Page 1220 – RTO Insider

January 28, 2018

LP&L Finalizing Agreements in ERCOT Move

Lubbock Power & Light told Texas regulators last week that it continues to hammer out settlement agreements that will resolve most of the arguments in the utility’s proposed migration of 470 MW of load from SPP to ERCOT.

Chris Brewster, legal counsel for LP&L, told the Public Utility Commission on Jan. 25 that the utility has modified a settlement agreement reached Jan. 17 with PUC staff and several consumer groups. (See Texas Regulators Noncommittal After LP&L Hearings.)

ERCOT SPP LP&L Lubbock Power & Light — LP&L counsel Chris Brewster (center) updates the PUC on the utility’s settlement agreements | *PUCT*

He also said the utility has reached a separate agreement in principle on the SPP side that involves an upfront payment from LP&L to SPP and Southwestern Public Service, which serves Lubbock’s load under a pair of long-term contracts. Brewster did not disclose monetary figures or further details in the agreement, which had not been filed with the PUC as of Friday afternoon.

The Texas parties agreed the only outstanding issue in the proceeding (Docket 47576) pertains to who will build the $360 million in infrastructure ERCOT has projected would be needed to connect LP&L’s load with its system.

“The discussions are ongoing,” Brewster told the PUC. “The parties in West Texas have a perspective on that.”

The commissioners discussed whether to carve out the transmission construction issue separately, but they decided to allow Brewster a chance to include it in the settlement agreements. Brewster will update the PUC at its next open meeting on Feb. 15.

PUC Opens Rulemaking on Distributed Battery Storage

The commission voted to dismiss an AEP Texas request to connect battery storage facilities to the ERCOT grid (Docket 46368), instead opening a rulemaking to “develop a framework within which [it] can consider a broader range of technologies and study the potential impacts to the competitive retail market and energy-only wholesale market in ERCOT.”

Chair DeAnn Walker said in a memo that AEP’s proposal included issues that need “additional commission review and information,” and suggested the PUC “take a wider view of the innovative concepts raised in this docket as well as other potential technological solutions.”

An administrative law judge had approved AEP’s proposal to connect a pair of utility-scale lithium-ion battery facilities to the ERCOT system in West Texas, but the company ran into broad industry opposition when the ALJ ordered the facilities to be classified as distribution assets and included in AEP’s cost-of-service rates. (See PUCT Considering Rulemaking over AEP Battery Proposal.)

In her memo, Walker said she “firmly” believed the energy consumed by the batteries should not be treated as unaccounted for — or unmetered — energy, as AEP proposed.

“The rulemaking should address a method by which any energy necessary for the implementation of a solution can be measured and accounted for within the market,” she said.

Walker also suggested amending PUC rules to require a utility to obtain a certificate of convenience and necessity to use “non-traditional technologies to solve distribution problems.”

“We’re excited about seeing this technology get into our market,” said Commissioner Brandy Marty Marquez. “Batteries are the commonsensical response to the renewables we’ll see in our market.”

Commissioner Arthur D’Andrea said he had concerns about allowing “regulated utilities to play in this space.”

“The energy does overhang the market,” he said.

Commission Issues Favorable Entergy Orders

In a pair of actions related to Entergy Texas, the PUC signed off on a report analyzing the costs and benefits of MISO membership and approved the company’s request to build a 230-kV transmission line in southeast Texas.

The commission requested the report when it approved the transfer of operational control of Entergy’s assets to MISO in October 2012. The PUC declined Texas Industrial Energy Consumers’ proposal to impose reporting requirements on Entergy, agreeing with staff that it already can request information from the utility as it deems necessary.

— Tom Kleckner

January 28, 2018January 3, 2024

MISO Seeks Stakeholder Input on Foxconn Decision

By Amanda Durish Cook

MISO last week said it will hold off on a decision to expedite its review of a proposal to interconnect Foxconn’s massive electronics plant planned for southeastern Wisconsin until it gets more feedback from stakeholders.

The RTO’s studies of American Transmission Co.’s plan to interconnect the Foxconn plant concluded the project is suitable for recommendation to the Board of Directors under the normal approval timeline for the 2018 Transmission Expansion Plan. But MISO is stopping short of granting expedited status until it hears stakeholder opinions at a Feb. 14 Planning Advisory Committee meeting.

ATC submitted the request for accelerated approval, contending that the proposed $140 million Mount Pleasant Tech Interconnection Project to hook up the $10 billion electronic manufacturing plant with We Energies’ network cannot wait until the usual approvals at the end of the year as part of MTEP 18. ATC has proposed constructing a 14-mile 345-kV transmission line, a new 345/138-kV substation and new underground 138-kV lines to connect the substation to a smaller Foxconn-owned substation near the plant. The transmission developer said it received We Energies’ request to construct the infrastructure in mid-October and notified MISO of the need for expedited approval in late November.

MISO’s studies have found the project will have no adverse impact on system reliability, with the project meeting NERC and ATC local planning reliability criteria.

