 1,625 MW last year.

The existing NYCA generating capability includes renewable resources totaling 6,351 MW, down from 6,373 MW last year; wind generation unchanged at 1,739 MW; hydropower virtually unchanged at 4,253 MW; large-scale PV unchanged at 32 MW; and other renewable resources down to 327 MW from 350 MW in 2018.

Beyond 2019, NYCA resource capability will be affected by additions of new generation, re-rates of currently operating units and the deactivation of existing generators, the ISO says.

NYISO got more than half of its electricity production from nuclear and hydropower in 2018. | *NYISO*

Transmission Updates

The new report lists existing NYCA transmission facilities 115 kV and larger, including several new ones that came into service since the publication of the 2018 Gold Book. It also shows proposed transmission facilities, including merchant projects as well as firm and non-firm projects submitted by each transmission owner.

In 2017, NYISO’s Board of Directors selected the NextEra Energy Transmission New York’s Empire State Line proposal to satisfy the Western New York public policy transmission need, with an expected in-service date of June 2022.

The board last week selected two 345-kV transmission projects intended to address persistent transmission congestion in New York and foster delivery of renewable energy to the state’s population centers. (See NYISO Board Selects 2 AC Public Policy Tx Projects.)

The projects — part of the broader AC Public Policy Transmission Project — address transmission capacity at the Central East (Segment A) electrical interface and Upstate New York/Southeast New York (UPNY/SENY or Segment B) interface.

While both projects are expected to be in service in December 2023, neither are included in the draft Gold Book, which lists only projects confirmed by March 15. Future Gold Books will include the newly selected public policy transmission projects, the ISO says.

The ISO is taking stakeholder comments on the Gold Book at stakeholder_services@nyiso.com through April 17.

April 13, 2019

Calif. Must Limit Wildfire Liability, Governor Says

By Hudson Sangree

SACRAMENTO, Calif. — California Gov. Gavin Newsom’s “strike force” on utilities and wildfires Friday called for the state to limit the liability that utilities face when their equipment sparks destructive blazes, while reforming the Public Utilities Commission and holding Pacific Gas and Electric accountable for its repeated safety failures.

The task force’s 59-page report details a strategy to ensure that the state’s utilities “are securing our grid, hardening their resources, participating in a procurement strategy that can meet our long-term climate goals and … deliver affordable, reliable service to millions and millions of Californians,” the governor said at a press conference at the state Office of Emergency Services’ operations center.

It recommends ways to prevent the type of catastrophic fires that have killed 139 residents, destroyed tens of thousands of structures, and burned 2.8 million acres since 2017. The report says equipment owned by the state’s three large investor-owned utilities, including PG&E, has sparked 2,000 fires in the past four years.

Sections of the report deal with climate change, changing how the PUC oversees safety and holding PG&E accountable. But shielding the state’s IOUs from wildfire liability is the top priority, Newsom said.

“The most vexing public policy challenge addressed in this report is the equitable distribution of wildfire liability,” the report says. To address the issue, it proposes three potential fixes.

One is changing the state’s strict liability standard, which holds utilities liable for wildfires started by their equipment regardless of negligence. The legal doctrine, called “inverse condemnation” and enshrined in the state constitution, is based on the premise that utilities have the power of eminent domain to take private property for rights of way and are therefore strictly liable for damage to that property.

Other states have inverse condemnation on the books, but none uses it as extensively as California. Critics have said the doctrine inordinately punishes utilities and puts them in financial peril. The report recommends moving to a more common fault-based standard, under which plaintiffs would be required to show wrongdoing to recover damages.

California Governor Gavin Newsom presenting wildfire report — Gov. Gavin Newsom released his “strike force” report on utilities and wildfires at the former Mather Air Force Base on Friday. | *Calif. Governor’s Office*

The “fair allocation of wildfire damages [is] the core of this report,” Newsom said. He pointed to a chart showing a massive increase in wildfire damages in the past two years — with nearly $20 billion in 2017 and almost $25 billion in 2018.

“Who the heck’s going to pay for that? Everybody wants someone else to pay. … The person behind the curtain is going to pay for that,” the governor said. “I’m of the opinion … [that] we all have a burden and responsibility to assume the costs.”

Newsom said it would be difficult to meet the state’s ambitious green energy goals and have a reliable and affordable electric system if changes aren’t made. He said last year’s SB 901, which gave utilities some relief but left inverse condemnation unchanged, is “not enough.”

The strike force report suggests establishing a catastrophic wildfire fund or a “utility liquidity fund” financed by investors, utilities and ratepayers to pay for damages caused by wildfires. (See Does California Need a Catastrophic Wildfire Fund?)

PG&E said in a statement Friday it welcomed the strike force’s recommendations. The company’s beleaguered stock price jumped from below $19 to almost $23/share Friday after Newsom’s presentation.

Southern California Edison parent Edison International also got a boost, rising from below $62 to more than $67. Sempra Energy, parent of San Diego Gas & Electric, rose from less than $128 to almost $130.

Ratepayer advocacy groups, including The Utility Reform Network, were more circumspect in their assessment of the proposals.

“The goal of protecting consumers by making it clear that investors, taxpayers and other stakeholders must share in the costs of wildfire prevention and damage is one we are in total agreement with,” TURN Executive Director Mark Toney said in a statement. But customers “obviously can’t afford to bail PG&E out of billions in liabilities when it is negligent.”

Reform the PUC

Reforming the PUC was another of the strike force’s major recommendations.

The report recommends expanding the PUC’s safety expertise and improving its ability to review wildfire mitigation plans, conduct inspections and audits, and enforce safety standards.

It urges delegating more authority to the commission’s staff “so that judges and commissioners [can] focus on core questions of ratesetting.” The PUC has been criticized for moving slowly and lacking a sense of urgency in addressing utility safety. PUC President Michael Picker recently told lawmakers the commission is set up to slowly process rate cases, not react quickly to emergencies. (See Lawmakers Grill PUC on PG&E, Fires.)

