DC Circuit Shoots down NE Utilities on CIP Cost Recovery Cutoff Date

The D.C. Circuit Court of Appeals on Friday sided with FERC over Cogentrix Energy Power Management and Vistra (NYSE:VST) on a 2020 order that authorized compensation to New England generators and transmission operators for compliance with NERC reliability standards.

FERC’s order approved ISO-NE adding a Schedule 17 to its tariff, permitting owners of assets that are critical to the derivation of interconnection reliability operating limits (IROLs) to seek compensation for the costs of complying with NERC’s Critical Infrastructure Protection (CIP) standards (ER20-739). (See FERC OKs Payment Rules for IROL Facilities.) ISO-NE identified 27 generation units at 15 plant locations and one merchant transmission facility that were IROL-critical facilities.

Under the commission’s ruling, facility owners could seek cost recovery as of March 6, 2020; however, FERC ruled that utilities could only recover costs incurred on or after the effective date of their rate filings under Section 205 of the Federal Power Act. A group of utilities, including Cogentrix and Vistra, objected to this cutoff, saying they had already spent “several million dollars” on meeting the CIP requirements and should be allowed to collect all historic costs.

The commission rejected the utilities’ rehearing request, clarifying that while “IROL-critical facility owners may seek recovery of the undepreciated costs of … past capital expenditures to comply with the IROL-CIP requirements,” it cited its rules against retroactive ratemaking. It also said that the companies had not shown that their inability to recover historic CIP compliance costs in the ISO-NE markets would interfere “with their opportunity to earn a reasonable return in the future.” Following the rejection, Cogentrix and Vistra appealed to the D.C. Circuit.

Court Sides with FERC on All Counts

In its ruling, the court agreed with FERC that Schedule 17 “does not address whether costs incurred before the effective date of the critical facility’s [Section] 205 filing can be recovered.” Writing for the court, Senior Circuit Judge A. Raymond Randolph pointed out that Schedule 17 expressly limits recovery for a particular facility only to costs found in the Section 205 filing for that facility; while this does not forbid recovery of prior costs, it does not permit such recovery as the plaintiffs claimed.

Cogentrix and Vistra also argued that FPA Section 219 requires the commission to “allow recovery of … all prudently incurred costs” of complying with NERC standards, with no reference to the time those costs were sustained. FERC responded that Section 219 cost recovery must be consistent with Section 205, including its “prohibition against retroactive rate recovery.”

The utilities countered that the rule against retroactive ratemaking is not explicitly stated in Section 205, but the court shot this argument down as well, pointing out that the Supreme Court has “recognized repeatedly that the filed-rate doctrine and the rule against retroactive ratemaking play an important role in helping the commission fulfill its statutory responsibility.”

“The commission could not ensure that rates are just and reasonable if the rates are not on file with the commission for a period of time before the rates go into effect,” Randolph wrote. “FPA [Section] 219 … therefore incorporates the filed-rate doctrine and the rule against retroactive ratemaking.”

Cogentrix and Vistra’s final argument claimed that FERC could not apply its rule against retroactive ratemaking “because there was no rate on file for medium-impact [cyber asset] reliability costs prior to Schedule 17.” The court responded that cost recovery for prior CIP compliance investments amounted to changing their rates “for a service that has already been rendered” and therefore was a retroactive action.

While FERC typically uses “historical costs to set current rates,” the court said that the utilities were not seeking to estimate future costs based on historical ones. Instead, they were looking to use new rates to recover costs “going back to 2014.” This is forbidden by the FPA because it amounts to utilities charging more to make up for previous under-collection, it said.

“Cogentrix and Vistra received transmission rates under the ISO New England tariff during the relevant period,” the court said. “That the companies failed to recover mandatory reliability costs does not allow an exception to the rule against retroactive ratemaking.”

January 31, 2022December 14, 2023

McAdams Stands up for Texas in SPP RSC Debate

Texas Public Utility Commissioner Will McAdams restored the Lone Star State’s voice last week to SPP’s Regional State Committee, arguing against a revision request he said is unfair to his state.

McAdams, taking a break from the PUC’s effort to overhaul the ERCOT market following last February’s devastating winter storm, beat his fellow regulators to the microphone when it came time to get his comments into the record on the measure being considered.

Will McAdams, Texas PUC | SPP

“I’m sure this will elicit debate or conversations,” he said during the RSC’s Jan. 24 meeting. “Texas continues to oppose the revision request. … This policy will have the effect of shifting more costs to Texas ratepayers without any foreseeable benefit to those ratepayers in the future.”

At issue is a proposal (RR483) that promises a “surgical approach” to evaluate byway transmission projects in wind-rich zones. It would allow a byway-funded upgrade to be funded through a regionwide allocation after meeting certain criteria under the “narrow review process.” Projects eligible for this “narrow and limited process” must have base plan upgrade costs eligible for cost allocation under the SPP tariff.

The measure is intended to address FERC-identified deficiencies in the grid operator’s byway facility cost-allocation process. It came just short of endorsement from the Markets and Operations Policy Committee two weeks ago. (See SPP Board, Regulators to Take up Rejected RRs.)

McAdams said the Texas PUC believes the rule change’s proposed highway waiver process would allow certain highway projects to be re-evaluated “solely for cost allocation purposes.” Echoing other members during the MOPC discussion, he said SPP’s regional cost allocation review process offers a remedy for those who think the highway/byway methodology of costs and benefits is unfair.