Minimal Economic Benefits

But MISO also determined that potential systemwide economic gains from the Foxconn project fall far short of the threshold for qualifying as a market efficiency project eligible for competitive bidding or broader cost allocation.

During a Jan. 25 conference call, MISO economic analyst Nicholas Przybilla said the RTO found the benefit-cost ratio of the project would likely be 0.009:1, well below the 1.25:1 requirement for market efficiency projects. He said the economic assessment was provided for informational purposes only, as the lead time and projected December 2019 in-service date are too short for consideration anyway.

Michigan Public Service Commission staffer Bonnie Janssen asked why the economic benefits were so low.

“There is a decent amount of interconnect in the area already,” Przybilla said.

Earlier this month, three Milwaukee aldermen questioned We Energies and ATC’s plan to pass the costs of the interconnection to ratepayers, given that the project stands to benefit just one large industrial customer. (See Milwaukee Signals Fight Against Foxconn Interconnection Plan.)

In response to a question from Kavita Maini, an economist for Midwest Industrial Customers, MISO said its study relied solely on ATC’s 230-MW load projection for the plant, rather than considering any other forecasts. ATC staff at the meeting said they determined that figure was credible after examining similar manufacturing plants in Asia.

Joseph Dunn, MISO West Region expansion planning engineer, said ATC provided an $130 million alternative proposal that would loop existing 345-kV lines into the new substation, but the RTO found the project would result in inferior reliability and more right-of-way approvals when compared to the original project.

If approved, ATC’s interconnection project will eliminate the need for the $12 million reconstruction of a 345-kV bus in Racine, Wis., that was originally approved in the MTEP 16 cycle. That smaller project also has a December 2019 in-service date, but MISO staff said it will be withdrawn should ATC’s project win approval.

January 26, 2018October 31, 2023

Northern Pass Cleans up in Mass. RFP

By Michael Kuser

Eversource Energy and Hydro-Québec were the big — and only — winners in a solicitation to provide Massachusetts with 9.45 TWh of renewable energy each year, state officials revealed Thursday.

The selection of the companies’ joint Northern Pass transmission project means that an additional 1,090 MW of hydropower will be delivered into the New England grid via a new 192-mile HVDC line.

The project contains no provisions for delivering other forms of renewables and was the only one selected among a handful of proposals dominated by hydroelectric output from Québec. (See Hydro-Québec Dominates Mass. Clean Energy Bids.) A separate Eversource bid that included Canadian wind energy was not accepted.

Massachusetts issued its solicitation for a high volume of hydro and Class I renewables (wind, solar or energy storage) last July.

Eversource Energy Northern Pass Transmission — Baker | © *RTO Insider*

“We collaborated with the legislature to propose and sign the bipartisan energy legislation that enables today’s procurement, and we look forward to working with all stakeholders involved to ensure it delivers a cost-effective and reliable energy future that makes substantial progress in reducing our carbon emissions,” Massachusetts Gov. Charlie Baker said.

The Massachusetts Department of Energy Resources worked with distribution utilities Eversource, National Grid and Unitil on the solicitation. Any contract awarded under the MA 83D request for proposals must be negotiated by March 27 and submitted to the state’s Department of Public Utilities by April 25.

All New Hampshire

Northern Pass Eversource — Northern Pass route map | *Eversource*

Northern Pass would run from Des Cantons, Québec, to Deerfield, N.H., where it will convert to AC and interconnect with ISO-NE.

The New Hampshire Site Evaluation Committee is scheduled to complete permit deliberations for the project Feb. 23 and issue a written decision by the end of March.

In a summary of its final application briefing filed with the committee Jan. 19, Eversource said that Northern Pass would “provide New Hampshire residents with more than $3 billion in benefits at no cost to the state’s energy customers,” employ 2,600 people during construction, and “reduce regional greenhouse gas emissions by more than 3.2 million tons per year, equal to the emissions of 670,000 cars.”

The province of Québec last month granted Hydro-Québec a permit to build the project.

Different Takes

“We are pleased with the decision announced today, and appreciate the thorough review by the Massachusetts bid evaluation team,” Eversource Executive Vice President Lee Olivier said in a statement Thursday.

“This is a major milestone in the energy transition underway in the Northeast. … Hydro-Québec’s clean, reliable power, along with our proven delivery capability were highly valued by decision-makers,” said Hydro-Québec CEO Éric Martel.

Eversource Energy Northern Pass — Dam | *Hydro-Québec*

Brian Murphy, business manager of the International Brotherhood of Electrical Workers Local 104, said that the project “not only brings tremendous clean energy benefits to our region but will also provide opportunity for thousands of working families in Massachusetts and New Hampshire. The IBEW looks forward to getting to work on the Northern Pass project in the coming months.”

Not everyone agreed with the Massachusetts decision.

“Providing long-term guarantees to the two largest utilities in the region is the wrong way forward for Massachusetts,” New England Power Generators Association President Dan Dolan said in a statement. “Eversource and Hydro-Québec are asking for Massachusetts consumers to guarantee them revenue through an above-market contract for electricity for the next two decades. Eversource wrote the RFP, and by picking their own project as the winner, have made consumers the losers.”