The effort is “long overdue,” Newsom said.

Picker stood near the governor at Friday’s press conference, in an apparent show of unity, and Newsom lauded his reform efforts.

Newsom said the report’s other recommendations are contingent on changes at the PUC.

“Know that each and every one of these attaches to consideration of reforms at the Public Utilities Commission,” the governor said.

Hold PG&E Accountable

Even as it urged overhauling liability standards, the report says PG&E must account for its poor safety record and past disasters.

PG&E filed for Chapter 11 bankruptcy in January, a few months after its equipment was suspected of starting the Camp Fire, which killed 86 people and leveled the town of Paradise. The company said it was forced to seek bankruptcy protection because of the liability it faced for the Camp Fire and a devastating series of blazes in 2017. (See Bankruptcy Only ‘Viable’ Option for PG&E, Lawyer says.)

“PG&E is a textbook example of what happens when a utility does not invest in safety after numerous deadly reminders to do so over many years,” the report says. “Even today, PG&E is taking advantage of the bankruptcy process to promote the interests of investors over fire victims and other stakeholders.”

State fire investigators have determined that PG&E equipment started at least 17 of the 21 major wildfires in Northern California in October 2017. The utility remains on criminal probation for illegal conduct related to the deadly San Bruno gas pipeline explosion in 2010.

The state’s massive wildfires have strained firefighting resources. | *Calif. Governor’s Office*

The report says the state should monitor and intervene in the utility’s bankruptcy proceedings where necessary to protect California residents and “demand that a reorganized PG&E serve the public interest.” Breaking up the company ought to remain an option, it says.

“After years of mismanagement and safety failures, no options can be taken off the table to reform PG&E, including municipalization of all or a portion of PG&E’s operations; division of PG&E’s service territories into smaller, regional markets; refocusing PG&E’s operations on transmission and distribution; or reorganization of PG&E as a new company structured to meet its obligations to California,” it says.

At the press conference, Newsom said, “I just want folks to know we’re watching. … I expect the investors that are involved at PG&E to participate in the solutions, and I expect that PG&E’s going to get serious [and] no longer misdirect, manipulate [and] mislead the people of this state.

“They haven’t been good actors,” the governor added. “I know this personally. I was mayor of San Francisco, where [PG&E is] headquartered. I’m not here to beat them up, but you know the state has suffered because of their neglect and their misdirection.

“Lives have been lost,” he said.

Calls for Legislative Action

Newsom called on lawmakers to implement the report’s recommendations.

“Let’s get something big done before [the legislative] recess,” which begins July 12, he said. “I’m hopeful [the legislature] can meet this moment and meet the demand to be bold and resolved.”

Investor services have downgraded the credit ratings of PG&E, SCE and Sempra to junk-bond or near-junk-bond status because of wildfire liability worries, Newsom said. The legislature can help alleviate those concerns, he said.

“Let the folks on Wall Street know we’re not screwing around,” he said.

Newsom formed his strike force in February and asked for its members to submit recommendations in 60 days.

It was led by his chief of staff, Ann O’Leary, and included members of O’Melveny, one of the nation’s largest law firms (formerly O’Melveny and Myers), and Guggenheim Partners, a global investment and advisory firm, Newsom said. State fire officials and utility regulators were part of the team, news reports said. A complete list of members was not immediately available.

April 12, 2019

UPDATED: Most MISO Zones Clear at $3/MW-day in 2019/20 PRA

By Amanda Durish Cook

MISO’s seventh annual capacity auction cleared at $2.99/MW-day in all but one zone, a significant decline compared with last year’s nearly uniform $10 clearing price.

Zone 7 — representing the Lower Peninsula of Michigan — was the only area to deviate significantly, clearing instead at $24.30/MW-day.

MISO on Friday reported that it committed 134.7 GW worth of capacity for the 2019/20 planning year beginning June 1. The Planning Resource Auction was characterized by “lower offer prices from market participants in most of MISO,” the RTO said, but the volume of generation supply was “consistent” with the predictions from last year’s resource adequacy survey issued in partnership with the Organization of MISO States.

MISO received more than 142 GW worth of offers in this year’s auction, about 7 GW above the nearly 135-GW reserve margin requirement for June 2019 to May 2020.

“There is a surplus above our resource adequacy requirements to meet peak load,” Eric Thoms, MISO manager of capacity market administration, said during a media call Monday to discuss the results.

Market participants this year “simply offered in at a lower price” when compared to last year, Thoms said.

2019/20 auction clearing price overview | *MISO*

Having all but one local resource zone clearing at the same price is a familiar story for MISO auctions. Last year’s auction cleared at $10/MW-day, with the exception of Zone 1 — covering parts of Wisconsin, Minnesota and the Dakotas — which cleared at $1/MW-day. (See MISO Clears at $10/MW-day in 2018/19 Capacity Auction.)

Although higher than 2017/18’s single clearing price of $1.50/MW-day, last year’s $10 price tag elicited criticism from some market stakeholders as being too low. In his 2017 State of the Market report issued last June, MISO’s Independent Market Monitor David Patton said the “fundamental problem” with diminishing capacity can be traced to “the relatively low net revenues generated in MISO’s markets.” (See “Low Capacity Prices,” MISO to Address Growing Supply Shortage in New Year.)

Price Separation, Mitigation for Lower Michigan

The Monitor has reviewed and certified this year’s results but did have to enforce market mitigation for economic withholding in Zone 7. MISO said the IMM mitigated “several” offers representing about 1.5 MW, resulting in a 1 cent/MW-day impact in lower Michigan. It was the second time in the auction’s seven-year history that the Monitor had to enforce mitigation, with the first instance of enforcement occurring in 2013/14 planning year. “While IMM mitigation is rare, we’d like to note the process is working as designed,” MISO said in a statement.