“No other types of transmission project is afforded this kind of a second chance,” McAdams said.

Under SPP’s highway/byway mechanism, transmission costs are allocated on a voltage threshold basis. Highway facilities, or those above 300 kV, are allocated 100% on regional, postage-stamp basis. Byway facilities, those between 100 and 300 kV, are allocated on a regional basis (33%) and to the pricing zone (67%) in which the facilities are located. Facilities at or below 100 kV are fully allocated to the zone in which they are located.

McAdams pointed out that Texas has “rigid statutes” for its non-ERCOT utilities that are not a part of the deregulated market. He asked whether SPP could “paint a roadmap” to where Texas consumers could see a long-term benefit as the state’s bountiful renewable energy resources continue to grow.

“In the future, and I know that we’re probably going to lose on this … we want to work with the rest of the [RTO]. We want to collaborate,” McAdams said. “We would just like to see if we can get to a point where we can see a reasonable benefit in the future for Texas ratepayers, and then we’re happy to work on the details.”

Joining McAdams in opposing RR483 were regulators from Louisiana, New Mexico and Oklahoma. That was not enough to stop the measure from passing, 7-4. The Board of Directors also approved the revision during its Jan. 25 meeting.

“I think this process is creating an incredibly targeted, narrow waiver process,” Kansas Corporation Commissioner Andrew French said. “By design, it’s probably not going to apply to a lot of projects. It’s going to provide some potential material relief to a few of the most egregious examples where customers in renewable-rich zones or maybe being burdened by costs but not receiving benefits.

“But as far as cost that might be shifted regionwide? That would be pretty minimal,” he said. “As we continue to transition our energy mix to take advantage of some economic energy sources that are that are remote, we do need to make more proactive holistic reforms to cost allocation. We need to continue to look at this because that’s ultimately going to be one of the bigger challenges we face.”

Four days later during a PUC open meeting, McAdams told his fellow commissioners the proposal “socializes costs for certain generation facilities in their home regions for the interconnection of the facilities.”

Noting that SPP’s East Texas and West Texas footprints account for about 30% of its load, he said that if RR483 is “reflective of future policy adjustments at SPP, it bears watching.”

“I’ll be working … to share our concerns so that SPP’s Texas ratepayers are not unduly subsidizing projects that are unbeneficial projects where we see no benefit,” McAdams said.

The RSC also endorsed RR476, which accepts storage resources as transmission assets. The measure defines them as “storage-as-transmission-only assets” and requires them to register as market storage resources in the Integrated Marketplace to account for their injections and withdrawals.

Staff Can Return to Office March 1

SPP has announced an optional return-to-the-office program for staff, effective March 1,

“I’m not a betting person, but if I were, I’m betting we’ll be together in April,” CEO Barbara Sugg said, referencing the RTO’s quarterly governance meetings.

She urged stakeholders not to lose patience with continued restrictions, which have prevented her from meeting publicly in person with the board and key stakeholders. Sugg was named CEO in January 2020, shortly before the pandemic began. (See SPP Board Taps Barbara Sugg as New CEO.)

“So far, she has refused to meet with us in person,” board Chair Larry Altenbaumer joked. “We hope to change that in the not-so-near future.”

Given the lack of travel in 2021, the RSC came in more than 99% under budget last year, spending $3,634 of a planned $498,000. The committee’s annual audit, which cost $3,000, accounted for the bulk of the spending.

“A lack of expenditures does not mean a lack of work,” said Paul Suskie, the committee’s staff secretary.

Coal Edges Wind as No. 1 Fuel

Coal-fired generation slightly outpaced wind in SPP’s fuel mix last year, Bruce Rew, senior vice president of operations, said during the quarterly joint stakeholder meeting.

Coal generation accounted for 35.7% of the fuel mix last year, while wind made up 34.6%. Natural gas was 19.9% in the face of increased prices.

Rew said SPP began 2022 with 30.5 GW of available wind generation. It accounted for as much as 70.49% of the RTO’s generation Dec. 26, when it produced almost 21 GW of the 27.23 GW of total load.

The Integrated Marketplace now has 281 market participants, with 178 of them classified as financial-only and 103 as asset-owning, Rew said.

January 30, 2022December 10, 2023

PJM MRC/MC Briefs: Jan. 26, 2022

Markets and Reliability Committee

Dead Bus Replacement Logic Changes Endorsed

PJM stakeholders unanimously endorsed changes to the dead bus replacement logic for assigning prices to de-energized pricing nodes (pnodes) at last week’s Markets and Reliability Committee meeting.

Vijay Shah, lead engineer in PJM’s real-time market operations department, reviewed revisions to Manual 11: Energy and Ancillary Services Market Operations designed to incorporate the changes that were introduced as part of a problem statement on five-minute dispatch and pricing in July 2020. (See PJM Stakeholders OK 5-Minute Dispatch Proposal.)

Vijay-Shah-2019-01-04-(RTO-Insider-LLC)-Content.jpg

Vijay Shah, PJM | © RTO Insider LLC

PJM said the revisions are intended to provide increased transparency in the logic and how it performs replacements for de-energized buses. The RTO is required to produce LMPs for all pnodes in the RTO’s network model for all intervals, including those that are de-energized.

The new logic is based on Dijkstra’s algorithm, an industry standard, to find a suitable replacement for de-energized pnodes. The manual changes include updated language to reflect the new logic.