The Conservation Law Foundation last week tried to sway Baker against the project with a full-page ad in The Boston Globe, saying Northern Pass should be disqualified on environmental and ethical grounds, and accusing the developers of having misrepresented in its bid the level of public support the project enjoys in New Hampshire.

No Wind Today

Northern Pass’s win came one day after Maine Gov. Paul LePage imposed a moratorium on new wind energy projects in western and coastal Maine and set up a commission to study the effect of wind turbines on tourism. Jeremy Payne, executive director of the Maine Renewable Energy Association, called the governor’s action “an attempt to thwart billions of dollars of investment that is looking at Maine,” according to the Portland Press Herald.

Chris O’Neil, a Portland-based consultant and former state representative who often lobbies for wind energy opponents in Maine’s capital, told RTO Insider that Massachusetts did the right thing by ignoring Maine wind in its search for clean energy.

“The RFP scoring is more favorable to dispatchable power that can guarantee 9.4 TWh … because the ISO-NE has lost and is losing some 5,000 MW of baseload and peak load generation,” O’Neil said. “Wind cannot perform these baseload and peak load functions. What New England needs is the good stuff. But the ISO-NE would do well to move forward with the other two HVDC projects also.”

He was referring to Maine-based Emera’s proposed Atlantic Link, a 375-mile submarine HVDC transmission line from New Brunswick to Plymouth, Mass., to deliver 5.69 TWh of clean energy per year; and National Grid and Citizens Energy’s Granite State Power Link, a 59-mile HVDC line from northern Vermont to New Hampshire that would deliver 1,200 MW of new wind power from Canada.

But Wind is Coming

But if wind energy was a loser in the most recent solicitation, its prospects are brighter elsewhere. Baker last year signed a law requiring Massachusetts to contract for 1,200 MW of renewable energy, including hydro, onshore wind and solar. A separate clause in the Act to Promote Energy Diversity mandated that the state solicit proposals for at least 1,600 MW of offshore wind energy, which it did in December. Those projects will be selected in April with contracts due to be submitted at the end of July.

Bay State Wind, a joint venture between Ørsted and Eversource, proposed building either a 400-MW or 800-MW wind farm 25 miles off New Bedford. It would be paired with a 55-MW battery storage facility.

Deepwater Wind proposed two versions of Revolution Wind, a wind farm of consisting of about 25 turbines generating 200 MW, or a project double that size to generate 400 MW. Deepwater is proposing to firm up the project’s output through an agreement with the 1,200-MW Northfield Mountain hydroelectric pumped storage facility operated by FirstLight Power Resources.

Vineyard Wind, a joint venture of Avangrid Renewables and Copenhagen Infrastructure Partners submitted proposals for 400-MW and 800-MW wind farms, with approximately 50 and 100 turbines, respectively. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)

January 26, 2018

Sempra, Oncor Add More Parties to Settlement Agreement

By Tom Kleckner

Sempra Energy and Oncor said Thursday they have added three more parties to a settlement agreement covering Sempra’s proposed $9.45 billion acquisition of Energy Future Holdings, which includes the bankrupt company’s 80% ownership of Oncor.

The companies said Energy Freedom Coalition of America, Nucor Steel and Golden Spread Electric Cooperative have joined a settlement previously agreed to by six other parties in December. The settling parties have agreed that the acquisition is in the public interest, meets Texas statutory standards, and provides tangible and quantifiable benefits, Sempra and Oncor said. (See Sempra, Oncor Reach Deal with Texas Stakeholders.)

Oncor Sempra Energy Future Holdings — Oncor Switching Yard | *Oncor*

Texas Legal Services Center, a nonprofit law firm that provides free legal representation and advice to low-income persons and Medicare recipients, is the lone holdout intervenor.

The agreement includes regulatory commitments that preserve the existing Oncor ring-fence and the independence of its board of directors. It also extinguishes all debt currently held by EFH and Energy Future Intermediate Holding Co.

With the latest agreement, California-based Sempra moves another step closer to acquiring Oncor, Texas’ largest utility. The companies joined with Public Utility Commission of Texas staff on Jan. 5 to request that the PUC approve the acquisition, consistent with the governance, regulatory and operating commitments in the settlement agreement (Docket 47675).

During a brief discussion at the PUC’s open meeting Thursday, Chair DeAnn Walker told her colleagues she will be meeting with each FERC commissioner at the same time the PUC has scheduled its hearing on the merits of the deal. The PUC set the hearing for Feb. 21-23, but Walker’s FERC meetings are on Feb. 22, suggesting the PUC won’t need all three days.

“If it goes longer than half a day on the 21st, I don’t think any of us should be happy with the use of our time,” Walker said.

The PUC is expected to make a decision by early April. The EFH transaction is also subject to approval by the U.S. Bankruptcy Court.

