New Eversource Rate Corrects Course on Conn.’s Dwindling Solar Program

A new electricity rate option for small, non-residential Eversource Energy customers in Connecticut could correct what solar advocates say has been a five-year death spiral for the state’s solar program.

Connecticut’s Public Utilities Regulatory Authority directed Eversource last week to offer optional interim rate riders to small businesses.

The move responds to concerns from Solar Connecticut that Eversource rates have damaged the state’s solar industry. State legislators also urged PURA to consider new rates to provide relief to small businesses that saw unusually high electricity bills during the pandemic.

SolarConn, in a filing to PURA, said a shift in 2015 from consumption rates (per kWh) to fixed charges (per kW) in rates for Eversource’s commercial customers decreased demand for solar. That shift, SolarConn said, changed the profitability profile for projects in the state’s Zero Emissions Renewable Energy Credit (ZREC) program.

By eliminating the ability of a solar project to net meter production against per kWh charges for consumption, “the entire economic model for distributed renewable energy was predictably upended,” the business group said.

The results of the 2015 rate change have been evident in the small ZREC program, SolarConn said, adding that “for over two years, almost no small ZRECs have been utilized for projects.”

PURA’s decision directs Eversource to establish an optional rider with “a volumetric component” (per kWh) for two of its existing rates.

Relief from the new interim rate should help in the latest round of solicitations for low-emissions REC and ZREC projects. Under the program, projects are supposed to realize a 15-year revenue stream from REC sales. That revenue, SolarConn said, has not materialized for many projects.

PURA said the creation of optional rate riders with both a volumetric rate and a demand charge component “is consistent with Connecticut law and public policy as it encourages economic development … by giving small businesses more control over their energy expenses.”

“Small businesses will have the potential to reduce their electric bills by decreasing their kWh electricity consumption through reduced usage, employing conservation and energy efficiency measures, or by participating in the LREC/ZREC program or its successor,” PURA wrote in its unanimous decision.

Eversource must update its website by July 1 to indicate the availability of the new optional riders — beginning Nov. 1 — and allow customers to sign up for them ahead of the effective date.

In addition, Eversource needs to show “how it plans to proactively work with new and existing customers” to ensure customers select the best rate option, according to PURA. The riders will be available until PURA approves Eversource’s new rate schedules in the utility’s subsequent rate-case proceeding.

Two Letters

PURA Chair Marissa Gillett said the leadership of the General Assembly’s Energy and Technology Committee sent a letter in December 2020 that called attention to “the importance of considering targeted relief” for Connecticut’s small businesses amid “the devastating impacts” of the COVID-19 pandemic. The committee’s leadership specifically requested PURA consider implementing interim rate riders to help small businesses curb “wildly high bills despite being closed or operating at reduced hours” because of “high fixed charges (per kW).” PURA concluded that the development of optional rate riders was “in the public interest, and is consistent with current practices and tariff offerings, the Take Back Our Grid Act, and PURA’s statutory authority. “The Take Back Our Grid Act, which passed into law in the wake of Tropical Storm Isaias in 2020, gives PURA legal latitude to consider an “interim rate decrease, low-income rates and economic development rates” for Eversource and United Illuminating customers.

In an additional supporting letter submitted in April, the Department of the Energy and Environmental Protection said the state’s Conservation and Load Management Plan demonstrates that “a reduction in both kW and kWh usage provides broad societal and energy benefits to Connecticut’s ratepayers.” According to DEEP, rate designs that encourage reductions in both demand and overall kWh consumption further realize those benefits.

DEEP stated that generally, “volumetric charges are shown to incent energy efficiency, and the greater the fixed cost within a rate structure, the less motivated a customer will be to lower their energy usage.”

Additionally, DEEP said commercial and industrial energy efficiency programs drive down demand and bring Connecticut “closer to its decarbonization goals.” In 2020, they provided 82,133 tons of annual carbon dioxide emissions reductions and 952,749 tons of lifetime emissions reductions. Cleaner air resulting from the state’s energy efficiency and clean energy programs deferred over $5 million in public health costs last year.

June 29, 2021December 10, 2023

PJM Reserve Price Formation Issue Charge Approved

PJM stakeholders narrowly approved an issue charge to examine the RTO’s operating reserve demand curve (ORDC) and transmission constraint penalty factors and the possible creation of a “circuit breaker” to control energy prices in an emergency.

The problem statement and issue charge, sponsored by nine different stakeholders, was approved in a sector-weighted vote of 2.505, barely passing the 2.5 threshold for endorsement at last week’s Markets and Reliability Committee meeting. Sixty-one members voted in favor, with 59 voting against.

John Rohrbach, representing Southern Maryland Electric Cooperative, presented the issue charge designed to consider whether an administrative mechanism, such as a circuit breaker, should be established in PJM’s energy market to protect consumers and market participants from financial impacts resulting from scarcity price signals.

Rohrbach said the recent pricing events in ERCOT, SPP and MISO during the winter storm emergency in February illuminate the potential adverse impact from the lack of a circuit breaker in PJM’s ORDC and transmission constraint penalty factor rules. Rohrbach said the issue charge was designed to highlight the lack of a circuit breaker in the future PJM ORDC rules and pertinent sections of the Operating Agreement for addressing an extended period in which ORDC penalty adders are binding.

Rohrbach said extreme pricing for an extended or indefinite period during an emergency can create costs that far exceed the value of any contribution to preserve grid reliability.