Shah highlighted a change to section 9.1.1: Intraday Offers Optionality that was not included in the first read at the December MRC, which clarifies language to state that a generation resource’s fuel-cost policy only needs to be updated when opting into intraday updates for the cost-based schedule.

“We already had an ongoing effort to update the language in Manual 11, and we thought it would be good to include these changes as part of that,” Shah said.

The new dead bus replacement logic and manual revisions will take effect March 1.

Fuel-cost Policy Standard Clarifications Endorsed

Members unanimously endorsed a joint PJM/Independent Market Monitor proposal regarding fuel-cost policy standards and penalty language.

Melissa Pilong, senior analyst in PJM’s performance compliance department, reviewed the proposal clarifying fuel-cost policy standards in Manual 15 and Schedule 2 penalty language of the Operating Agreement. The proposal was endorsed at the December Market Implementation Committee meeting. (See “Fuel-cost Policy Standards Proposal Endorsed,” PJM MIC Briefs: Dec. 1, 2021.)

The changes would require that generation unit market sellers verify that all intraday offer triggers are specified in the unit’s fuel-cost policy. The Manual 15 updates include changes to the intraday update triggers. Pilong said market sellers would need to have a one-time trigger to update the maximum allowable cost offer to opt into intraday offers. Another clarification to Manual 15 includes language that PJM or the Monitor can work with market sellers to extend their fuel-cost policies prior to their expiration.

OA updates include standards of review that must be systematic and verifiable. Fuel-cost policies would be required to provide a fuel price that can be calculated by the Monitor or PJM “after the fact with the same data available to the generation owner at the time the decision was made and documentation for that data from a public or a private source.”

The changes now go to the Members Committee for a vote this month and would take effect upon approval by the PJM Board of Managers and FERC.

Virtual CC Proposal Endorsed

Stakeholders unanimously endorsed a proposal from Vistra addressing regulation for virtual combined cycles.

Michael Olaleye, senior engineer with PJM’s real-time market operations, reviewed the proposal to revise Manual 12: Balancing Operations. The issue charge was originally endorsed at the May MIC meeting and worked on during committee meetings. (See “Virtual Combined Cycle Regulation Issue Charge Endorsed,” PJM MIC Briefs: May 13, 2021.)

Units that are modeled virtually by PJM can sometimes receive varying regulation awards from the market clearing engine, Olaleye said, which Vistra has experienced with some of its units, calling it “operationally challenging.” When a combined cycle unit is modeled as multiple virtual units, there is a possibility for unbalanced or unequal regulation awards to each unit by the engine.

Comparison-of-combined-cycle-units-(PJM)-Alt-FI.jpg

Comparison of a 2×1 combined cycle unit with a pseudo-modeled 2×1 combined cycle unit when dispatched on a parameter-limited schedule | PJM

Vistra’s proposal calls for calculating the “hourly” score and extending it to each market resource with an assigned regulation for the given hour. It also called for PJM to calculate the “historic” performance score and extend it to each market resource in the performance group.

Olaleye said the changes would ensure that all resources of the performance group have the same historic performance score, which should fix the regulation clearing calculation problem in the software.

“The proposal is not changing the process of regulation clearing, pricing or settlement,” Olaleye said.

PJM plans on implementing the changes beginning March 1.

Consent Agenda

In the MRC consent agenda, members unanimously endorsed revisions to Manual 38: Operations Planning resulting from a periodic review. The revisions were originally endorsed at the Jan. 13 Operating Committee meeting and included minor changes. (See “Manual 38 Revisions Endorsed,” PJM Operating Committee Briefs: Jan. 13, 2022.)

Members Committee

Sector Selection Challenge Proposal Fails

Stakeholders rejected a proposal at last week’s Members Committee meeting seeking to change the way challenges can be made to sector selections in PJM.

The proposal, brought forward by Exelon and Public Service Enterprise Group from the Stakeholder Process Forum, received 45 votes in favor for a sector-weighted vote of 2.2, failing to meet the 3.33 threshold.

Sharon Midgley, Exelon’s director of wholesale market development, reviewed the proposed OA revisions. Several stakeholders questioned the proposal at the December MC meeting. (See “Sector Selection Challenge Process,” PJM MRC/MC Briefs: Dec. 15, 2021.)

The issue of sector challenges has been a source of discussion at the Stakeholder Process Forum for the last 18 months. In 2020, Exelon and FirstEnergy requested that PJM more actively police stakeholder selections after the disclosure that an LS Power affiliate was improperly voting in the RTO’s senior committees. (See Exelon, FE Ask PJM to Tighten Sector Selection Process.)

Under current rules, Midgley said, “questionable” sector selections of an existing member may only be challenged one time per year, coming within 30 days of the Annual Meeting. Challenges to a new member’s sector selection must be made within 30 days of the member joining PJM.

In the last three years, Midgley said, PJM required changes to the sector selections of 14 members, determining that a sector modification was warranted for 88% of challenges.

“Our goal is to make sure going forward that we ensure the integrity of sector-weighted voting at PJM,” Midgley said.

The proposed solution called for revising section 8.1.3 of the OA to say that any member may request that PJM review the qualification of another member to participate in a sector “if the basis for such challenged member’s qualifications have not been subject to a sector challenge review in the prior 24 months, unless there is a good faith assertion of a material change in the challenged member’s active and significant business interests with PJM.”