Sempra agreed to acquire EFH last August. In September, the U.S. Bankruptcy Court for the District of Delaware approved EFH’s entry into the merger agreement with Sempra.

January 26, 2018

EDF Renewable Wins Platform for Queue Concerns

By Amanda Durish Cook

EDF Renewable Energy will get a shot at taking its gripes about MISO’s interconnection process to a wider group of the RTO’s stakeholders.

In a unanimous vote Wednesday, MISO’s Steering Committee agreed to forward the company’s grievance about the length of the interconnection queue for further discussion in the RTO’s Planning Advisory Committee.

Still, some committee members expressed concern over similarities between EDF’s request to examine interconnection timelines and its recent FERC complaint about the structure of the queue. (See Renewables Developer Escalates MISO Queue Design Dispute.)

EDF, which asked the Steering Committee for an issue assignment in November, is still advocating for a two-stage interconnection queue process, rather than the current three stages. The company on Wednesday again asked committee members to consider how MISO could increase the pace of interconnections after RTO planners won approval for a new, streamlined design last year.

MISO Director of Stakeholder Affairs Shawna Lake said the RTO still believes it’s “premature” to make changes to the recently FERC-approved design before completion of a full cycle of queue studies.

“There are very, very long delays happening now, and we’re thinking there’s a way to tighten this up,” Bruce Grabow, an attorney representing the company, said during the committee’s Jan. 24 conference call. For starters, MISO could require secured site control for new generation, instead of a deposit, he said. The queue currently contains 355 projects representing 60 GW, the largest number of prospective projects in a decade.

MISO FERC interconnection queue EDF Energy — Queued projects in MISO South region | *MISO*

EDF provided similar background earlier this month in its FERC complaint, which asked the commission to order a “workable” interconnection timeline to ensure that wind developers can secure federal production tax credits (PTCs) before they expire at the end of 2020.

But during Wednesday’s call, Grabow said EDF’s FERC complaint is entirely different from its committee request because the complaint focuses narrowly on speeding up studies only for wind developers and others impacted by PTC deadlines. Grabow predicted that even if FERC found fault with the queue process, queue entrants not relying on PTCs would continue within the current three-stage queue.

“There’s no way FERC would issue something that would impact the three-stage queue,” said Grabow, eliciting some skepticism from the committee.

Steering Committee Chair Tia Elliott suggested that EDF craft a fuller explanation of how the two arguments differ and where overlap might occur.

Two weeks after EDF lodged its complaint, RTO staff introduced a new feedback form designed specifically to capture stakeholder opinions on issues discussed during Interconnection Process Task Force meetings, in addition to other advice related to the queue. (See MISO Seeks Stakeholder Input as Queue Timeline Lengthens.)

MISO’s most recent predictions for the August 2017 cycle of projects in the queue indicate that most are expected to wrap up in February or March 2019, except in the Upper Peninsula area of MISO East, where projects are slated to finish this December. But in the wind-heavy MISO West region, projects are expected to clear the definitive planning phase (DPP) of the queue as late as July 3, 2019.

MISO FERC interconnection queue EDF Renewable Energy — Queued projects in MISO West region | *MISO*

The RTO’s queue reform was intended to reduce the number of days that interconnection customers spend in the DPP from an average of 589 days to 460. Customers that entered the August 2017 cycle are currently predicted to spend an average of 579 days in the DPP before signing an interconnection agreement.

January 25, 2018

SPP Market Monitor: Negative Prices May Require Rule Changes

By Tom Kleckner

SPP’s Marketing Monitoring Unit says it is concerned with a “marked increase” in the frequency of negative price intervals, and that market rules may need to be revised to address self-committing resources in the day-ahead market and the absence of some forecasted variable energy resources in the real-time market.

In releasing its most recent quarterly State of the Market report, the MMU said that with the prolific growth of wind generation, the frequency of intervals experiencing negative prices increased from 2.6% in 2015 to 7% through November 2017.

SPP MMU market monitor negative prices — Logan’s Gap Wind Farm | *AWEA*

“Negative prices may not be a problem in and of themselves, but they do indicate an increase in surplus energy on the system,” the Monitor said in its report. The market’s practice of self-committing resources in the day-ahead market may be “exacerbat[ing]” the situation, it said.

Negative prices can occur when there is excess power and renewable resources must be backed down so that traditional resources can meet their scheduled generation, the MMU said. It said unit commitment differences resulting from wind resources opting out of the day-ahead market but coming online in the real-time market can create differences in the frequency of negative price intervals.

In October, 17% of all real-time intervals had prices below zero, most occurring in the overnight low-load hours, with a “sizable” number of intervals having prices lower than -$25/MWh.

Negative prices in the day-ahead market are almost exclusively between -1 cent/MWh and -$25/MWh, the Monitor said.