PJM uses an ORDC and transmission constraint penalty factors to establish locational marginal pricing. Under current PJM rules, the maximum price the energy component of an LMP can reach is $3,750/MWh.

But the “downward sloping” ORDC that was approved by FERC in May 2020 and takes effect in PJM on May 1, 2022, allows the RTO’s LMPs to reach or exceed $12,050/MWh in cases of extreme reserve shortages. (See FERC Approves PJM Reserve Market Overhaul.)

Key Work Activities

Adrien Ford of Old Dominion Electric Cooperative outlined the key work activities of the issue charge.

The first includes education on the current and pending PJM market rules for use of ORDCs and transmission constraint penalty factors in LMPs, including the input assumptions for the ORDCs. Ford said the education will also include pricing rules during emergency actions, triggers for performance assessment intervals (PAI) and the automatic use of the maximum reserve penalty factors. Education is slated to begin in July.

The second key work activity features exploring potential circuit breakers or other stop loss approaches that could limit extreme pricing when the cost “likely far exceeds the value of any contribution to preserving grid reliability.”

Ford said discussion would also include potential additional operational authorities needed by PJM to maintain grid reliability under conditions with excessive costs.

“Grid reliability is extremely important,” Ford said.

Work on the second key work activity is expected to take six months. Ford said efforts will be made to expedite voting to receive FERC action on any potential rule changes before the downward sloping ORDC takes effect in May 2022.

The third key work activity features exploring potential enhancements to PJM’s ORDC rules to address the impact of recent changes in PJM’s dispatch protocols on forecast uncertainty. Ford said stakeholders will examine and address the additional market and credit risks of the ORDC changes considering the recent pricing events in ERCOT, SPP and MISO.

Work on the issue charge will take place in the Energy Price Formation Senior Task Force.

Stakeholder Opinions

Stakeholder opinions on the issue charge were divided, with some saying the planned work doesn’t go far enough and others indicating the issue could become too complicated to implement before the ORDC changes next year.

Kent Chandler, executive director of the Kentucky Public Service Commission, said he sees the new ORDC as a “massive risk” to consumers in PJM. Chandler said the revised ORDC should have never been filed by the PJM Board of Managers or approved by FERC. (See PJM Files Energy Price Formation Plan.)

A review of the ORDC is necessary, Chandler said, but PJM and stakeholders need to “move immediately” to ensure a circuit breaker is in place before the implementation in May 2022. Chandler said any proposal that doesn’t prioritize having a circuit breaker in place at the end of the work is “inadequate.”

Dominion Energy’s Jim Davis, a co-sponsor of the issue charge, said the concept behind the work is not to reexamine the ORDC issue but focus on the creation of a circuit breaker. Davis said in order to develop an effective stop-loss provision, stakeholders need to be able to consider different aspects of the ORDC set to be implemented.

“I think we’re fortunate to be able to contemplate a circuit breaker prior to the implementation of the new ORDC construct, but we cannot do so in a vacuum,” Davis said. “We need to be able to consider enhancements to the ORDC rules.”

Susan Bruce, counsel to the PJM Industrial Customer Coalition (ICC), said many ICC members have facilities in ERCOT, SPP and MISO that were impacted by the winter emergency event and don’t want to see a similar event happen in PJM. Bruce said it’s the stakeholders’ responsibility as “stewards” of the PJM market to make sure markets work for customers.

“We want to make sure the markets are working for all market participants,” Bruce said.

Becky Robinson of Vistra said she believed it was more appropriate to proceed with a “focused effort” to address circuit breakers instead of a broader discussion in the issue charge. Robinson said the work to create a circuit breaker could be “weighed down” by a broader discussion of the issue.

Paul Sotkiewicz of E-Cubed Policy Associates said the third key work activity in the approved issue charge was “a bit more open-ended” than he would like. Sotkiewicz said having the circuit breaker in place is very important but thinks discussions may get “bogged down” in the third key work activity and won’t get to the point of creating a circuit breaker.

Sharon Midgley of Exelon presented an alternative problem statement and issue charge on behalf of multiple sponsors regarding a scarcity pricing circuit breaker for a vote. Midgley said the alternative issue charge arose out of the “overly broad scope and ill-defined problems” of the first issue charge and to focus specifically on creating a circuit breaker.

June 28, 2021November 29, 2023

New Jersey Lawmakers Back Offshore Wind Bills

New Jersey lawmakers moved several wind energy and vehicle electrification bills ahead last week in a flurry of activity before the legislative summer break begins. Both houses approved a key proposed law that will allow offshore wind developers to override local and state government to site transmission lines and related infrastructure for their projects on public land.

Passed Thursday, the offshore wind override bill, S3926, now sits on Gov. Phil Murphy’s desk. The Assembly last week also approved A1971, which would create a pilot program to use electric buses in three school districts, and A4899, which would extend to electric motorcycles the incentive program that the state operates to encourage the purchase of electric vehicles.

A fourth bill, A5840, also backed by the Assembly, would authorize the state treasurer and New Jersey Economic Development Authority (NJEDA) to partner on a lease for property and improvements for the New Jersey Wind Port project in South Jersey. The three Assembly-approved bills still need Senate approval to advance.

The votes came as lawmakers prepare to wind down activities for the summer on June 30. Little legislative action is expected before the Nov. 2 elections, when the governorship and Senate and Assembly seats are up for a vote. Pending bills can then be taken up and voted on before the end of the session on Jan. 11, 2022.

