Page 1053 – RTO Insider

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

April 9, 2019

AWEA: Another Record-breaking Year for Wind Industry

By Tom Kleckner

The American Wind Energy Association’s (AWEA) annual market report on the wind industry, released Tuesday, marks off one record achievement after another.

U.S. wind capacity grew another 8% last year, helping the industry support a record 114,000 jobs, more than 500 domestic factories and more than $1 billion a year in revenue for states and communities hosting wind farms.

Credit that to the 2020 wind-down of the production tax credit, said AWEA CEO Tom Kiernan.

But how does the end of tax credits help the wind industry if that means it becomes one of the few energy sources without some sort of tax support?

Kiernan said the 2015 extension of the PTC, which included a phased end of tax credits, provided the certainty the wind industry needed after years of on-again, off-again legislation in Washington, D.C. He said the “longer-term policy” was just what AWEA had been looking for, as it created an incentive for further investment in the industry and its technologies.

Kiernan said major turbine designers have all announced new designs, adding longer blades, newer technologies, digitization and “other factors that will continue to increase our productivity.” Noting developers have added roughly 8 GW of wind energy each year since 2015, he said he expects the growth to continue, if not increase, over the next few years.

“Because of that long-term policy, [wind] companies have been able to make investments and keep driving down costs,” Kiernan said. “After the PTCs phase off, there will probably be a softening, but because of that five-year horizon, we’ll be two to three years into our next product cycle. We still think we’ll be able to compete with solar, storage and gas.”

AWEA projects a “record amount” of wind generation to come online in the near future. It says more than 35 GW of capacity is either under construction or in advanced development across 31 states.

‘Americans Want It’

Wind energy now stands at 96.4 GW of cumulative installed capacity, more than double what it was in 2010. AWEA says the United States now has enough installed wind energy to power more than 30 million homes. According to the report, wind energy now “reliably delivers” more than 20% of the electricity produced in six states: Iowa, Kansas, Maine, North Dakota, Oklahoma and South Dakota.

Kiernan attributed the growth to corporate and industrial purchases of wind energy — 11.3 GW of clean wind energy because “Americans want it” — and utility purchase agreements.

“Fifty percent of Americans are more likely to buy products from a company that purchased wind energy,” Kiernan said, citing a Yale University p oll. “Wind energy is the cheapest source of new electricity on an unsubsidized basis. Utilities are buying it because it’s clean but also affordable.”

To ensure the momentum continues, Kiernan said AWEA is encouraging the continued advancement of tax-abatement policies and other legislation at the state level, while asking for a focus on transmission infrastructure at the federal level.

“Our transmission grid is outdated and not built out to provide clean energy sources for the future,” he said, drawing comparisons to the interstate highway system. “We’re asking Congress to do a better job of permitting transmission, and we’re calling on FERC to do the interregional planning.”

Kiernan said transmission should be a key element in any infrastructure package Congress is working on, and it should include an element “requiring FERC to call on RTOs to do joint planning.”

“[Planning] should be done the same way and at the same time in addressing joint projects,” he said. “Connecting these different grids will allow more efficiency in connecting wind projects to the grid.”

Success in Texas

AWEA officials chose to announce its annual market report in Texas partly because Houston will be the site of its May 20-23 WINDPOWER Conference and E xhibition, billed as “the Western Hemisphere’s largest gathering of the people and technology driving wind power trends.”

But Texas is also a “living, breathing example of what’s happening nationally,” Kiernan said.

AWEA says if Texas were a country, it would rank fifth globally in wind energy capacity, with nearly 25 GW of installed capacity. Texas is home to about a quarter of the nation’s wind capacity, and the 7 GW of additional projects under construction or in advanced development is more wind than all but two other states have installed.

The state’s Competitive Renewable Energy Zones transmission buildout, which connected West Texas wind farms with urban population centers, serves as a model of the type of legislation the organization would like to see nationwide.

“The Texas success story is very much an American success story,” Kiernan said.

AWEA’s 2018 market repo r t is just the latest annual or quarterly report it provides. The report includes market rankings of major players, state-by-state details, economic and environmental impacts and assessments of power offtake, wind capacity ownership and project finance.