The revised language also called for removing the 30-day requirement from the Annual Meeting. Midgley said the requirement can be “challenging” for stakeholders to do “proper investigative work” on a sector challenge.

Susan Bruce, counsel to the PJM Industrial Customer Coalition, said the ICC was “not in a position to support” the proposal. She noted that it takes “significant time” to go through the sector selection process. “I think there’s value in having the orderly progression of having it be done once per year,” she said.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said he could see the arguments in expanding the sector challenge process to any time, but he said he had “broader concerns” after talking to his members about the proposal. Poulos said he is concerned that there could be “cherry picking” in what PJM members are selected for a sector challenge.

“It’s too limited and too narrow in the approach,” Poulos said.

After the vote failed, Midgley said Exelon and PSEG were “disappointed by the outcome.” A lack of a framework to allow stakeholders to appeal a sector selection on a “timely basis” can result in “inaccurate sector-weighted voting outcomes,” she said.

Consent Agenda

Stakeholders endorsed two different items on the MC consent agenda. They included:

tariff and OA revisions addressing several aspects of market participation by solar-battery hybrid resources. The revisions were unanimously endorsed at the Dec. 15 MRC meeting. (See “Solar-battery Hybrid Resources Endorsed,” PJM MRC/MC Briefs: Dec. 15, 2021.)
tariff and OA revisions addressing synchronous reserve deployment. The proposal, which was developed from discussions in the Synchronized Reserve Deployment Task Force (SRDTF), is meant to improve the deployment of synchronized reserves during a spin event. (See “Synchronous Reserve Endorsed,” PJM MRC/MC Briefs: Dec. 15, 2021.) The proposal was endorsed with 18 objections.

January 30, 2022

MISO Market Subcommittee Briefs: Jan. 27, 2022

CARMEL, Ind. — MISO is making slow progress on its plans to handle electric storage assets that aim to provide transmission services while also offering into the energy markets.

During a Market Subcommittee meeting Thursday, American Transmission Co.’s Bob McKee said his company intends to use the $8.1 million, 2.5-MW Waupaca Area Storage Project in Wisconsin for market and transmission purposes. The project was approved under MISO’s 2019 Transmission Expansion Plan as the RTO’s first — and currently only —transmission-only storage asset. It’s expected to be in service late this year.

“We want a clear path to know what we need to do to pursue this,” McKee said, referencing MISO’s allowing the project to furnish market services when it’s able. “We would urge MISO not to delay.”

MISO’s Michael Robinson said the grid operator might pursue one-off service agreements for its first dual-use energy storage projects instead of trying to finish lengthy tariff edits in time for interconnection.

“We think we have a defined path for where we’re going here,” Robinson said.

MISO has said for several years that it likely will require dual-use storage to first enter the generator interconnection queue before submitting energy offers, like any other generation asset seeking grid treatment. The Waupaca project has yet to apply to enter the queue.

Robinson said storage serving as transmission assets will be free to participate in any market, provided it can still address a transmission need.

But he said MISO and stakeholders still have work ahead regarding how the resources will collect both market compensation and transmission revenue requirements without being overcompensated. Robinson also said MISO must figure out whether storage assets should prioritize their market obligations or their transmission obligations during maximum generation emergencies.

Multiple stakeholders urged MISO not to rush tariff changes. Clean Grid Alliance’s Natalie McIntire asked for a “robust” stakeholder process that “fleshes out all details” before it drafts an overarching revision filing.

Market Interface Retirement Postponed

MISO has delayed retiring its aging market user interface (MUI) until Feb. 15 to accommodate members who haven’t yet switched to the new system.

“Everyone knows the end is near for the legacy MUI,” MISO’s Shawn McFarlane warned. “I think this is it; there won’t be any further pushback in terms of dates.”

Staff originally intended to retire the interface on Jan. 18, but some market participants have been slow to migrate their operations to the new system. The grid operator has been running both the old and new interfaces in parallel since early September.

Roughly 300 MISO customers use the nonpublic MUI to make energy offers and bids in the MISO markets. The upgrade is part of the RTO’s ongoing market platform replacement.

The grid operator is entering the fifth year of a multistage swap of its older, more rigid market platform for a newer modular one that can host more complex market offerings.

2 Conservative Ops Declarations in January

Frigid weather compelled MISO to declare conservative operations twice in late January.

The grid operator issued the alerts Jan. 20-21 for its South region and again on Wednesday for the northern part of its Midwestern footprint. Neither alert escalated into a maximum generation emergency or warning.

Under conservative operations, MISO requests members return generation and transmission facilities undergoing maintenance to service, if possible.

The RTO earlier declared conservative operations and a maximum generation emergency warning in the first week of January for its Central and North regions. Cold weather was again the culprit behind the close shave. (See Near-emergency Follows MISO’s Winter Warnings.)

MISO has been warning stakeholders since last fall that a generation emergency was a real possibility in January. While it experienced one close call, the month is nearly over and the system remains emergency-free.

MISO Independent Market Monitor David Patton said he has observed more coal-fired generation usage in the footprint with high natural gas prices. However, he said some facilities have been conserving coal to preserve their winter inventories, as railroad coal deliveries remain dogged by labor shortages.

Patton said that strategy will likely reduce coal capacity factors in winter. He added that he’s working with resource owners so that coal resources’ facility-specific reference levels “reflect the opportunity costs associated with maintaining winter coal inventory.”