Removing Obstacles to Offshore Wind

The offshore wind legislation, S3926, is designed to smooth the way for offshore wind projects as New Jersey strives to reach the goal of deploying 7,500 MW of offshore wind capacity by 2035. The New Jersey Board of Public Utilities (NJBPU) on Wedneday is expected to announce the developer of the state’s second designated offshore wind project. The first project, the $1.6-billion Ocean Wind project awarded in 2019, will eventually put 98 wind turbines 15 miles off the Jersey shore. The state expects to award a total of six offshore wind projects by 2035.

S3926 would allow qualified offshore wind developers to site, construct and operate “wires, conduits, lines, and associated infrastructure” needed to connect an offshore project to the grid on public land, regardless of any opposition from local authorities as long as they are consulted. The bill stipulates that the connecting infrastructure should be buried underground.

The bill, approved 49 to 26 in the Assembly and 25 to 13 in the Senate, also would allow a qualified offshore wind developer to seek a waiver from the NJBPU to allow the project to advance if a local or state government body denied the project a critical easement or right of way.

Sen. Bob Smith (D), a bill sponsor, acknowledged at a Senate hearing earlier this month that the bill is “pretty powerful,” because it overrides the state’s long-held tradition of home rule, under which local authorities make the decisions that affect their own back yard. But Smith and other supporters said the need to move speedily to combat climate change makes the measure necessary.

The bill drew support from the New Jersey Chamber of Commerce and some environmental groups, while other environmentalists opposed it, saying it was an overreach that encroached on local power. (See: NJ Lawmakers Back Local Override for Offshore Wind Transmission).

Three Democratic Assemblymen who co-sponsored the bill, John Burzichelli, James Kennedy and Robert Karabinchak, released a statement after the bill’s passage saying that offshore wind projects are “poised to provide clean, renewable energy to New Jersey.”

“Once more projects begin, the benefits of getting involved in the sustainable energy industry will bring more jobs for residents and a significant investment into the State’s economy,” the statement said. “This legislation will further support the BPU’s timeline for solicitations of wind energy generation by making clearer the roles of these projects in municipalities.”

Electrifying Motorcycles, School Buses

Other clean-energy-related legislation that moved forward last week included:

- - A5840 authorizes the state, through the NJEDA, to sign a lease and begin improvements on property in Lower Alloways Creek Township, where the state is seeking to build the New Jersey Wind Port. The project is part of New Jersey’s effort to create a manufacturing and logistics hub that will serve the offshore wind industry in the state and other parts of the East Coast. The NJEDA is in negotiations for property in the township that could be used for a marshalling, installation and manufacturing hub, according to the legislation. The bill passed the Assembly with a 48-25 vote, and a Senate vote is expected on Wednesday.
  - A1971 would require the NJBPU to allocate $10 million to create a pilot electric school bus program. The aim of the project would be to ”determine the operational reliability and cost effectiveness of replacing diesel-powered school buses with electric school buses for daily transportation of students.” One of the three school districts selected for the pilot must be either a low-income, urban or environmental justice community. The selected districts or bus companies must file regular reports “detailing the cost to operate the electric school buses and any reliability issues related to the operation of the electric school buses.” The bill, which the Assembly backed 57 to 14, will now be heard by the Senate Economic Growth Committee.
  - A4899 would extend the state’s program for providing incentives to electric vehicles with new incentives of up to $1,000 for electric motorcycles. The rules for calculating the size of the incentives would be created by the NJBPU. The bill passed the Assembly 72 to 3; an identical bill has yet to be heard in the Senate.

June 28, 2021December 10, 2023

NEPOOL Participants Committee Summer Meeting Briefs: June 24, 2021

External Market Monitor Delivers 2020 Assessment

ISO-NE energy prices and uplift costs exceed those in other RTO markets, External Market Monitor Potomac Economics told the NEPOOL Participants committee last week.

The Monitor was presenting its 2020 ISO-NE assessment at the committee’s annual summer meeting.

Other than ERCOT’s energy-only market, ISO-NE had the highest average prices among RTO markets over the last three years because of higher natural gas prices.

The Monitor also found that New England energy prices are more sensitive to costs for complying with state greenhouse gas emissions policies. Compliance with the Regional Greenhouse Gas Initiative (RGGI) last year added about $6.60/MWh to the marginal production costs of a gas-fired combined cycle generator in Massachusetts and $2.90/MWh in the other five New England states. While NYISO is also subject to RGGI, no such programs impact generators in ERCOT or MISO. RGGI compliance costs are included in a small number of PJM states.

ISO-NE also incurs more uplift costs than MISO and NYISO, in part the result of New England’s higher fuel costs and the fact that ISO-NE does not have day-ahead ancillary services markets to coordinate and price its system-level and local operating reserve requirements.

ISO-NE additionally makes real-time net commitment period compensation (NCPC) payments to resources under a broader range of circumstances than MISO and NYISO. In 2020, ISO-NE’s market-wide NCPC uplift ($0.42/MWh) was more than double that of NYISO ($0.19) or MISO ($0.18). Day-ahead ancillary services markets also help reduce uplift charges.

And while all three markets have rules for compensating a generator whose scheduled output level differs from its most profitable output level, ISO-NE’s tariff provides compensation in some circumstances when MISO’s and NYISO’s do not. The Monitor recommended that the grid operator examine differences and identify best practices across markets.