The report also said:

Prices averaged $20.22/MWh (day-ahead) and $20.53/MWh (real-time) during the fall. October’s average price of about $18/MWh was the lowest monthly average since spring 2016.
The average monthly gas price at the Panhandle Eastern hub continued to hover around $2.60/MMBtu, as it has for the previous 10 months.
Fall’s all-in cost was $22.40/MWh, a 12% decrease compared to the fall 2016 level of $25.53/MWh. The gas price at the Panhandle Eastern hub dropped by 1 percentage point for the same period.
Coal-powered resources continued their downward trend, accounting for only 45% of energy produced in the fall, compared to 50% in fall 2016 and 52% in fall 2015. Wind generation continued its upward trend with 26% of energy produced last fall, compared to 20% in fall 2016 and 15% in fall 2015.
More than 11% of all intervals in the real-time market had no congestion, compared to 2% in fall 2016 and nearly 4% in fall 2015.

The MMU will host a webinar on Feb. 8 to discuss the fall report.

January 25, 2018

EIM Body Tables Nominating Process Changes

By Jason Fordney

FOLSOM, Calif. — The Energy Imbalance Market (EIM) Governing Body on Tuesday rejected CAISO’s move to change how members of the panel are nominated, saying the idea “appeared to come out of nowhere.”

EIM Governing Body CAISO Nominating Committee — Howe | © *RTO Insider*

Chairman Doug Howe made the “out of nowhere” comment as the board unanimously tabled any decision on the ISO’s proposed revisions to the nomination process.

“What problem are we trying to solve here?” Howe said after a CAISO briefing on the proposal during a Jan. 23 meeting of the panel. “For me, it’s ‘I really don’t know.’” He said the changes could create confusion in the market. “It doesn’t strike me as sending the right message out.”

The rejected proposal would have eliminated the EIM Nominating Committee’s obligation to use an executive search firm to help fill Governing Body vacancies, instead encouraging committee members to rely more on their own contacts. The plan would also have altered a current policy that allows the committee to re-nominate sitting body members without considering other candidates.

Governing Body member Kristine Schmidt said the proposal would saddle the Nominating Committee with the “heavy lifting” normally performed by a search firm. This would include tasks such as defining the scope of the work, evaluating qualifications and accreditations, narrowing the list, and conducting interviews.

“In my opinion, that is the work of the executive search firm,” Schmidt said, adding that the proposal should be vetted by the committee and the EIM Body of State Regulators.

“The changes that are being proposed trouble me greatly,” she said, contending that they appeared to be the product of a few individuals, and “there is no sunshine on that decision.” She added that “the process is working just fine to date.”

Looming Term Expirations

Created in 2016 to oversee the rapidly expanding regional market, the five-member Governing Body has decisional authority over EIM matters. The current members were all among the first to be seated on the body, and the terms of Howe and Carl Linvill are set to expire on June 30, while Vice Chair Valerie Fong and John Prescott’s terms expire June 30, 2019.

Schmidt, whose term expires in 2020, was the only member to be reappointed to the body after her inaugural, one-year term ended last year. (See EIM Governing Body OKs Charter Expansion; Retains Schmidt.) A former executive at ITC Holdings and Xcel Energy, Schmidt served as chair during her first term, which was truncated to stagger the normally three-year terms for members.

CAISO’s proposal would have altered the policy around reappointing a member that has expressed a wish to be re-nominated. Current practice dictates that the Nominating Committee “should determine whether it wants to re-nominate the departing member without interviewing other candidates.” If the committee decides against re-nomination, it is required to use the outside firm to find at least two other candidates.

The proposed change would have obligated the Nominating Committee to consider the current member but “also normally consider additional qualified candidates.” It also would have specified that the committee interview and consider at least two candidates for each position when a sitting member is not seeking re-nomination.

CAISO has cited the expense of hiring an outside consultant as a reason for the proposed changes. (See CAISO Proposes EIM Governance Changes.)

The ISO also proposed to change the process for determining whether the Governing Body — rather than its Board of Governors — has decisional authority over an ISO proposal. CAISO currently makes that determination, but a dispute resolution process is triggered if the chair of either the ISO board or EIM body challenge the decision and cannot conclude an agreement on the issue.

CAISO’s proposal would have allowed ISO management to directly consult with the objecting chair. Any change resulting from that consultation would then be subject to a vote by both chairs, a process the ISO thinks would avoid further meetings and delays.

Fong said that CAISO must take “a more holistic approach” to EIM governance changes, calling the proposal “confusing for the market and confusing for us.”

Body Briefed on ISO Roadmap

During the Jan. 23 meeting, CAISO staff told the Governing Body that the EIM could expand as a result of the ISO’s proposal to extend its day-ahead energy market into what is now a regional balancing market. (See CAISO Plan Extends Day-Ahead Market to EIM.) The ISO is focused on the day-ahead market to better manage the load curve and is working on a package of other changes. The ISO is also pursuing efforts to support reliability-must-run payments for needed gas generators and to lower market barriers for distributed energy resources.

The EIM Governing Body met on Tuesday at CAISO headquarters in Folsom | © *RTO Insider*

CAISO Director of Market and Infrastructure Policy Greg Cook briefed the Governing Body on the final roadmap posted Jan. 12. Out of the 16 initiatives CAISO is undertaking this year, 12 are related to the EIM, he said.