Thoms said the mitigation was “interesting development.”

Speaking during a separate stakeholder call on the results Monday, Thoms said non-zero price offers, tight supply and a lower capacity import limit than last year contributed to price separation in lower Michigan. At nearly 22 GW, Zone 7 had the highest planning reserve margin requirement of MISO’s 10 local resource zones.

Michigan Public Service Commission staffer Bonnie Janssen asked if the price separation was at least in part the result of MISO no longer counting external resources towards satisfying the local clearing requirements for local zones. Thoms said the RTO would examine that as part of future presentations on the auction.

Cleared fuel type in MISO 2019/20 PRA | *MISO*

MISO also reported that more solar and wind generation cleared this year’s auction when compared to the 2018/19 planning year. The auction cleared 680 MW worth of solar, up 47% from last year, while wind capacity increased 21% to nearly 2.7 GW. The share of natural gas-fired capacity (38%) beat out coal (35%), which MISO said illustrates “the industry’s ongoing shift away from coal-fired generation and increasing reliance on gas-fired resources and renewables.”

Thoms said this auction was the first in which natural gas supplanted coal as the leading source of MISO capacity. He also called the increase in renewables capacity “significant.”

The PRA also cleared 15 GW of non-traditional resources, including demand response, energy efficiency, behind-the-meter generation and generation from external resources, compared with slightly more than 14 GW for those resource types last year. This was the first year that MISO included its newly created external resource zones in the auction. (See FERC OKs MISO External Capacity Zones, Dispute Deadlines.) Prior to its external zone creation, MISO treated external resources as if they were physically located within the nearest local resource zone. Even though external resources can clear at different prices than local resource zones, all external resource prices this year followed the $2.99/MW-day clearing price set by the planning reserve requirement.

MISO will go over more detailed PRA results with stakeholders at the May 8 Resource Adequacy Subcommittee meeting.

April 11, 2019

FERC Rejects RTO Insider Bid to Open NEPOOL

By Rich Heidorn Jr.

FERC on Wednesday rejected RTO Insider’s bid to force the New England Power Pool to open its meetings to the public and press, saying it lacked authority to act (EL18-196).

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

RTO Insider’s complaint under Federal Power Act Section 206 asked the commission to terminate NEPOOL’s role as the stakeholder body for ISO-NE or order it to adopt an open stakeholder process like those used by others. The publication filed the complaint in August in response to NEPOOL’s request to bar members of the press from joining the organization.

NEPOOL asked FERC permission to amend its rules after RTO Insider reporter Michael Kuser, an electric ratepayer in Vermont, applied to join as an End User Customer.

New Hampshire Consumer Advocate D. Maurice Kreis, a former journalist, said in a blog post he had turned his photo of Supreme Court Justice Louis Brandeis upside down in protest of FERC’s ruling. | *D. Maurice Kreis*

On Jan. 29, the commission rejected NEPOOL’s request, saying prohibiting membership based on employment was unduly discriminatory. NEPOOL is seeking rehearing of the ruling, but last month its Participants Committee agreed to admit Kuser as an End User member under strict rules that prevent him from reporting publicly on what he hears in meetings. (See RTO Insider Reporter Admitted to NEPOOL.)

NEPOOL said it sought to change its membership rules because allowing the press to join would inhibit the group’s ability to foster candid discussions and negotiations that narrow and resolve complex issues. NEPOOL also contended FERC had no jurisdiction to reject the rule change.

The commission — which said in the Jan. 29 ruling that it had jurisdiction to reject the membership rule change — ruled Wednesday that it did not have authority to grant RTO Insider’s request to open NEPOOL’s meetings to public scrutiny.

Commissioner Cheryl LaFleur did not participate in the 3-0 ruling by Chairman Neil Chatterjee and Commissioners Bernard McNamee and Richard Glick, the latter of whom filed a concurrence calling on NEPOOL to change its rules. LaFleur declined to say why she abstained.

Because NEPOOL does not own or operate facilities involved in the interstate transmission of electricity, it is not a public utility under the FPA, the commission said. As a result, it said its jurisdiction is limited to NEPOOL’s operations “only insofar as they directly affect jurisdictional rates.”

In the Jan. 29 ruling, the commission said it found that rules governing NEPOOL membership “directly affect what filings the commission receives pursuant to FPA Section 205” because they dictate who may vote on proposed ISO-NE filings and NEPOOL-originated “jump ball” proposals.

“However, NEPOOL rules prohibiting press and public attendance at NEPOOL meetings do not directly affect such filings because they do not affect who may vote on NEPOOL proposals. Only NEPOOL members may vote on proposed ISO-NE filings and NEPOOL-originated ‘jump ball’ proposals. As nonmembers, the press and public could not vote on such proposals or speak in support or against such proposals even if they were to attend NEPOOL meetings,” the commission said. “Therefore, rules governing only attendance at NEPOOL meetings do not directly affect the filings brought before the commission in the way that membership rules that allow members to vote do.”

The commission also rejected arguments that press coverage of NEPOOL meetings could ease the burden of monitoring NEPOOL activities for smaller or prospective members.

“We are not convinced that easing the burden of monitoring these meetings can directly affect the outcome of NEPOOL proceedings. Even if reporting eases the burden of participating in NEPOOL, it does not enable participation; therefore, any effect it may have on jurisdictional rates is indirect,” the commission said.

Glick: Change the Rules

In his concurrence, Glick said that while he agreed with his colleagues on the jurisdictional issue, NEPOOL’s membership policies are “misguided” and should be changed.

“NEPOOL meetings address a broad range of important issues, including, among other things, the reliability of the electric grid, state policies for addressing climate change, and the integration of new technologies into the resource mix. The public and, by extension, the press have a legitimate interest in how NEPOOL, the entity charged with administering ISO New England’s stakeholder process, is considering these matters of public interest.