ISO-NE does experience far less congestion than other RTOs. Congestion costs have averaged under $0.35/MWh in the last five years, 10 to 20% the levels seen in other RTO markets. That reflects significant transmission investments made over the past decade, resulting in a transmission service cost of more than $19/MWh in 2020, which is far higher than the rates in other RTO markets.

Transmission investments made in ISO-NE primarily satisfy relatively aggressive local reliability planning criteria. The primary reasons for transmission expansion in ERCOT, MISO and NYISO have been to increase the deliverability of renewable generation to consumers, the EMM said.

The Monitor withdrew its recommendations to improve the minimum offer price rule (MOPR) after ISO-NE said it plans to eliminate the rule to ensure market access for state policy resources but will reassess in the future.

The EMM also plans to provide comments to NEPOOL this summer identifying market rule changes needed to ensure that the markets will attract necessary investment and maintain needed existing units after the MOPR is eliminated. Such changes will improve the RTO’s accreditation of capacity resources and reflect increased financial risk in the capacity demand curves that investors will face in New England without the MOPR.

RTO Presents Preliminary Budgets for 2022-23

ISO-NE Chief Financial and Compliance Officer Robert Ludlow provided a look at the preliminary 2022 and 2023 operating and capital budgets, with the respective year-over-year increases before depreciation for the operating budgets projected to be $10.61 million (5.9%) and $9.16 million (4.8%).

The RTO plans to add several full-time equivalent positions to address changes impacting the capacity market, including the proposed elimination of the MOPR. Additional new FTEs will:

help deal with increased interconnection studies for renewable resources;
work on continuing studies on carbon pricing and a forward clean energy market; and
consult on the Pathways to the Future Grid work.

The RTO expects its capital budget over the next five years to increase from $28 million to $35 million, including $32 million for 2022. The primary drivers of the spending spike are: GEMplatform replacement, cybersecurity, the clean energy transition, and reliability improvement projects, as well as IT asset and infrastructure replacement.

The proposed budget timeline includes meeting with state officials in August and the RTO’s Board of Directors in September, a vote before the Planning Committee during its Oct. 7 meeting and filing with FERC by Oct. 15.

June 28, 2021January 19, 2024

Minnesota’s ‘Clean Cars’ Emissions Standards Debated, Approved

In a game of political chicken over the state’s “clean cars” emissions standards, Minnesota’s Democratic-Farmer-Labor legislators have won. This time.

After months of debate and efforts by the state’s Republicans to stall the upcoming two-year budget if DFL Gov. Tim Walz did not rescind his clean cars proposal, the Minnesota House of Representatives on Friday approved by a 99-34 vote an environmental budget bill that includes tougher vehicle emissions standards and requires state auto dealers to carry more hybrid and electric vehicles.

But in this ongoing, hotly debated battle, which pushed the Minnesota Legislature into special session, the matter is likely to turn into a key 2022 election issue. Walz is up for re-election. Republicans, who are are hoping to gain control of the Minnesota House as well, are suggesting the governor has abused his emergency powers authority and pointing to civil unrest in Minneapolis following the death of George Floyd.

The state’s DFL party controls the Minnesota House of Representatives 70-64. The Republican caucus holds a slim 34-31-2 edge in the Minnesota Senate. And the Senate Majority Leader, Sen. Paul Gazelka (R), who helped negotiate the compromise bill, has made it clear the fight is not over. The compromise bill passed 49-14 in the Senate.

“The environmental bill will be moving forward,” Gazelka had said in a press conference earlier last week, confirming the Senate Republicans had backed down on their demand to delay the Minnesota Pollution Control Agency (MPCA) from implementing emissions standards effective Jan. 1, 2024.

Gazelka said that he did not approve of an administrative law judge’s decision in early May to support Walz’s tougher car emissions standards, which closely align with California’s rules, nor with the MPCA’s role in any rulemaking. He and fellow Republicans want the standards addressed in a legislative process. Instead, Gazelka says the compromise “means this becomes an election issue.”

Friday’s two-and-a-half-hour debate on the clean cars issue showed that the vehicle emissions standards have become a political hot potato in Minnesota.

Even the state’s more liberal DFLers weren’t overly excited about the comprehensive environmental bill, which included $367 billion for agencies and programs ranging from the MPCA, the Department of Natural Resources, state parks, the Minnesota Zoo and Science Museum. Progressive DFL legislators didn’t think it went far enough into dealing with climate change.

Rep. Rick Hansen (DFL) authored the House bill and was one of a small group of legislators who helped frame the compromise.

“I come here not to praise this bill nor to bury it,” Hansen said Friday before debate. “I come here to ask you to vote for it.” He acknowledged “weeks of very, very, very difficult negotiations.”

But Hansen, who in earlier conference committee meetings often criticized Republican efforts to stall the vehicle emissions standards as “brinkmanship,” said “we’re just disgusted by it,” and moved quickly back to political jabs at the opposition. Hansen said Republicans used “closure of the (state) parks…as a potential bludgeon.”

Hansen also used his time to criticize proposed cuts by Republicans of several environmental issues advocated by DFLers in the Minnesota House.

“The Senate [Republicans] had proposed cutting pollinators (funding for programs to foster an increase in bees and monarchs),” Hansen said. “They had proposed cutting microplastics (funding). They had proposed cutting STEM projects. They had proposed cutting funds for the Science Museum. All that is restored.”