January 30, 2022

Climate Policy Champion Leaving Wash. Senate

The architect of the nation’s second cap-and-trade law said last week that he will leave the Washington Senate when his term expires next year.

On Jan. 24, Sen. Reuven Carlyle (D) announced that he won’t run for re-election later this year. “I have a deep sense of fulfillment. … It’s time for me to open a new chapter of my life. … I’m taking the luxury of going out on top,” he said Tuesday in an interview.

Carlyle is chairman of the Senate Environment, Energy and Technology Committee. Along with Rep. Joe Fitzgibbon (D), chairman of the House’s Environment and Energy Committee, he is one of the state’s top two legislators on climate change issues.

Carlyle represents an upscale, north-central Seattle district in the state legislature.

In the interview, Carlyle said he has achieved most of what he wanted in a legislative career dating back to 2009 and is ready to tackle something else.

Carlyle pointed to the 2021 passage of Washington’s Climate Commitment Act, which implements a cap-and-trade program in the state, as a crowning achievement of his legislative career. (See Wash. Becomes 2nd State to Adopt Cap-and-trade.)

Washington has the nation’s second cap-and trade program behind California. It took several years for Carlyle to get this legislation passed after first facing a hostile Republican-controlled Senate and then opposition from moderate Democrats in swing districts when his party took over the Senate in 2018.

“We won the Super Bowl of climate activities. … I’ve given it everything I have,” he said.

The 2021 law requires the Washington Department of Ecology to create system by 2023 to set the state’s total industrial carbon emissions annually, a cap that slowly decreases through the years. Large polluters would submit bids in the state quarterly auction for allowances enabling them to emit greenhouse gases within a year’s overall limit. Companies would be allowed to trade, buy and sell the allowances.

Under the law, an environmental justice panel will be appointed to ensure that low-income neighborhoods and communities of color would not be disproportionally burdened with excess pollution. The state anticipates the auctions would raise $500 million annually that the state can allocate to those areas.

The program would cover facilities that emit 25,000 metric tons or more of GHGs annually. There are at least 100 such facilities in the state, including the oil, cement, steel and power industries and large food processing plants.

Carbon emissions have been blamed for negative health impacts; increased wildfires; changing snowpack melt patterns in the Cascade Range, which translates to streams not feeding irrigated farms at the proper times; and creating acid rain that destroys the shells of baby oysters in the state’s shellfish industry. A 2018 University of Washington study said the state’s poor face additional health dangers from climate change.

In 2018, Washington’s carbon emissions totaled 99.57 million tons. An earlier law set emission goals of 50 million tons by 2030, 27 million tons by 2040 and 5 million tons by 2050.

Carlyle also spearheaded passage of a 2019 law that will eliminate coal-fired electricity in Washington by 2025, require all retail electricity in the state to be carbon neutral by 2030 and require 100% of its retail electricity to come from sources other than those that emit greenhouse gases by 2045.

Along with setting new low-carbon fuel standards and advancing other climate bills in 2021, “we have passed the strongest suite of climate change legislation in United States history at the state level,” Carlyle said.

No Lobbyist

Climate change was not high on Carlyle’s priorities when he joined Washington’s House of Representatives in 2009, where he eventually became chairman of the Finance Committee, which handles tax and revenue issues. Carlyle credited his conversion to his three daughters and one son — currently ages 15 through 24 — as influencing him to consider climate change as the major focus of his legislative career.

He moved to the Senate in 2018, the same year that Democrats assumed control of that chamber.

Other Carlyle accomplishments include improvements in foster care, making the value of a corporate tax break public information and easing the transfers of students from two-year to four-year colleges. He is proud to be one of seven senators to vote against exempting the legislature from Washington’s public records law. Gov. Jay Inslee vetoed that legislation.

Carlyle’s biggest unfulfilled wishes are eliminating the death penalty and bolstering the state’ data privacy laws — efforts that have passed the Senate but have stalled in the House. He has also unsuccessfully tried to pass a bill for years to require a one-year cooling off period between when a legislator or state official leaves office and becomes a lobbyist.

His day job is being a high-tech entrepreneur and business consultant in the wireless, software and clean energy industries. He plans to keep active in local, state and federal civic affairs, but he does not know what he will tackle next. “I have no formal plans,” Carlyle said.

“I won’t become a lobbyist,” he added.

January 30, 2022

Stakeholders Debate OSW Ban to 75 Nautical Miles off Maine Coast

A working group of the Maine Offshore Wind Roadmap is considering a request that the U.S. Bureau of Ocean Energy Management bar OSW development within 75 miles of the state’s coast.

“There is strong interest in the [Fisheries Working Group] in advocating for the state to take a position on moving OSW construction further offshore … to minimize OSW development and fisheries conflict,” Meredith Mendelson, deputy commissioner of the Department of Marine Resources and co-chair of the working group said during a roadmap advisory committee meeting Friday. “We’ve had multiple discussions around this, and I expect we will continue to for some time, but we wanted to bring it forward to the advisory committee because we think this is an important issue.”

Mendelson said the group has not settled on a proposed distance for the prohibition. A document released by the working group Jan. 18, however, said the Fisheries Working Group “strongly encourages the state to advocate for BOEM and the [Gulf of Maine] Interagency Task Force to prohibit the development construction of OSW turbines within 75 nautical miles or less from the Maine coast.”

At that distance, the prohibition would easily exceed the distance of all active BOEM lease areas on the East Coast.