“Although I appreciate NEPOOL’s concern about preserving a forum for candid discussion, I am troubled by NEPOOL’s apparent belief that closed-door meetings with no opportunity for public involvement or education through the press furthers the mission of the stakeholder process or the broader interests at play in these proceedings,” Glick continued. “To paraphrase Justice Louis Brandeis, sunlight is the best disinfectant, and it is hard for me to understand how barring public and press scrutiny will further NEPOOL’s mission or, ultimately, its legitimacy as the forum for considering how ISO New England’s actions affect its stakeholders. Rather than trying to hide their discussions from the public, NEPOOL and its members would be better served by permitting public and press attendance, so that all entities — including those that cannot spend the time or money needed to attend all NEPOOL meetings — can remain informed of the discussions regarding the important issues under NEPOOL’s purview. That result would lead to a more robust discussion of the issues and, ultimately, to better public policy.”

New Hampshire Consumer Advocate D. Maurice Kreis, a former journalist, said in a blog post he had turned his photo of Brandeis upside down in protest of FERC’s ruling, which he said “hobbles my ability to participate in NEPOOL effectively.

“There are 15 days of NEPOOL meetings on the calendar for April. … If you’re a big transmission owner like Eversource or a big generation conglomerate like Exelon (owner of Mystic Station), you have the resources to staff all of these NEPOOL meetings as necessary. My tiny organization — we have five employees and a bit of consulting help — does not.”

“NEPOOL is a gentlemen’s club straight out of the 1880s, a time when financiers like J.P. Morgan determined the course of the U.S. economy behind closed doors,” he added. “… NEPOOL is doing the public’s business and its meetings should therefore be public.”

While the two cases were pending, six members of New England’s Senate delegation and a dozen members of the House of Representatives called on the commission to open the meetings. (See New England Senators Urge FERC to End Press Ban.)

Gag Rule

NEPOOL’s Participants Committee conditioned Kuser’s admission on compliance with its bylaws, which were rewritten in June 2018 in response to his application.

NEPOOL said the revisions were intended to codify a longstanding practice barring disclosure of meeting proceedings to nonmembers. But they also appear to carve out an exception for members who are not members of the press.

Section 5.6(a)(ii) states that:

“Attendees may use the information received in discussion, and may share the information received within their respective organizations or with those they represent, provided those who receive such communications are not press and also are aware of and agree to respect the nonpublic nature of the information. In no event may attendees reveal publicly the identity or the affiliation (other than sector affiliation) of those participating in meeting discussions…”

Members who violate the provision, the bylaws state, will have their attendance privileges revoked.

April 11, 2019

PJM Operating Committee Briefs: April 9, 2019

Two substation fires that occurred earlier this year revealed weaknesses in utilities’ incident response procedures and command structures.

Donnie Bielak, PJM’s manager of reliability engineering, presented a Feb. 28 “Less o ns Learned” report by NERC to stakeholders Tuesday. The report did not disclose the location of the incidents.

PJM Operating Committee Chair Dave Souder and Anisha Fernandes, who served as secretary of the April 9 meeting | © *RTO Insider*

In the first case, an arc flash on a closed 12-kV feeder circuit breaker cabinet in an enclosed substation sparked a fire. Four technicians at the scene heard the explosion, evacuated and called 911 after determining the third-party alarming system had not yet contacted emergency authorities.

Bielak said it was unclear which of the technicians should have served as incident commander, hampering effective communications with firefighters. A dead secondary battery for the substation card reader also forced first responders to break into the facility, despite existing rules that no one enter the facility without an escort.

In the second incident, a 230-kV transformer high-side bushing failed in an outdoor substation. Bielak said responding utility and fire department personnel arrived without the proper equipment for transformer fire suppression.

Corrective actions for utilities include:

Implement policy that the first person to discover a fire must report it via 911 regardless of any central station monitoring that may be present.
Perform a review of the effectiveness of the fire entry procedure for indoor substations and update it as appropriate along with the applicable training.
Expand the fire entry procedure to include situations in which qualified personnel could already be present at the site. This procedure should identify who is the incident commander, who must call for the fire department, and what assistance, if any, do company personnel provide the fire department.
Review fire entry requirements with the fire department to clarify the requirement that utility personnel should not enter the building prior to the fire department declaring the building safe.
Coordinate with the fire department to establish the practice of immediately mobilizing a foam unit in the case of substation and switchgear fires, whether indoor or outdoor.
Ensure expectations from the fire department are understood and documented on what assistance company personnel are supposed to do.
Ensure additional equipment inside the substation is maintained.
Ensure fire alarms at all substations work on the operator human machine interface (HMI) screen and are audible.

Drones Deployed to Save Money, Time

Bielak said drone usage is growing across the RTO as companies use the devices in place of helicopters to survey major storm damage, identify line repairs and inspect power plants, wind farms and gas pipelines, among other uses.

The drones save time and money, Bielak said, and have provided essential support during storm recovery. In the aftermath of Hurricane Maria, a drone was used to string lines between structures on either side of uncrossable terrain in Puerto Rico.

The technology has its limitations, however. Short flying times of 20 to 45 minutes prevents long-distance transmission line inspections and government regulations complicate where drones can fly safely.

Spring Restoration Drill Invites Sent

PJM’s Alpa Jani told the committee that invitations for the 2019 spring restoration drill went out April 3.

System restoration coordinators and transmission and generator operators with nuclear units, black start units and units with a hot start-up time of four hours or less received an email mandating participation in the systemwide drill on May 21 and 22. Recipients must complete the exercise in compliance with NERC standards.

Coordinators schedule the exercise twice a year and participation is required once every two years.