Republican Rep. Josh Heintzeman led the party’s opposition to the clean cars language in the bill. But two amendments he proposed were defeated in party-line votes. The first had requested the bill be sent back to the Minnesota House committee for discussion; the second was to delete the clean cars language entirely from the bill.

“Obviously, there’s been a controversial discussion about this issue,” Heintzeman said, adding that the Republicans’ goal was to ask that the MPCA “no longer intends to pursue (emissions standards) adoption” until “a thorough opportunity to get to some of the facts.”

A significant number of fellow Republican House members supported Heintzeman’s amendment proposals to slow down or eliminate the MPCA’s rulemaking authority.

“It don’t (sic) make sense to follow California standards and also technology that’s not up to snuff in Minnesota weather,” said Rep. Jeff Backer, (R). Backer said electric car batteries don’t perform well in minus-30 degree cold.

Backer said other than Republicans’ ongoing disagreement over Walz’s emergency powers actions during the COVID pandemic, the clean cars issue was the second most important issue among his constituents in north central and western Minnesota. Fellow Republican Rep. Brian Johnson was more blunt.

“We don’t need a bunch of legislators from California telling us what to do,” Johnson said. “We’ve seen the mess in California. It’s almost as bad as the mess in Minneapolis.”

Heintzeman added: “I don’t think the (MPCA) agency has the credibility to push something like this forward.”

“The technology is going to get better. That’s a good thing. But trying to force it through baffles as opposed to telling the market to reach those needs and expectations.”

Critics say bill doesn’t go far enough

Despite the compromise on the environmental bill, some DFLers in the State Senate voted against the package because of its lack of attention to climate change issues.

“We’ve got a problem here and a real crisis,” said 11-term DFL Sen. John Marty, one of the Senate’s most liberal legislators.

“I’ve talked to a lot of people who want to buy electric cars, and their dealers don’t carry them,” Marty said. “But we can’t talk about climate change in this bill. I’m going to vote against it because of that.”

Sen. Bill Engebrigtsen (R), who chaired the Senate’s environmental committee and championed its bill, often said Walz’s clean cars initiatives could not be included and was willing to shut down state government if it was. But he backed down from that stance.

“Everybody is anxious to move on,” he said. “This is a good bill.”

Fellow Republican Sen. Andrew Mathews disagreed and said the matter should not be left up to executive branch rulemaking, calling it an effort “to go around the legislative process.”

“The people of Minnesota have several shots down the road to get this changed,” he added, hinting at hopes the Republicans can win control of both state chambers and the governor’s race.

But Gazelka, who fellow Republicans in the House criticized for closing them out of negotiations, had the final word.

“It’s always a cautionary tale of be careful you don’t go too far, too soon,” he said. “I don’t want to follow California emissions standards. I think Minnesota could have found its own way.”

June 28, 2021November 27, 2023

Paper Hearing Opened on PJM DFAX Method

FERC ordered a paper hearing Friday to reconsider whether the 1% de minimis threshold and netting provisions of PJM’s solution-based distribution factor (DFAX) method result in fair transmission cost allocations (EL21-39).

Neptune Regional Transmission System and Long Island Power Authority (LIPA) filed a complaint last December alleging the assignment of costs of the regional cost allocation method included in the PJM tariff results in unjust and unreasonable rates.

In the complaint, Neptune and LIPA challenged PJM tariff provisions of the cost allocation method the commission previously accepted in Order 1000 for the portion of cost responsibility assigned to the solution-based DFAX method for transmission facilities selected in the RTO’s Regional Transmission Expansion Plan (RTEP) process.

The DFAX method allocates costs of new transmission facilities by modeling how each load zone contributes to the electricity flows over a new transmission facility. PJM simulates the incremental flow on the new transmission facility resulting from an increase in load of 1 MW in each load zone, FERC said, while holding load in all other load zones at a constant.

The result of PJM’s calculation is the DFAX value, the commission said, which represents incremental flows on the new transmission facility “per incremental increase in demand for a particular load zone.” PJM then applies a 1% de minimis threshold to the calculated DFAX values and replaces any DFAX value less than 0.01 with a DFAX value of zero.

As part of the procedure, PJM models the transfer of the net of energy flow in the positive and negative directions from generation to all load within an individual transmission zone.

The commission had rejected a 2015 complaint by Linden VFT that raised similar allegations (EL15-67), reiterating its position in rulings last year. (See FERC Rebuffs Challenges to PJM Tx Cost Allocation.)

But the commission said the new complaint, and filings by Exelon supporting it in part, persuaded it “to look anew at the question of whether the 1% de minimis threshold and netting provisions of PJM’s ex ante cost allocation method have become unjust and unreasonable.”

Complaints

Neptune owns the Neptune Line, a merchant transmission facility running from northern New Jersey in the Jersey Central Power and Light zone of PJM to New York. Neptune holds 685 MW of firm transmission withdrawal rights.

LIPA contractually holds long-term transmission rights over the Neptune Line through Dec. 31, 2027, and pays the transmission enhancement charges assessed to Neptune under Schedule 12 of the PJM tariff.

Neptune and LIPA said netting and 1% de minimis threshold provisions in the PJM tariff “materially distort the assignment of cost responsibility resulting from application of the solution-based DFAX method.” The companies said the netting of modeled energy flows in both directions across a transmission facility “produces an incorrect measure of total usage,” and the de minimis threshold “arbitrarily excludes zones from cost allocation.”