Vineyard Wind I, for example, is sited 30 nautical miles from the Massachusetts coast, and the lease areas recently announced by BOEM for the New York Bight range between 20 and 69 nautical miles from the New York coast.

Gov. Janet Mills signed a law last summer that prohibits new OSW development in state waters, which extend 3 nautical miles from the coast. Mills had originally proposed a 10-year moratorium on OSW in state waters, but she eventually agreed to a permanent ban to protect commercial lobster harvesting.

The Maine Governor’s Energy Office filed an application in October to lease a site in federal waters in the Gulf of Maine for a floating offshore wind research array. The preferred site, according to the application, is 25 nautical miles from the nearest point on the mainland.

Considerable engagement with members of the fishing industry went into selecting the proposed array site, according to the application. Selection of a site “no less than 17 nautical miles offshore” reduces “potential impacts on inshore fisheries,” the application said.

The call to extend the state-waters ban to federal waters would be part of a wider package of recommendations that the advisory committee will consider related to OSW development and the state’s fishing industry.

The group shared 11 initial recommendations with the committee Friday, including encouraging the state and BOEM to engage the fishing industry directly in the development of wind areas in the Gulf of Maine. In addition, the group wants to see the state initiate a port assessment as wind areas are identified to determine the implications for local port economies.

Three other working groups delivered their initial recommendations to the committee in December, and all the groups will refine their recommendations with a goal of releasing an official set of draft recommendations in July. The final roadmap is due at the end of the year.

January 30, 2022

Maine Could Extend OSW Ban to 75 Nautical Miles off Coast

A working group of the Maine Offshore Wind Roadmap is considering making a recommendation to extend the current OSW development prohibition for state territorial waters into federal waters.

The group is still discussing the potential recommendation, and it has not settled on a proposed distance for the prohibition, Mendelson said during a roadmap advisory committee meeting Friday.

“We’ve had multiple discussions around this, and I expect we will continue to for some time, but we wanted to bring it forward to the advisory committee because we think this is an important issue,” she said.

A document released by the working group Jan. 18, however, included a suggested distance of 75 nautical miles for the prohibition. At that distance, the prohibition would easily exceed the distance from shore of all active U.S. Bureau of Ocean Energy Management lease areas on the East Coast.

A possible recommendation by the working group to extend the state-waters ban to federal waters would be part of a wider package of recommendations that the advisory committee will consider related to OSW development and the state’s fishing industry.

January 30, 2022June 14, 2023

NY Officials, Stakeholders Discuss Utilities’ Tx Planning Process Proposal

[EDITOR’S NOTE: A previous version of this story erroneously included the New York Power Authority as part of the group of utilities.]

New York’s local transmission and distribution system owners on Thursday recommended that state regulators approve a coordinated grid planning process (CGPP) and revised benefit-cost analysis (BCA) method as proposed by them in December (20-E-0197).

The New York Public Service Commission in September established a category of public policy transmission investments and directed investor-owned utilities to revise their proposed benefit-cost analyses. (See New York Adopts Groundbreaking Tx Investment Rules.)

“The CGPP will facilitate technical collaboration between planning authorities and vetting of the existing system studies to ensure consistency between all studies, eliminating confusion and potential conflicting information,” Bart Franey, National Grid supervisor of regulatory strategy, said to more than 220 participants at a technical conference held by the PSC.

“Once established, the CGPP will align system representation planning tool assumptions and other key constraints to drive consistency between all CLCPA-based studies [and] will be used to inform the market policymakers on the cost and viability of future interconnections,” Franey said, referring to the Climate Leadership and Community Protection Act, which requires that 70% of New York’s electricity generation come from renewable resources by 2030 and that generation be 100% carbon-free by 2040.

The utilities group include the state’s IOUs, as well as the Long Island Power Authority. Staff from the Department of Public Service (DPS), the New York State Research and Development Authority (NYSERDA) and NYISO helped shape the proposals, on which interested parties can submit comments until March 21.

The revised BCA approach would use capacity expansion analyses. Costs would be evaluated on a dollars-per-megawatt basis for transmission and non-wire alternatives (NWAs). Benefits would be evaluated as the incremental amount of energy delivered to load as a result of reduced curtailments and the capacity of additional renewable generation that can be interconnected.

Projects would be ranked on the basis of metrics and criteria to be developed in collaboration with DPS staff, the utilities said.

New Technologies and More

The utilities considered several new and emerging technologies in their potential projects, including power flow control devices, dynamic line ratings and energy storage, the commission said, noting several “areas of concern” characterized by the presence of existing renewable generation that is already experiencing curtailments and a strong level of developer interest that exceeds the capability of the local transmission system.

FERC in December ordered transmission owners to stop the use of static line ratings in evaluating near-term transmission service, which it said will improve accuracy and transparency, and increase utilization of the grid. (See FERC Orders End to Static Tx Line Ratings.)

“Modifying the rating of a given transmission line throughout some given period rather than solely having seasonal based ratings, as is the conventional practice, can be taken into consideration in operations and planning, so that’s a very recent order,” said Zach Smith, NYISO vice president of system and resource planning. “From NYISO’s perspective we’re looking at it and considering what we do on compliance for that.”

PSC orders in this proceeding have specifically pointed to DLR as a technology that may help the state get more CLCPA benefit at low cost, said Elizabeth Grisaru, deputy director of the DPS’ Office of Electric, Gas and Water. “The commission has specifically pointed to [DLR] as one of the technologies our utilities should be considering when developing and proposing” their projects.