Manual First Reads

While there were no endorsements scheduled for Tuesday’s meeting, members heard first reads of several manual revisions, including:

Manual 1: Periodic cover-to-cover review to update terminology and guidelines for control center and data exchange requirements.
Manual 3: Biannual revi e w to update transmission operating procedures.
Manual 10: Clarifies existing language for prescheduling operations.
Manuals 11, 13 and 28: Clarifie s the impact of operationalizing gas contingencies on reserve requirements and reserve market eligibility.
Manual 13: Periodic cover-to-cover review and changes to align with new Markets Gateway functionality for resource-limitation reporting to be implemented June 1.
Manual 36: Annual update requirement.

– Christen Smith

April 11, 2019

PJM to Hold Capacity Auction in August

By Christen Smith

VALLEY FORGE, Pa. — PJM will move forward with its August capacity auction under current market rules, unless FERC says otherwise, CEO Andy Ott told stakeholders Wednesday.

Ott said the PJM Board of Managers settled on that course after determining the RTO’s minimum offer price rule (MOPR) — rejected last year by FERC — impacts only a small number of resources, meaning an updated commission ruling on the matter wouldn’t change prices too much within the current environment.

“We think this is the best approach,” he told the Market Implementation Committee on Wednesday. “There is no way to get absolute certainty. This was not an easy decision.”

PJM filed a request with FERC later that day seeking validation that the commission would not force the RTO to rerun the 2022/23 Base Residual Auction under new rules in the future — an outcome that stakeholders want to avoid at all costs.

“We’re trying our best to provide a path forward that provides as much clarity as we can,” Ott said.

The decision comes three weeks after PJM staff presented the Markets and Reliability Committee with four options for the August BRA, including: doing nothing and running the auction under current rules; filing a delay waiver; filing a request to confirm existing rules for the interim; or proposing an interim rate. (See PJM Mulls Options for August Capacity Auction.) Each option came with considerable drawbacks, PJM’s Stu Bresler said at the time.

PJM delayed the BRA once already after a June 2018 FERC ruling determined its MOPR was unjust and unreasonable because it didn’t address price suppression arising from state subsidies for renewable and nuclear power. The RTO proposed a new rate in October and had hoped for a ruling from the commission by March 15 to no avail.

Ott said Wednesday many stakeholders expressed support for moving ahead as planned. The Electric Power Supply Association said in a press release that the RTO made the right choice and will boost much-needed investor confidence. The group also called on FERC to protect the capacity market from the distortions of nuclear subsidies and those who benefit from them.

“EPSA opposes delaying the 2019 auction to 2020,” the group wrote. “This is merely an attempt by some to buy time to continue seeking costly subsidies. Such out-of-market payments erode PJM’s markets at the expense of consumers and competition.”

Jason Barker of Exelon called the chosen path “short-sighted.” Exelon joined a coalition of utility companies in a letter to the board requesting a delay until April 2020, citing seven outstanding FERC dockets. Consumer advocacy groups from six states likewise sent their own letter pushing for a delay. (See Stakeholders Tell PJM Board to Delay Capacity Auction.)

“We think the path that PJM is taking will make FERC address the underlying subject of MOPR, which they’ve been reluctant to do so far,” he said. “Why is the balance of interest better served by this path than just the delay?”

PJM spokesman Jeff Shields said the RTO remains obligated to run the BRA and, given the uncertainty, staff decided it was best to move forward under existing rules.

“Certainty is needed and we simply don’t know when FERC is going to act,” Shields said. “We don’t even know whether FERC will respond to this request for clarification or would have responded to an additional request for delay.”

April 11, 2019

Judge Puts off Decision in PGE v. FERC

By Hudson Sangree

A federal judge asked lawyers Wednesday to find common ground in a case that has pitted Pacific Gas and Electric against FERC in a conflict over billions of dollars in power purchase agreements that the bankrupt utility has said it might try to modify or cancel during its Chapter 11 reorganization.

Judge Dennis Montali, of the U.S. Bankruptcy Court in San Francisco, asked the attorneys to take two weeks to determine if they can “unring the bell” that was rung when FERC declared in January that it shared jurisdiction with the court in deciding the fate of the wholesale power contracts.

Theodore Tsekerides | *Weil, Gotshal & Manges*

PG&E’s lawyer, Theodore Tsekerides, told the judge he thought a compromise was unlikely. The New York-based litigator, of Weil, Gotshal & Manges, argued strenuously for Montali to impose a permanent injunction against FERC that would prevent it from interfering in the bankruptcy case. He said the bankruptcy code governed the matter, not the Federal Power Act, as FERC contended.

Attorneys for FERC and the wind and solar generators under contract with PG&E argued against an injunction but said a compromise might be possible. FERC’s attorney said he would need to ask for the commission’s approval.

Montali suggested to the attorneys that FERC might somehow soften or change the language in its Jan. 25 order to remove the apparent conflict between the court’s authority and the commission’s jurisdiction.

“Have we got a deal here?” Montali asked the lawyers half-jokingly at one point in the two-and-a-half-hour proceeding. They said they didn’t but were willing to work on it.

The case began in January, when NextEra Energy and Exelon, two companies that have PPAs with PG&E, asked for FERC’s help in anticipation of PG&E trying to reject the agreements in bankruptcy.

PG&E’s efforts to obtain an injuction against FERC center on its renewable power purchase agreements.

In response, FERC declared it shares authority over PG&E’s wholesale PPAs with the bankruptcy court. (See FERC Claims Authority Over PG&E Contracts in Bankruptcy.)

PG&E then moved for an injunction blocking FERC from meddling in its bankruptcy, which was brought about by the utility’s potential liability for billions of dollars in wildfire damages. (See Bankruptcy Only ‘Viable’ Option for PG&E, Lawyer says.)

To comply with the state’s renewable power requirements, the utility entered into contracts that were far pricier than they would be today, when wind and solar are among the lowest-priced electricity sources. The utility said it has 387 PPAs with 350 companies worth about $42 billion. (See PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy.)