Neptune and LIPA also assert that the netting and 1% de minimis threshold provisions “result in cost responsibility assignments that are not roughly commensurate with derived benefits,” making them unjust and unreasonable. The companies said the DFAX method should be “implemented without netting, by measuring gross zonal usage of a transmission facility in the positive and negative directions and assigning cost responsibility based on each zone’s gross relative usage in both directions.”

Neptune and LIPA submitted examples showing a zone with the highest relative use of a transmission facility receiving no cost allocation for the facility.

Questions

FERC listed 14 questions for PJM and stakeholders to answer in the paper hearing.

The commission said it wants an explanation on whether cost responsibility under the DFAX method with a de minimis threshold value less than 1% “should be considered anomalous rather than an indication that there is a circuitous low-impedance path for a zone to serve its own load.”

FERC also said it wants to know why it’s appropriate to “exclude zones from cost allocation based on their solution-based DFAX values rather than their relative megawatt usage of the transmission facility in question” under a “beneficiary-pays approach to cost allocation for transmission facilities.”

Stakeholders interested in intervening were given 21 days to notify FERC of their intent. Responses to FERC’s questions are due within 60 days of the order, and comments on the responses are due 30 days after that.

June 28, 2021January 19, 2024

PJM MRC/MC Briefs: June 23, 2021

Markets and Reliability Committee

ICSA Revisions Endorsed

Stakeholders unanimously endorsed PJM’s proposed tariff revisions to address concerns associated with the pro forma interconnection construction service agreement’s (ICSA) lack of superseding language and current automatic termination provision.

Mark Sims, PJM manager of infrastructure coordination, reviewed the proposed solution and associated tariff revisions at last week’s Markets and Reliability Committee meeting. Sims first presented the issue at the March MRC meeting, with stakeholders providing recommendations to PJM’s proposal.

The Planning Committee endorsed the changes in May, as PJM said the growing interconnection queue volume has created the need for improvements. (See “ICSA Endorsed,” PJM PC/TEAC Briefs: May 11, 2021.)

PJM identified improvements in two areas of tariff Attachment P that deal with ICSAs. Section 1 of the attachment does not contain pro forma language that considers when an ICSA supersedes an already effective agreement, and the solution involved simple tariff language revisions, Sims said.

The tariff also provides for automatic termination of ICSAs upon the occurrence of certain conditions, which can occur without PJM’s knowledge at the completion of construction of all interconnection facilities, a transfer of title, final payment of all costs or delivery of final as-built drawings to the transmission owner. PJM proposes to update the language to make any termination contingent upon PJM receiving notice of the conditions from the TO.

Sims said the changes directly relate to improving process efficiency related to the PJM interconnection queue volume. He said the vetting of the language at the PC and additional review and feedback at the Transmission Owners Agreement-Administrative Committee provided “great feedback” from stakeholders throughout the process.

“As a result, we have a very good proposal,” Sims said.

The tariff revisions will now go to the Members Committee on July 28 for a final vote.

Alex Stern, director of RTO strategy for PSEG Services, thanked PJM staff for “taking a little extra time” to work on the proposal. Stern said the additional work allowed language regarding the automatic termination provisions for conforming and nonconforming agreements to be clarified and enhanced.

Regulation Mileage Ratio First Read

Members questioned PJM’s proposed solution to address issues with the regulation mileage ratio, asking the RTO to reconsider the mileage value it has suggested as an alternative to the existing value.

Michael Olaleye, senior engineer with PJM’s real-time market operations, reviewed the proposed solution addressing the regulation mileage ratio and corresponding revisions to the tariff, the Operating Agreement and Manual 28: Operating Agreement Accounting. Olaleye first introduced the proposed solution at the May Market Implementation Committee meeting. (See “Regulation Mileage Ratio,” PJM MIC Briefs: May 13, 2021.)

Regulation mileage is the measurement of the amount of movement requested by the regulation control signal that a resource is following, and it’s calculated for the duration of the operating hour for each regulation control signal.

PJM’s performance-based regulation market splits the dispatch signal in two: RegA for slower-moving, longer-running units; and RegD for faster-responding units that operate for shorter periods, including batteries. If a signal is “pegged” high or low for an entire operating hour, the corresponding mileage would be zero for that hour.

Olaleye said PJM has seen increased frequency of RegA signal pegging and times the RegA signal is pegged for extended periods. He said the pegging highlights a potential problem in the regulation mileage ratio calculation, setting the RegA mileage at zero for a given hour and creating a divide-by-zero error in the calculation of the mileage ratio.

PJM is proposing to set the floor RegA mileage at 0.1 instead of zero, Olaleye said, which would allow for a “valid solution” for mileage ratio and still maintain market design objectives. He said there would be no impact to the regulation signal design, operations or regulation market clearing.

Independent Market Monitor Joe Bowring raised a counterproposal at the MIC after questioning PJM’s value of 0.1. Bowring proposed a cap of 5.5 on the realized mileage ratio in all hours, indicating the cap would eliminate the current undefined mileage ratio result that PJM is attempting to address, but it in a “preferable way.”

The cap would reduce but not eliminate the market distortion that results from the use of mileage ratios when they incorrectly represent regulation output, Bowring said, and would affect less than 50% of impacted hours based on data collected by the Monitor over the last 15 months.

Bowring said he believes the PJM proposal ignores the fact that there’s still going to be “excessively high” mileage ratios for a significant number of hours.