April 9, 2019

NYISO Seeks to Refine Carbon Price Equation

By Michael Kuser

RENSSELAER, N.Y. — NYI S O on Monday prop o sed using an estimated fuel cost to help determine the carbon component of locational-based marginal prices (LBMPc), while the state’s largest waste energy producer called for carbon offsets to be included in the ISO’s final carbon pricing plan.

The ISO’s fuel cost proposal is intended to improve stakeholders’ ability to estimate the LBMPc, carbon charges and credits and the carbon residual allocation. It would use the real-time LBMP divided by an estimated marginal fuel cost to provide an approximate heat rate in MMBtus, which would be applied against a “conversion factor” for calculating tons of emissions per megawatt-hour.

“We propose using the lowest-cost fuel on the system, on an MMBtu basis, given the varying costs of natural gas and oil,” Ethan D. Avallone, NYISO technical specialist, told the Installed Capacity/Market Issues Working Group.

The largest operator of New York waste-to-energy plants contends the facilities should get more generous treatment under a carbon pricing scheme because they provide a net reduction in GHGs. | *Covanta*

The ISO will determine the conversion factor from MMBtus to tons of carbon emissions and will post the factor and the fuel indices used, he said.

The ISO initially proposed calculating the LBMPc using a system of equations to determine binding transmission constraints and the characteristics of marginal resources, but staff found in many cases they could not solve the system of equations or could not determine a system of equations for a given market interval, Avallone said. (See NYIS O Looks at Carbon Charge Tariff Impacts, Residuals.)

The new method will calculate the LBMPc in dollars per megawatt-hour by multiplying the tons of carbon emissions per megawatt-hour by the social cost of carbon.

Bias and Accuracy

“How do you determine a statewide lowest-cost fuel given the varying access to pipelines?” asked Howard Fromer, director of market policy for PSEG Power New York. “There’s quite a variation among major pipelines for natural gas prices under peak conditions.”

Avallone said one benefit of the new approach is that it captures price variations among different load zones.

Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, asked about levels of accuracy and whether the ISO is “comparing the former equations-based approach and this heat rate approach.”

“Any approach we use is going to be an estimate, so we will be looking at accuracy factors,” Avallone said.

David Clarke, director of wholesale market policy for Power Supply Long Island, was concerned about the potential for the new fuel-cost method to overstate the carbon component.

“You might end up dividing a high cost by a lower carbon component,” Clarke said.

Mark Reeder, representing the Alliance for Clean Energy New York, agreed with Clarke.

“If you’re using the lowest-cost fuel, and if it turns out the plant on the margin is really using a higher-cost fuel, then you would be overstating the carbon component,” Reeder said. “This method seems a bit biased toward the high side. I recommend the NYISO, when judging the quality of any approach, give significant weight to the goal of a lack of bias and not just to the goal of accuracy. There is often a tradeoff between these two goals.”

In the NYISO market, certain carbon-free resources able to store energy structure their bids to achieve schedules during the most profitable periods of the day. When energy prices are low, the bids from such resources include an estimated opportunity cost of profit relative to intervals with higher prices.

“The proposed LBMPc methodology we just walked through will incorporate carbon adders that are the result of bidding opportunity costs,” Avallone said, noting carbon-free opportunity cost resource bids are also likely to increase as a result of carbon pricing in some hours.

He also said internal generators would be charged for carbon based on their actual emissions — not the LBMPc — and the LBMP used to calculate LBMPc will include the impact of resources’ bidding opportunity costs when such resources are marginal, making any additional adjustments unnecessary.

Referring to an instance when a California gas-fired generator installed batteries as part of its facility, Couch White attorney Kevin Lang, representing the City of New York, asked how NYISO’s carbon pricing would impact carbon resources able to store energy.

“I think you’d have the same treatment … the LBMP would still incorporate the costs of that generator,” Avallone said.

Reeder said he found the ISO approach “an elegant way to determine opportunity costs.”

Waste to Energy

Michael E. Van Brunt, director of sustainability for Covanta Energy, which owns or operates most of the state’s waste-to-energy (WTE) plants, addressed a different challenge his industry faces regarding the carbon pricing scheme.

New York’s 10 WTE plants employ nearly 1,400 people and convert 3.2 million tons of solid waste per year into electricity, with a combined installed capacity of 285.1 MW. Van Brunt sa i d while New York state policy values WTE over dumping in landfills, the facilities do not qualify for renewable energy credits under the Clean Energy Standard (CES) appen d ices, while landfill methane conversion does.