The PG&E v. FERC matter, known in court as the adversary proceeding, is distinct from, but closely linked to, PG&E’s bankruptcy case. Over FERC’s objections, a U.S. district court judge ruled last month that the adversary proceeding should remain in Montali’s court for the sake of judicial efficiency. (See Judge Sides with PG&E over FERC in PPA Dispute.)

Judge Dennis Montali | *Commercial Law League of America*

Montali wrote to the judge in that case, saying the “plain language” of Section 365 of the bankruptcy code could answer “the question of whether FERC can decree that [the code section] must be construed to permit FERC to second-guess the bankruptcy court and impose its own decision on that court.”

Montali has not said if he intends to enjoin FERC or dismiss PG&E’s request for an injunction. However, he repeated his view Wednesday that it would be best to issue a permanent injunction, rather than a preliminary one, if he chooses that route.

A preliminary injunction would require a trial to determine if a permanent injunction is warranted and would consume time and energy when there may be no facts in dispute, Montali said. Issuing a permanent injunction would allow FERC to quickly appeal the matter to the higher court, he said.

April 11, 2019

MISO Signals Readiness for DER Stakeholder Process

By Amanda Durish Cook

CARMEL, Ind. — MISO will kick off discussions on distributed energy resources policy after it this month completes a third round of stakeholder workshops on integrating DER into its system, the RTO said this week.

Over the next decade, MISO expects to confront increased volumes of DERs that will “likely challenge utility staff and processes” with possible two-way flows of electricity on the distribution system.

Those challenges were the topic of an April 9-10 workshop that nearly concludes a series of educational sessions hosted by the MISO and the Organization of MISO States.

Discussion groups at the MISO DER workshop at the Renaissance Indianapolis North Hotel in Carmel, Ind. | © *RTO Insider*

The events are a precursor to MISO bringing discussion of DER market rules into its stakeholder process as RTO leaders prepare for a possible MISO Contemplates DER Effect, Possible Rules.) MISO will host identical sessions April 17-18 in Little Rock, Ark., and April 24-25 in Eagan, Minn.

MISO staff said they would use input from the final workshops to set policy-level discussions with stakeholders on DER integration.

MISO DER project manager Kristin Swenson said once the workshops are complete, MISO may assemble stakeholders for periodic “debriefs” on what aspects of DER integration MISO might address first.

Swenson also said the RTO is trying to forge deeper connections with distribution utilities after it encountered difficulties assembling a large group of distribution operators for the early April event.

“MISO does not have deep connection with the distribution operators in our footprint. Our main connections are with our transmission operators,” Swenson said, adding MISO might consider holding more local meetings “to move the conversation to them.” She also asked stakeholders in the room for suggestions on how best to involve distribution operators in the DER conversation.

Breakout Session

Attendees broke into groups to consider several DER integration questions with the caveats that representatives from the same companies not sit together and that state regulators not share tables with representatives from the utilities they oversee. Participants observed Chatham House Rules, not attributing discussion points to specific individuals or companies. The idea, MISO representatives said, was to encourage free conversation.

MISO asked the roughly 50 attendees to discuss modeling behind-the-meter generation and how to best approach DER deployment in load forecasting and long-term DER planning assumptions. It also asked distribution operators how they approach generation interconnection on the distribution level and the funding of distribution upgrades, as well as how they might manage reverse flow congestion, real power flow patterns and phase balancing issues.

The RTO also prompted distribution companies to consider how they might alter their under-frequency and under-voltage load shed schemes under circumstances in which the schemes could shed generation as well as load.

Workshop attendees said distribution utilities will need to create interconnection protocols and facilitate a three-way communication system among the DERs, themselves and the grid operator. Many MISO members predicted distribution utilities will become mini system operators themselves. Others said distribution utilities themselves will need better visibility into their own operations before they can hand off DER information to MISO. Some distribution representatives probed MISO on what level of detail it could handle in terms of DER data submissions.

Other participants said MISO should determine when utilities might come to rely on DERs, though some allowed that long-term DER load forecasting is a difficult process. Attendees said MISO must factor in economics, weather patterns and unusual weather and state policies when forecasting DERs for planning. Some added MISO should hire an in-house meteorologist to better predict when certain DERs will be in use.

If DERs are to become market resources in MISO, the resources should be prepared to supply the RTO with the same types of information required of traditional resources, many attendees agreed.

Break with Tradition?

MISO adviser Robert Merring said significant DER penetration could prompt MISO to expand reserve requirements. He also noted that essentially “uncontrolled generation” could further impact transmission constraints.

“Our traditional way of doing business — we plan for an annual peak and we’re good — may no longer work. Those load profiles are changing,” he told attendees.

With significant solar generation on the system, MISO could also experience “huge ramps at sunset,” Merring said. “They have one heck of a race at sunset to cover their ramping needs,” he said of CAISO.

Merring added MISO today has an “amazingly small” amount of regulating reserves, with the RTO handling virtually all load through its energy market.

Merring said while an abundance of low-cost gas has put a “squeeze” on coal profitability in the footprint, distribution-level generation could soon take its turn in driving down price.

“We’re not seeing a slow-down in distributed resources buildout. If that continues, we’re going to see continued revenue constraints on the traditional fleet,” he said.

Merring concluded with a point salient for most stakeholders: As an increasing volume of load is served by DER generation that bypasses the MISO wholesale market, the RTO’s remaining load could be forced to shoulder more of the cost burden for the system.

April 11, 2019November 5, 2023

Europe Sees Dollar Signs in East Coast Waters

By Rich Heidorn Jr.

NEW YORK — With 30 MW installed, the U.S. has barely dipped its toes into offshore wind. Europe, which has been harvesting its ocean breezes since the 1990s, has 18 GW.

But based on the Scandinavian, German and British accents at the Grand Hyatt in New York this week, a lot of people in the European OSW industry believe the waters off New England and the Mid-Atlantic states are the next big thing.