“You have a busy year coming up in front of you,” Cook told body members.

January 25, 2018

New York Court to Consider ZEC Challenge

By Michael Kuser

The Albany County Supreme Court on Monday rejected New York’s motions to dismiss outright a lawsuit challenging the state’s Clean Energy Standard and provisions for zero-emission credit subsidies for nuclear plants.

ZEC zero-emission credits clean energy standard — New York State Supreme Court in Albany | *NYCourts*

The decision means that ZEC opponents will get their day in court, although the presiding judge did dismiss a handful of their complaints — as well as a number of the plaintiffs themselves.

Environmental group Hudson River Sloop Clearwater and 60 other litigants last year challenged the New York Public Service Commission’s August 2016 order (15-E-0302) adopting the CES and creating the ZEC program.

The petitioners filed suit in response to a December 2016 PSC ruling that rejected nearly all requests to rehear the order. The PSC in that ruling noted that issues raised in other requests would be “further explored” in the future.

Chief among their complaints is that the commission rushed the CES without allowing sufficient time for public comment, violating provisions of New York’s State Administrative Procedures Act and Public Service Law.

The suit challenges the provision of ratepayer subsidies in the form of ZECs to four nuclear plants in the state, including Entergy’s Indian Point north of New York City and Exelon’s three upstate plants: James A. Fitzpatrick, R.E. Ginna, and Nine Mile Point Units 1 and 2.

ZECs zero-emission credits clean energy standard — Indian Point

In his Jan. 22 ruling, Judge Roger D. McDonough declined to comment on the merits of the procedural claims made by the environmentalists and consumer advocates.

“In the absence of a proper motion for summary judgment or even a request for [procedural review], the court declines to entertain such discussions without the benefit of answers and the full administrative record,” said the ruling, which provided the PSC 35 days to file its answers.

Procedural Review

McDonough did grant the PSC’s motion to dismiss the petitioners’ claims on Indian Point, finding them “unripe because they are wholly dependent upon Indian Point applying and being approved for ZEC payments.”

The judge also dismissed 56 plaintiffs from the litigation for procedural reasons such as ripeness, standing and statute of limitations. He also dismissed a claim premised on the State Environmental Quality Review Act.

The plaintiffs, however, cheered the decision to reject the state’s motion to dismiss the suit altogether. Manna Jo Greene, environmental director of Hudson River Sloop Clearwater, called it a “David versus Goliath” victory.

“We were opposed by the PSC, the nuclear energy plant owners … but we prevailed and proved our issues are substantive and triable,” Greene said in a statement.

The PSC declined to comment on the case.

The decision comes at the same time federal courts are hearing — or soon will hear — appeals on prior ZEC rulings in other states.

A three-judge panel of the 7th U.S. Circuit Court of Appeals on Jan. 3 heard oral arguments on Illinois’ 2016 law. The Electric Power Supply Association and retail ratepayers are asking the court to overturn a district court ruling that dismissed their challenge last July. (See Ill. ZECs Defenders Face Harsh Questioning on Appeal.)

The 2nd Circuit Court is likely in March to hear an appeal on a similar district court ruling in New York.

January 25, 2018March 22, 2024

FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014

WASHINGTON — Generation operators fared better during the early January cold snap than in the 2014 polar vortex, officials told Congress on Tuesday, but New England needs to take urgent action to prevent major reliability problems.

“Although we are still receiving and reviewing data, it appears that, notwithstanding stress in several regions, overall the bulk power system performed relatively well,” FERC Chairman Kevin McIntyre told the Senate Energy and Natural Resources Committee. “There were no customer outages resulting from failures of the bulk power system, generators or transmission lines. … With limited exceptions, the RTOs/ISOs had sufficient reserves to ensure reliable operations.” (See related story, McIntyre Wades into Capitol Hill Fuel Wars.)

Temperatures between Dec. 28 and Jan. 7 were 20 to 35 degrees Fahrenheit below average in many regions, but peak load in eastern markets was slightly below that in 2014, FERC said.

PJM recorded three of its top 10 winter peak demand days of all time. SPP set a new winter demand peak of 42.71 GW on Jan. 16, besting a record set Jan. 2. ERCOT set a new winter peak of 65.73 GW on Jan. 17 — almost 3 GW higher than the previous record of 62.86 GW on Jan. 3. (See ERCOT, SPP Extend Winter Peak Records.)

The MISO South region set a new winter peak of 32.1 GW on Jan. 17, just short of the all-time (summer) peak of 32.6 GW.

Reserves

Only MISO (Jan. 1-5) and NYISO (Jan. 5-7) saw reserve shortages, McIntyre said. Reserve prices for resources that can respond within 10 minutes were more than $1/MWh during 41% of hours in PJM, 39% in NYISO and 72% in MISO.

McIntyre said initial data suggest that generator performance was better than in 2014 but that “a definitive assessment cannot be made at this time.”