The crux of the grid analysis is to identify the placement of generation that can optimally use existing transmission on both the bulk and non-bulk systems, and those siting assumptions and land-use assumptions are going to be critical, Franey said.

Resource Adequacy Margins (NYISO) Content.jpg

NYISO analysis found tightening margins across the New York grid through time, with a margin of only 200 MW in New York City (Zone J) and only 700 MW in western New York (Zone A) by 2030. | NYISO

Transmission providers are hoping for long-sought-after changes on FERC’s Advance Notice of Proposed Rulemaking, a wide-ranging inquiry into the commission’s rules on transmission planning, cost allocation and generator interconnection. (See Transmission Industry Hoping for Landmark Order(s) out of FERC ANOPR.)

The ANOPR proceeding will likely have impacts not only on the comprehensive system planning process, but on the way that that interacts with various policies, such as the interconnection process and how the system is planned as a whole relative to generation coming forward, Smith said.

“Depending on what comes out of that FERC proceeding, presumably an order at some point, it could be a great opportunity for the NYISO, our stakeholders, for all of us to be working together on what’s the most efficient planning process,” Smith said.

Advisory Council Makeup

The utilities also proposed creating a new advisory council to manage the planning cycles.

The scope of work would be developed in the first stages of the CGPP by the council, said Martin Paszek, section manager for transmission planning at Consolidated Edison.

“I would try to keep the council as one group and maybe with subgroups … but not have two separate groups that are losing the coordination we’re trying to achieve,” said Bill Acker, executive director of New York Battery and Energy Storage Technology Consortium (NY-BEST).

A planning group with a distribution subgroup would work well, agreed Zack Dufresne, executive director of the New York Solar Energy Industries Association (NYSEIA).

The proposed process is two-pronged, with the first being NYISO’s local transmission owner planning process, wherein utilities’ specific content and technical information regarding transmission investments would be reviewed and discussed openly, Franey said.

“The second prong to our stakeholder engagement plan really adopts a couple of models that exist in New York today such as the New York State Reliability Council or the Climate Action Council, [which] are very useful at leveraging stakeholder input on a more tactical basis,” Franey said.

The council would invite information that utilities aren’t experts in, such as generation development and land use, so it would consist of representatives not only from utilities and the state, but also from community organizations and renewable energy trade associations, he said.

“We envision that these industry organizations or groups would nominate a rep and an alternate to set up a lot of the critical input that would then translate into assumptions for modeling purposes,” Franey said.

In thinking about stakeholder engagement, the DPS considered its own Interconnection Policy Working Group and Interconnection Technical Working Group structures, which “are pretty good models,” Grisaru said.

One important group that wasn’t in the proposal is consumers, who “absolutely” need to have a voice in the process, said Couch White attorney Kevin Lang, representing New York City.

“I believe there are a lot of people that are participating this morning who are not active in the NYISO process, and if what we’re talking about is distribution and local transmission, which is under PSC purview, I question whether or not a NYISO process that looks at the bulk system is the right venue to be talking about distribution and local transmission issues and whether or not the audience is even the correct audience for those discussions,” Lang said.

Lang had an ally in Erin Hogan of the state’s Utility Intervention Unit.

“Allowing developers to select sites very remotely and then have the expectation that consumers will be recouping costs and the investments that might need to expand the headroom does not seem to be wise, leaving consumers too far out of the loop,” Hogan said.

She suggested informing county executives of the planning discussions so they can share the information and make communities knowledgeable about the decisions being made and how people might be able to participate.

“I want to be clear today that this is the starting point for this effort,” said Tammy Mitchell, director of the DPS Office of Electric, Gas and Water. “Much more work and stakeholder input will be needed to fill out the details of the process and align [utilities] and New York ISO activities to support holistic views of CLCPA needs, so there will be many other opportunities to ask questions and provide input in the planning process.”

January 30, 2022

HECO Approved for $5M Make-ready EV Charger Pilot

State regulators last week approved Hawaiian Electric Company’s (HECO) $4.98 million pilot to install electric vehicle charging infrastructure across the state in a bid to incentivize commercial customers to invest in charging ports.

The pilot program, Charge Ready Hawaii, tasks HECO with building the underlying infrastructure so that commercial customers only have to pay for the installation and maintenance of the EV charging ports themselves.

HECO will build “make-read” infrastructure in 30 locations across the state — 14 on Oahu, 8 on Maui and 8 on Hawaii Island, enough to support an estimated 180 EV charging ports over a three-year period. The pilot program will target commercial sites, multi-unit dwellings and locations for EV fleet parking.

HECO defines make-ready infrastructure as including “all infrastructure that the customer would otherwise be responsible for,” such as transformer upgrades and line extensions, “but excludes the charging stations, which are provided by the customer.”

Because of the high cost of installing EV charging infrastructure, HECO noted, the pilot program will provide an easier way for customers to “realize fuel savings relative to gasoline when they are charging at pilot participating commercial locations.”

HECO said emissions reductions “are anticipated” from the program, but that it could not provide specific figures. The data collected from the pilot will help with modeling future energy loads on the grid as the transportation sector adopts more EVs, the utility said.

HECO also noted its “openness” to prioritize building in underserved communities.

Based on expectations for future EV adoption in Hawaii, HECO estimates it will recover the $4.98 million cost of the pilot program in 10 to 12 years.