More than 1,100 attendees crammed into the Hyatt’s ballroom next to Grand Central Station for the Business Network for Offshore Wind’s 2019 International Partnering Forum — double last year’s attendance, according to the group’s CEO Liz Burdock.

The excitement is largely based on pledges by New York and Maryland since January that have boosted the East Coast’s planned OSW pipeline to almost 18 GW from 10 GW in 2018.

“In our view, the Northeast U.S. is the most attractive opportunity for the expansion of offshore wind outside of Europe,” said Sunny Gupta, head of new market development for Danish-owned Ørsted U.S. Offshore Wind.

Gupta recalled that at his first meeting with the fledgling business network about eight years ago, no more than 40 or 50 people were in attendance. “Here we are today with IPF 2019 — four years straight sold out — in a big fancy hotel in midtown Manhattan,” he marveled. “Not many people get to say they helped create an industry, so this is indeed a very unique moment in all of our lives.”

“It feels good to say it’s no longer a question of when offshore wind will ever come to the U.S.,” agreed Gupta’s boss, Ørsted U.S. Offshore Wind CEO Thomas Brostrøm. “Because now it is here, and I think the question is more: How much potential do we actually see? How big can this industry become?”

Eric Thumma, director of policy and regulatory affairs for Avangrid Renewables said the IPF conference reminded him of his introduction to land-based wind power in Los Angeles in 2007. The U.S. has since grown from less than 17 GW to more than 96 GW of land-based wind, he noted. (See AWEA: Another Record-Breaking Year for Wind Industry.)

New York Gov. Andrew M. Cuomo jolted the market in January by proposing the state nearly quadruple its offshore wind energy goal to 9 GW by 2035. (See New York Boosts Zero-carbon, Renewable Goals.)

Richard Kauffman, chair of the New York State Energy Research and Development Authority, said the response his agency received to its first, 800-MW solicitation for offshore wind is proof the industry is taking the U.S. market seriously. Four groups of companies entered 18 bids; NYSERDA is expected to announce the winners in about a month. (See Four Bidders Vie for NY Offshore Wind Project.)

“Offshore wind on the East Coast of the U.S. has gone from being a distant dream to a huge market opportunity,” Kauffman said.

New Jersey Gov. Phil Murphy said the Board of Public Utilities will announce the results of its 1,100-MW solicitation by the end of June.

“We have a lot of lost time to make up,” said Murphy, a Democrat who revived the state’s OSW plans after taking office in 2018. Murphy replaced Republican Gov. Chris Christie, who had not supported the initiative.

Murphy noted the state issued its OSW plan in 2010. “But for seven-and-a-half years that plan sat on a shelf collecting dust. That was just one of many oversights by the prior administration that stymied our progress as a state.”

Also adding to momentum was the Maryland legislature’s April 8 approval of a bill (SB 516) that boosted the state’s offshore wind target to 1,200 MW by 2030, up from 366 MW.

Burdock said the pressure is now on the industry to show it can execute the development plans on schedule. Some 1,800 MW is targeted to be built and operating by 2023.

“So, we are under [a] severely compressed timeframe,” she said. “That is one of the reasons why I stay awake at night. The one thing I worry about is supply chain capacity. Do we have enough businesses?”

Lessons from Europe

How much the U.S. could, or should, take from Europe’s experience was a recurring theme at the conference.

The U.S. Bureau of Ocean Energy Management (BOEM), which oversees OSW development in federal waters, met with counterparts from nine countries this week to share experiences and best practices. BOEM Acting Director Walter Cruickshank said it was the first of what will be an annual forum of global OSW regulators.

Gil Quiniones, CEO of the New York Power Authority, said the U.S. will be looking to the Europeans for guidance for the foreseeable future. While New York hopes to have 9 GW of OSW by 2035, Europe is expected to expand from its current 18 GW to 60 GW by 2027. “So, we are going to learn a lot from the Europeans as this journey happens,” he said.

“The U.S. can learn a lot from the U.K. experience in particular,” said Ørsted’s Gupta. “The U.K. was not the original wind market in Europe, but it quickly became the largest player, and governments made significant investments knowing that is what it would take to attract [a] supply chain. The result of that has been an achievement of significant local content [production] in the U.K. — not only for their own projects but now they’re exporting that technology to other European countries and indeed to emerging markets.”

Gupta said the takeaway is “Don’t do it small. And focus on what you’re good at.”

Still, he acknowledged some lessons won’t translate. “The U.S. is very different … [from] state and federal permitting to the way transmission works, the way the energy market works in general here, there’s only so much you can draw from the European experience.”

Sven Utermöhlen, a board member for E.ON Climate & Renewables GmbH, said there is no one model to follow. “I think you really have to cater it to the specific situation in terms of coastline, number of suitable connection points, number of windfarms and geographical situations.”

April 11, 2019

PJM MIC Briefs: April 10, 2019

VALLEY FORGE, Pa. — PJM on Wednesday proposed an alternative stakeholder process to implement the market rule changes recommended in a special report on the RTO’s role in the GreenHat default.

Last month, three independent consultants completed a six-month probe into how a small trading shop amassed the largest portfolio of financial transmission rights in PJM history without the collateral to back it up, ultimately blaming naïve staff and underlying market flaws for the 890 million-MWh default that could cost members up to $430 million. (See Report: ‘Naïve ’ PJM Underestimated GreenHat Risks and PJM: FERC Order Could Boost GreenHat Default b y $300M.)

CEO Andy Ott told the Market Implementation Committee on Wednesday he will oversee organizational and procedural changes within PJM itself but will rely on stakeholders to guide the process for market rule changes.

“We are going to suggest a stakeholder process to you all,” he said. “We think the current process may not be the best approach. Let me be clear, it’s a suggestion.”