PJM reported that forced outages during the peak demand hour of the recent cold blast were less than 23 GW (11%), half the 22% rate during the polar vortex.

Prices

Between Dec. 28 and Jan. 7, ISO-NE recorded the highest average day-ahead prices at $177/MWh, while PJM hit the highest maximum at $375/MWh. (See chart.) Prices last winter ranged from the low $30s to low $40s.

The energy market prices are consistent with the spike in natural gas prices during the period, McIntyre said, although FERC staff are conducting routine screening of market data for any signs of manipulative behavior.

Natural gas spot prices hit $140/MMBtu in New York on Jan. 4, and seven other trading points in the Northeast and Mid-Atlantic had averages above $100. Gas demand on Jan. 1 hit 150.7 billion cubic feet, exceeding the previous single-day record set in 2014, the Energy Information Administration reported.

Oil, LNG Save New England — This Time

Pipelines in the Northeast and parts of the Midwest had frequent delivery limitations during the period. Operational Flow Orders (OFOs) — requiring shippers to balance their supply with their customers’ usage daily within a specified tolerance band — were declared on the Algonquin, Dominion, Iroquois, Tennessee and Texas Eastern pipelines in the Northeast. Most of the OFOs declared during the cold were lifted on or before Jan. 9, FERC said.

New England survived its gas pipeline capacity constraints thanks to LNG shipments and plants switching to oil.

ISO-NE CEO Gordon van Welie, who also testified to the committee Tuesday, expressed frustration that New England has not taken steps to address threats to its reliability given the growth of gas-fired generation since he first told Congress of his concerns in 2013. Since 2000, oil- and coal-fired generation’s share of ISO-NE’s power production has fallen from 40% to less than 10%, while natural gas has risen from 15% to about 50%.

The region will have lost much of its nuclear power with the retirement of Pilgrim in 2019 (Vermont Yankee closed in 2014), leaving only the 2,100-MW Millstone station in Connecticut and the 1,200-MW Seabrook plant in New Hampshire. Dominion Energy has threatened to shutter Millstone if it does not begin earning higher revenues. (See Conn. Regulators Signal Support for Millstone.)

On Jan. 17, ISO-NE released its Operational Fuel-Security Analysis, which examined 23 fuel-mix scenarios using current pipeline infrastructure to determine whether enough fuel would be available to meet demand.

The report concluded that power shortages attributed to inadequate fuel would occur in 19 of the scenarios by winter 2024/2025, requiring use of emergency actions such as voluntary energy conservation and involuntary load-shedding. (See Report: Fuel Security Key Risk for New England Grid.)

“What our study [shows] is we’re really close to the edge in New England, and we need to find a way of relieving this constraint one way or the other,” van Welie told the committee. “Either through investment in pipeline infrastructure or continuing to invest in other sources of energy that will take the pressure off the gas pipelines or reducing demand on the system. Those are the three avenues available to the region.”

Costly

“It will be costly to remedy these fuel-security challenges — whether the region chooses to invest in renewable energy (and related transmission), fuel infrastructure with long-term contracts, or further measures to reduce demand for wholesale electricity and natural gas,” he continued.

“A key question to be addressed will be the level of fuel-security risk that New England is willing to accept.”

Failing to invest, van Welie said, will result in “chronic price spikes during cold weather, higher emissions when it’s more economic to burn oil than natural gas, and the possibility of further interventions by ISO-NE in the wholesale electricity market to try to delay critical resources from retiring.”

With FERC approval, the RTO can sign reliability agreements to delay generator retirements that would cause transmission overloads. Van Welie said the RTO could change its Tariff for authority to delay retirements because of fuel-security risks, but “generation owners may choose to retire their assets regardless of the offer of a reliability agreement.”

In addition to considering Tariff changes, the RTO will be looking at the impact of a pending rule change: The Pay-for-Performance program, which increases penalties for generator nonperformance, takes effect June 1.

ISO-NE also will be looking at the impact of its Competitive Auctions with Sponsored Policy Resources (CASPR) proposal, filed with FERC on Jan. 8. “While this is a positive step toward accommodating policy-driven resources in the wholesale markets, it may exacerbate the fuel-security challenge if certain non-natural gas-fired generation were to retire before the region has addressed the fuel infrastructure constraints highlighted in the Operational Fuel-Security Analysis,” van Welie said. (See ISO-NE Files CASPR Proposal.)

PJM Pushes Price Formation Plan

PJM said it “had an abundance of reserves and capacity” during the cold spell.

“In most respects, the recent cold snap was much milder than the polar vortex,” PJM CEO Andy Ott said in his written testimony to the committee. “The temperatures were not as low, the wind chill was much less and the demand for electricity was lower, in part due to the cold snap occurring during a holiday week. On the flip side, the cold snap did last for much longer, which led to some degrading of generator performance over time.”

Ott used some of his time before the committee to promote the RTO’s proposal to allow inflexible generators, including coal and nuclear plants, to set LMPs. (See “PJM Wins Examination of Price Formation,” PJM Markets and Reliability Committee Briefs: Dec. 21, 2017.)