“It’s important to recognize this is more than just a simple mathematical issue,” Bowring said. “It reflects an underlying issue with mileage ratio.”

Calpine’s David “Scarp” Scarpignato said the numbers currently used in the regulation mileage ratio calculation are “majorly messed up” and need to be addressed. Scarp said Bowring’s solution “makes a lot more sense” than PJM’s because it uses a high mileage ratio but does not create “insane” results. Scarp said dividing by PJM’s 0.1 value “can give you some pretty insane numbers.”

“Joe’s proposal is a temporary fix that actually addresses the real issue, which is more than a mathematical issue,” Scarp said. “It’s where do you reach a point of craziness.”

ELCC Manuals

Andrew Levitt, of PJM’s market design and economics department, reviewed conforming revisions to Manual 18: PJM Capacity Market, Manual 20: PJM Resource Adequacy Analysis, Manual 21: Rules and Procedures for Determination of Generating Capability and Manual 21A: Determination of Accredited UCAP Using Effective Load Carrying Capability Analysis to address the effective load-carrying capability (ELCC) for limited-duration and intermittent resources.

ELCC sets the capacity value for storage and renewables. The revisions would require a unit’s ELCC accreditation to be updated annually based on system conditions and unit performance.

Stakeholders endorsed a revised joint stakeholder proposal to use the ELCC method to calculate the capacity value of limited-duration, intermittent and combination (limited-duration plus intermittent) resources at the September MRC and MC meetings. (See ELCC Method Endorsed by PJM Stakeholders.) Levitt said PJM expects a final ruling by FERC on the ELCC issue by July 30.

Levitt said Manual 18 includes conforming changes to coordinate the term “installed capacity (ICAP)” with new terminology used for ELCC resources, including the new term “accredited unforced capacity (UCAP).”

Manual 20 has a description of the technical details of the ELCC analysis and its methodology, Levitt said, while Manual 21 strikes the “10-hour rule” for limited-duration resources and provides for a sunset date of June 1, 2023, for testing provisions for ELCC resources in the manual.

Levitt said Manual 21A is a new manual describing the business processes for deriving an accredited UCAP value for each ELCC resource.

Stakeholders will be asked to endorse the proposed revisions at the July MRC meeting.

Levitt said PJM is proposing to have ELCC tariff rules currently in front of FERC take effect by Aug. 1 so they’re able to be applied to the 2023/24 delivery year and Base Residual Auction, scheduled for Dec. 1.

Consultant Roy Shanker asked Levitt what PJM would do if FERC doesn’t act on the ELCC proposal by July 30.

Levitt said FERC has a statutory obligation to make a decision by July 30. He said if the commission’s decision involves a denial of the ELCC proposal or moving the decision date, PJM would have to “assess our options.” He said he has a “difficult time seeing” how PJM could run the 2023/24 BRA under ELCC rules if FERC doesn’t approve them on time.

Manual 14 Revisions Endorsed

Stakeholders endorsed revisions to Manual 14B: PJM Region Transmission Planning Process and Manual 14F: Competitive Planning Process conforming to tariff revisions accepted by FERC in December (ER21-162) in the MRC consent agenda.

PJM proposed including capacity constraints as inputs to the analysis for market efficiency projects in the Regional Transmission Expansion Plan and to clarify when capacity benefits of such projects are calculated. Both manual changes were unanimously endorsed at the May PC meeting. (See “Manual 14F and 14B Updates,” PJM PC/TEAC Briefs: May 11, 2021.)

Members Committee

Consent Agenda

Two proposals were endorsed with two objections as part of the consent agenda at last week’s MC meeting.

Stakeholders endorsed tariff revisions to address new service requests deficiency review requirements. Members unanimously endorsed the proposed solution and tariff revisions at the May MRC meeting. (See “New Service Requests Approved,” PJM MRC Briefs: May 26, 2021.)

Members also approved OA revisions to address the avoidance of future CIP-014 facilities. The avoidance proposal was approved by an acclamation vote at the May MRC meeting. (See “CISO Avoidance Endorsed,” PJM MRC Briefs: May 26, 2021.)

June 28, 2021December 6, 2023

California Air Resources Board Sounds off on Net-zero Roadmap

The California Air Resources Board (CARB) has started work on a scoping plan that will serve as a roadmap for the state to reach net-zero greenhouse gas emissions by 2045.

And though it’s just the beginning of what’s expected to be an 18-month process to develop the plan, some board members voiced strong opinions last week during a meeting on what areas deserve emphasis.

For board member Hector De La Torre, transportation, natural and working lands, and short-lived climate pollutants should be the primary areas of focus if the state wants to meet an interim target of reducing GHG emissions to 40% below 1990 levels by 2030. The short-lived pollutants include methane, hydrofluorocarbons and black carbon.

Those sectors did not deliver GHG reductions during the past decade, De La Torre said during a CARB board meeting on Thursday.

“Those three have to step up,” De La Torre said. “If we’re going to do this, and I believe we are, then we need to have all of these sectors deliver GHG reductions in the next nine years.”

Board member Daniel Sperling pointed to transportation electrification as a way to reduce air pollution and improve public health. The transportation sector accounts for more than 40% of the state’s emissions, according to CARB data.

In addition, Sperling said, CARB has jurisdiction over transportation electrification.

“This is within our wheelhouse, and it’s the most important thing we’re going to do as part of this scoping plan,” said Sperling, who is a founding director of the Institute of Transportation Studies at the University of California, Davis.