In approving the pilot, the Hawaii Public Utilities Commission said Charge Ready Hawaii will “yield meaningful data acquisition and experience that will enhance the development of a more permanent EV rate scheme and will inform the continued development of EV charging infrastructure.”

January 30, 2022

Ariz. Regulators Reverse Clean Energy Rules

In a reversal of a decision last year, Arizona regulators voted last week to reject a set of energy rules that would have required the state’s electric utilities to cut carbon emissions 50% by 2032 and 100% by 2070.

The Arizona Corporation Commission (ACC) voted 3-2 on Wednesday to reject the energy rules. Commissioners Anna Tovar (D) and Sandra Kennedy (D) voted in favor of the rules, while commissioners Jim O’Connor (R) and Justin Olson (R), along with Chairwoman Lea Marquez Peterson (R), voted against them.

The vote is a reversal of the commission’s 3-2 vote in May to advance the rules, with O’Connor changing his vote. Because the rules approved in May incorporated substantial amendments, they needed to go through further rulemaking and return to the commission for a final vote.

O’Connor said on Wednesday that he supports clean energy but questioned whether the energy rules are needed.

“I have concluded that the utilities are serious and sincere with their commitment to clean energy,” O’Connor said. “I concluded they do not need these state-level energy rules at this time, which impose risks for ratepayers.”

‘Flip-Flop’ Criticized

Tovar chastised fellow commissioners who “flip-flopped” on the energy rules, “wasting hundreds of hours of staff time” as a result. The energy rules have been in the works for years, received thousands of public comments and are supported by a wide range of stakeholders, including utilities and energy industry companies, she said.

“We as commissioners should be ashamed that all of this painstaking effort was in vain, because we let politics get in the way of what is right,” Tovar said.

In November 2020, Marquez Peterson was one of four commissioners who voted in favor of starting the formal process to adopt a proposed rule that would require electric utilities to eliminate their carbon emissions by 2050.

But Marquez Peterson later said that she opposed mandates for reducing carbon emissions, saying such requirements would give utilities a “blank check” for recovering costs associated with the mandates.

When the energy rules came to the commission for a vote on May 5, 2021, Olson proposed an amendment to make the carbon-reduction targets voluntary. The amendment passed with votes from three commissioners — Olson, O’Connor and Marquez Peterson.

But when the amended rules went up for a vote, Olson voted “no.” The rules failed with Olson, Tovar and Kennedy opposed. (See Ariz. Regulators Kill Clean Energy Proposal.)

Later that month, Kennedy asked for a reconsideration of the rules. During a meeting on May 26, 2021, the commission accepted an amendment proposed by Tovar and O’Connor, which gave utilities until 2070 to reach 100% carbon-free emissions. Interim standards included a 50% reduction by 2032, a 65% reduction by 2040, an 80% reduction by 2050, and a 95% reduction by 2060.

The rules also included requirements for energy efficiency and energy storage.

The amended energy rules, with the 2070 deadline for eliminating carbon emissions, were approved on May 26 with a 3-2 vote. Marquez Peterson and Olson were opposed. (See Arizona Regulators Revive Clean Energy Rules.)

Utility Commitments

Marquez Peterson said Wednesday that when commissioners voted on early drafts of the rules, they knew it wasn’t the final vote.

She said that she supports 100% clean energy by 2050 as a goal. And now, she said, for-profit utilities have “adopted voluntary clean energy commitments on their own.”

“With their voluntary commitments, I believe we’ve entered into a new chapter and a transition to clean energy,” Marquez Peterson said.

In addition, she said, a report on the costs of a clean-energy mandate came out after the commission’s May vote.

An analysis by Ascend Analytics found that monthly electric bills would be $8 to $35 higher in 2050 if utilities provided 100% clean energy by then. The difference in cost, which varies by utility, is in comparison to a “least-cost” scenario. (See Report Projects Ariz. Ratepayer Costs for Going Clean.)

In a statement on Thursday, Marquez Peterson listed some examples of utilities’ commitment to clean energy. In January 2020, APS announced a goal of providing 100% clean, carbon-free electricity to customers by 2050.

In its 2020 integrated resource plan, Tucson Electric Power (TEP) said it would provide more than 70% of its power from renewable sources by 2035 and reduce carbon emissions by 80%.

TEP said in January that it brought three large clean-energy systems online in 2021. They are the 250 MW Oso Grande Wind Project near Roswell, N.M.; Wilmot Energy Center, which consists of a 100 MW solar array and 30 MW of battery storage near the Tucson International Airport; and the Borderlands Wind Project near the Arizona-New Mexico border, which includes 34 turbines producing a combined 99 MW.

Business Impact

Groups supporting clean energy reacted with disappointment to ACC’s decision to reject the energy rules.

“Strong, predictable clean energy standards are crucial for helping Arizona attract new businesses and build a booming job market for years to come,” said Shelby Stults, Arizona policy lead at Advanced Energy Economy, a national business group. “Abandoning this rules package takes Arizona’s economic and advanced energy growth drastically off course.”

Adam Stafford, Western Resource Advocates’ senior staff attorney in Phoenix, said that ACC must now find a new path forward for addressing the climate crisis.

“The power sector provides some of the most cost-effective opportunities to reduce climate pollution,” Stafford said in a release. “Arizona’s largest utilities have all said they want the regulatory certainty of a firm emissions reduction standard, and the business community has voiced support for that, as well.”