He said the proposal would increase energy prices while reducing uplift and capacity prices.

“While out-of-market payments have improved since the polar vortex (approximately $16 million per day) we still saw significant payments during the recent event (approximately $4 million per day),” Ott said. “By contrast, on a typical day, out-of-market payments may be approximately $400,000 to $500,000.”

The ‘Next Level’ for Gas-Electric Coordination

Ott also called for “bringing gas-electric coordination to the next level.”

“To reach this next level, we believe it is important that FERC, [the Department of Energy] and, in some cases, this committee look into some key dichotomies in the regulation of these vital infrastructures.”

While the electric industry is subject to mandatory physical and cybersecurity standards under FERC, the gas pipeline industry uses “high-level voluntary guidelines” from the Transportation Security Administration “augmented with yet a different level of regulation by the Pipeline and Hazardous Materials Safety Administration,” Ott said.

“I say this not to impugn work that the pipelines have done in this area but to point out that the two industries face vastly different compliance obligations, particularly in the area of cybersecurity. By definition, these dichotomies will inevitably hinder an optimal integrated and coordinated approach to common threats from both physical and cyberattack.”

Tightening CEII?

Ott also suggested changing the handling of critical electric infrastructure information (CEII) to balance transparency with security concerns.

“The CEII rules utilized at FERC and at the state level are designed around a ‘right to know’ approach, with some verification of the bona fides of the requestor. Yet, the federal government doesn’t approach classified information this way,” Ott said. “Rather, that system is based on the provision of access based on a demonstrated ‘need to know.’ It may be time to consider evolving our release of a limited set of highly sensitive infrastructure information from a ‘right to know’ to a ‘need to know’ basis.”

January 25, 2018

FERC Grants PJM Waiver of MOPR Exemption Deadlines

By Robert Mullin

Some PJM generators will have additional time to submit unit-specific exemptions to the minimum offer price rule (MOPR) before the RTO’s capacity auction next month under a Tariff waiver approved by FERC on Monday.

The decision (ER18-489) comes a month after the commission for a second time again rejected PJM’s 2012 MOPR compromise, which would have permitted categorical exemptions to the price rule (ER13-535-004). FERC had ruled that it was unreasonable for PJM to remove unit-specific exemptions and also directed the RTO to eliminate the proposed categorical exemptions. (See On Remand, FERC Rejects PJM MOPR Compromise.)

The commission issued last month’s order on remand after the D.C. Circuit Court of Appeals last July found FERC had overstepped its “passive and reactive role” in undoing the compromise and suggesting the inclusion of unit-specific exemptions to the MOPR, which PJM had adopted in a compliance filing. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)

In response to the December ruling, PJM asked for a one-time waiver of a Tariff provision that requires sellers to apply for unit-specific MOPR exemptions 135 days in advance of the third 2018/19 Incremental Auction slated for Feb. 26. Unsure of the outcome of FERC’s remand order, some sellers preparing for the auction opted last October to apply for the categorical exemptions — leaving them outside the deadline for seeking unit-specific exceptions once the commission had rejected PJM’s proposed rules.

The timing of the remand order also meant that Tariff-based deadlines had slipped for PJM and its Independent Market Monitor to provide a seller their respective determinations on the unit-specific request — and for the seller to commit to an offer price.

“As a result of these already-passed or plainly impracticable deadlines, parties that reasonably relied on the categorical exemptions, but that could also qualify for a unit-specific exception, would be barred by the current Tariff deadlines from submitting justifiably competitive offers in the auction,” PJM wrote in its Dec. 20 waiver request.

“Without waiver, resources that followed the then-effective Tariff language would be unfairly penalized for simply adhering to the Tariff,” the commission wrote in granting the request. “PJM’s waiver request remedies the timing conflict between the remand order and the effective Tariff rules, thus allowing these affected resources to submit unit-specific review requests.”

FERC rejected LS Power’s request to broaden the scope of the waiver to include generating resources that had not applied for categorical exemptions by the October 2017 deadline. The company contended that some of its affiliates had only recently acquired some new resources “or faced uncertainties regarding interconnection service for those resources,” the commission noted.

PJM FERC waiver LS Power MOPR exemption — FERC rejected LS Power’s bid to extend PJM’s original MOPR exemption waiver request to accommodate plants the company had acquired late last year, such as the Ironwood Plant above | *TransCanada*

“LS Power does not explain why expanding the scope to entities that were not affected by the timing of the remand order is justified. Accordingly, we grant PJM’s waiver request and reject LS Power’s request to expand it,” the commission said.

The waiver sets these one-time deadlines to remedy the issue:

Jan. 12: Deadline for markets sellers that had submitted categorical exemption requests to submit a unit-specific request;
Feb. 2 (Monitor) and Feb. 16 (PJM): Deadlines for proposed determinations on the exemption request; and
Feb. 22: Deadline for the seller to provide its commitment on a unit-specific offer price.