Landfills are required by state law to capture methane beyond a certain volume and use it to run generators. The latest figu r es from the state’s Department of Environmental Conservation show landfill methane generated 782,500 MWh of electricity in 2015.

In the voluntary emissions market, the WTE industry generates and sells offset credits from new capacity but “faces a significant penalty under the current NYISO proposal that will directly impact communities using WTE,” Van Brunt said, displaying a slide that shows the industry in New York having a net greenhouse gas factor of -0.8 ton CO2/MWh.

“I think a rational carbon pricing policy has to account for carbon offsets,” said Clarke.

Nicole Bouchez, the ISO’s principal economist, said state policy is “conflicted to some extent” and the CES does not cover WTE, requiring NYISO to have state approval to exempt WTE facilities from carbon pricing.

“The ISO plays an important role as arbiter on policy, and, in this case, where there are policy distortions,” its voice could count, Van Brunt said.

“Are you looking to be held harmless, as if the [carbon] program didn’t exist … or do you want to keep all the incremental revenue from carbon pricing?” asked Fromer.

“We look for equal treatment with landfills from the state,” Van Brunt said. “If landfills are going to be exempted, so should WTE.”

Bouchez said the ISO will soon announce a date for a second presentation by Analysis Group, which last month revealed the outli n e of a new study to provide additional insight into pricing carbon in NYISO’s wholesale electricity markets. (See Analysis Group Presents NYISO Carbon Pricin g Study Plan.)

April 9, 2019

NYISO Board Selects 2 AC Public Policy Tx Projects

By Michael Kuser

NYISO’s Board of Directors on Monday 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.

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.

“The projects will add the largest amount of free-flowing transmission capacity to the state’s grid in more than 30 years,” the board said in a statement.

The board in December issued a mixed decision on project selections made by NYISO’s Management Committee. The MC — along with ISO staff — had backed two joint proposals by North America Transmission (NAT) and the New York Power Authority. (See NYISO MC Supports AC Transmis s ion Project s.) Cost estimates for both projects ranged from $900 million to $1.1 billion.

New York’s AC Public Policy Transmission projects are intended to relieve congestion in key corridors. | *NYISO*

But while the board accepted the committee’s recommendation for Segment A, it switched Segment B to a competing proposal by National Grid and New York Transco. (See NYISO Board Partially Reverses AC Tx Project Selection.)

The NAT/NYPA Central East project involves construction of a new 345-kV line from Edic to New Scotland on an existing right-of-way; construction of two new 345-kV lines from Princetown to Rotterdam; decommissioning of two 230-kV lines from Edic to Rotterdam; and related switching or substation work at Edic, Princetown, Rotterdam and New Scotland.

The National Grid/Transco UPNY/SENY project involves several different areas of focus, including construction of a new double-circuit 345/115-kV lines from Knickerbocker to Churchtown and on to Pleasant Valley; construction of a new tap of the New Scotland-Alps 345-kV line and new Knickerbocker switching station; and related switching or substation work at the Greenbush, Knickerbocker, Churchtown and Pleasant Valley substations.

The project also entails decommissioning a double-circuit 115-kV line from Knickerbocker to Churchtown and two double-circuit 115-kV lines from Knickerbocker to Pleasant Valley.

National Grid and Transco will also oversee new line traps, relays, potential transformer upgrades, switch upgrades, system control upgrades and the installation of data acquisition measuring equipment and control wire needed to handle the higher line currents resulting from the buildout. The companies also will build a new double-circuit 138-kV line from Shoemaker to Sugarloaf; decommission a double-circuit 69-kV line from Shoemaker to Sugarloaf; and perform related switching or substation work.

“The additional transmission projects selected will improve the flow of power from upstate renewable resources to meet downstate demand and enhance the reliability and resilience of the grid … will alleviate congestion, help deliver power where it is needed most and aid the state in meeting its ambitious renewable energy goals,” interim NYISO CEO Robert Fernandez said in a press release.

The projects are the second and third transmission projects to emerge from the ISO’s Public Policy Transmission Planning Process, a planning activity required by FERC Order 1000 and the state’s Public Service Commission. The PSC identified the public policy transmission needs to increase transfer capability from central to eastern New York by at least 350 MW and from the Albany region through the Hudson Valley region by at least 900 MW.