PJM’s suggesti o n is to create a Financial Risk Management Senior Task Force that will assemble beginning May 2 to begin the overhaul of credit and risk management requirements, market design, membership qualifications and processes and the stakeholder process itself.

PJM’s Dave Anders wants the Markets and Reliability Committee (MRC) to approve staff’s proposed cha r ter for the task force at its April 25 meeting so an educational session can commence in May. Staff will present their own observations at a May 13 meeting and propose foundational questions for thoughtful discussion over the following two weeks. The task force will then create a work plan and develop packages that produce the report’s recommendations for the Board of Managers to consider at its Dec. 4 meeting.

“Our stakeholder process is a strong one, but it’s not always the most efficient,” Anders said. “We believe we need to adapt the process to provide more efficiency.”

ORDCs Shrink in Updated Energy Price Formation Simulation

A late-stage change to how PJM treats expected generation outages resulted in a smaller Operating Reserve Demand Curve (ORDC) in the RTO’s energy price formation simulation.

PJM’s Adam Keech said changing unit commitment based on real-time instead of day-ahead markets increased locational marginal prices, boosted energy revenues and cut uplift by more than 80% compared with the status quo.

“It’s not exactly what real-time is but it’s the closest we can get to what real-time would be,” he said. “We stayed toward real-time because we think that’s the best tool we have and gives us the best approximation we can get.”

Likewise, implementing a 30-minute reserve market and PJM’s proposed ORDC increased LMPs by an average of $0.46 MWh, assigned an additional 1,350 MWh of synchronized reserve and 3,337 MWh of secondary reserve and generated $550 million more in total energy and reserve market revenues, Keech said.

FTR Forfeiture Calculation Change Endorsed

Stakeholders endorsed calculation changes for financial transmission rights forfeitures on Wednesday.

Brian Chmielewski, manager of market simulation, said PJM and the Independent Market Monitor agreed the current forfeiture rules should be adjusted because they do not distinguish between on-peak and off-peak FTRs. (See “First Read on Change to FTR Forfeiture Calculation” in PJM MIC Briefs: March 6, 2019.)

FTR forfeitures are intended to discourage traders from cross-market manipulation. Holders subject to forfeiture are credited for the hourly cost of the FTR. Under current rules, a $1,500 off-peak FTR for June 2018 would be credited an hourly cost of $2.08, equivalent to $1,500 divided by 720 hours (30 days x 24 hours). Under the endorsed change, the FTR cost would be divided by only 384 off-peak hours, increasing the credit to $3.91.

The proposal will now advance to a first read at the April 25 MRC. PJM hopes to implement the changes in the third quarter of 2019.

MIC Will Work IARR Funding Flaw

Chmielewksi told the MIC last month underfunding of interregional incremental auction revenue rights (IARRs) may occur because MISO’s process cannot guarantee future firm flow entitlements on upgrades consistent with PJM’s rules. (See “Incremental Auction Revenue Rights Funding” in PJM MIC Briefs: Ma r ch 6, 2019.)

IARRs are granted to the customer only if the transmission improvement provides additional capacity that makes the request feasible. PJM guarantees that awarded IARRs are at least 80% of studied IARR megawatts. Any portion of the FFEs for an affected coordinated flowgate that is less than 80% of the IARR megawatt total will result in inadequate FTR revenues, the RTO has found.

PJM wants stakeholder work completed by Aug. 1 to allow implementation of the new rules for the 2020/21 planning period.

Gas Contingencies on Reserves Spur Manual Changes

PJM will upd a te Manuals 11 and 28 to clarify the impact of operationalizing gas contingencies on reserve requirements and reserve market eligibility.

“In the existing manual language, based on the triggers that are defined for how PJM identifies a gas contingency, there’s language in there that says very broadly that PJM would increase reserve requirements either in day-ahead or real-time to address the need for reliability for gas contingency,” said PJM’s Natalie Tacka. “So this just clarifies how we would do that.”

The MIC will be asked to endorse the revisions in May.

RT SCED Process Lacks Transparency, Monitor Says

PJM’s Independent Market Monitor wants stakeholders to review processes for real-time security constrained economic dispatch (RT SCED) and pricing that PJM uses in the energy market to send dispatch signals to generators and calculate LMPs.

The monitor presented a problem state m ent to the MIC and asked for feedback from stakeholders about the status quo. The IMM raised questions surrounding RT SCED case execution and approval processes, who approves the SCED cases, what criteria PJM uses to approve RT SCED cases and what criteria PJM uses for selecting cases to be used in the locational pricing calculator (LPC). Manual language should be updated to reflect the answers to these questions, the monitor said.

“This is all good stuff ,and we as a company, as a stakeholder, have been pushing for greater transparency,” said Gary Greiner, of PSEG. “More of an open kimono where we understand the dispatch decisions that are getting made.”

Lisa Morelli, PJM’s real-time markets operations manager, said staff would be open to exploring the issue further.

“We are certainly supportive of providing education in these areas and take the conversation from there,” she said.

NYISO and PJM Agree to New Flowgate Type

NYISO and PJM will rev i se their Joint Operating Agreement to create a new flowgate type for the East Towanda-Hillside 230-kV tie line.

The RTOs will classify the line as an “other coordinated flowgate,” defined as a flowgate where constraints are jointly monitored and coordinated for reliability purposes but are not settled on due to a lack of impactful dispatchable generation on the non-monitoring system.

The ISO and PJM last September filed with FERC a joint request for waiver of the JOA to permit them to add the East Towanda-Hillside tie line as a market-to-market (M2M) flowgate. The requested waivers enable PJM to temporarily conduct redispatch operations to control flows to the more restrictive rating on the NYISO side of the line without violating its Tariff while the grid operators work to develop a permanent solution. The commission granted the waiver in November. (See “NYISO, PJM Revising JOA for Tie Line Issues” in NYISO Business Issues Committe e Briefs: March 13, 2019.)

– Christen Smith