During last week’s meeting, board members heard a presentation on the scoping plan process. Although several board members made comments, the board took no formal action.

Scoping Plan Update

The scoping plan is an outgrowth of Assembly Bill 32, also known as the Global Warming Solutions Act of 2006.

AB 32 requires CARB to develop a scoping plan that lays out a strategy for California to meet its GHG reduction goals. The plan must be updated at least once every five years.

The initial scoping plan was approved in 2008 with updates in 2014 and 2017. The next version of the plan is expected to go to the CARB board for approval in late 2022, following release of a draft plan in the spring.

With an eye toward carbon neutrality by 2045, the 2022 scoping plan will have the longest planning horizon of any scoping plan to date.

Environmental Justice Issues

As part of the process to develop a scoping plan, AB 32 requires CARB to convene an environmental justice advisory committee (EJAC) that includes representatives of communities with high levels of air pollution, including minority and low-income communities.

Several speakers during Thursday’s board meeting criticized CARB for relegating to an appendix the EJAC’s nearly 200 recommendations for the 2017 scoping plan.

EJAC member Paulina Torres asked the board to direct CARB staff to review and analyze the EJAC recommendations from the 2017 plan. That way, the previous recommendations can be used as a foundation for the current EJAC’s work, she said.

“It’s one way to signal that EJAC recommendations won’t just be appendicized somewhere, but that staff is really prioritizing and taking these measures seriously and conducting the necessary, detailed analysis,” said Torres, who is a staff attorney for the Center on Race, Poverty & the Environment.

Another issue for Torres is pesticides and their contribution to GHG emissions. Torres said that CARB should consult with the California Department of Pesticide Regulation in developing the scoping plan.

EJAC member Sharifa Taylor called for better integration of the committee’s work into the body of the scoping plan, rather than listing recommendations in an appendix.

Taylor also cautioned against focusing on the 2045 net-zero goal at the expense of the interim 2030 goal of reducing GHG emissions to 40% below 1990 levels.

“We’re getting to a point where our climate impacts are becoming accelerated and potentially unstoppable,” she said.

June 28, 2021

Western ‘Megadrought’ Curtails Hydropower

A drought in the West is cutting into hydropower supplies that are important for summer reliability and threatening to have longer-term effects on the region’s grid, panelists said Friday in a session hosted by the United States Energy Association.

In its short-term energy outlook in June, the U.S. Energy Information Administration predicted the Western Interconnection’s hydroelectric production will decrease 9% from last year, the lowest level since 2015, EIA senior economist Tyler Hodge said.

“When you throw in things like extreme weather events … it could really add a lot of uncertainty,” Hodge said.

Lower hydro generation could increase reliance on natural gas generation and raise prices for natural gas, he said. If California or other states require additional imports to offset the reduction in hydropower, it could cause transmission congestion, he said.

The Pacific Northwest and California account for most of the hydroelectric generation in the nation, and both areas are experiencing dryer-than-average conditions.

Snow water content in California peaked at 60% of normal in 2021 after a similarly dry winter last year, CAISO said its annual summer resource assessment. The average water level in large reservoirs was 70% of normal earlier this year. (See CAISO Could See More Outages this Summer.)

CAISO used Northwest River Forecast Center projections to assess hydropower imports this summer from the Pacific Northwest. The hydrologic center predicted reservoir storage at The Dalles Dam on the Columbia River, a key indicator, will be 89% of average from April to September.

Hydropower accounts for about 15% of California’s summer peak capacity, making it the second largest generation source after natural gas, which fills 57% of the state’s resource needs.

FERC focused on the California hydropower crisis in its Summer Energy Market and Reliability Assessment. Snowpack, the state’s main source of dry-season water, was critically low at 6% of normal levels May 11. Earlier-than-normal runoff will worsen the situation, FERC said. (See FERC Summer Assessment Spotlights Western Drought Risks.)

CAISO has said low in-state hydro could cause problems meeting peak demand this summer. In Friday’s meeting, CEO Elliot Mainzer said the situation adds volatility to resource planning and needs to be accounted for. Whether drought conditions will abate or continue is a big unknown, he said.

“The uncertainty … is absolutely something that we now need to bake into our planning,” Mainzer said.

Hotter, dryer conditions exacerbate the water shortage, he said. Severe heat waves in the West led to energy emergencies in California and Nevada last summer, and heat waves have already impacted Western states this year.

Triple-digit temperatures and strained resources caused CAISO to issue a warning in June. Portland, Ore., hit a record high of 112 degrees Fahrenheit on Sunday; a similar temperature was expected Monday, the National Weather Service said.

“The associated heat is the other variable that is really putting a lot of stress on the grid at the moment,” Mainzer said.

“Under normal conditions, even on a day when it’s really hot in California, but it’s not super hot in Portland or Salt Lake City or Phoenix, our grid is typically OK,” he said. “But when it gets simultaneously hot and dry in all these different regions, the amount of power available to California through imports … puts a lot of stress on the system.”

June 28, 2021November 27, 2023

Ohio Lawmakers Vote to Block Local Natural Gas Bans

Ohio joined 18 other states Thursday in adopting legislation backed by the gas industry barring municipalities from prohibiting or limiting access to natural gas or propane. The bill now heads to Gov. Mike DeWine’s (R) desk.

Ohio was the seventh largest producer of natural gas among the 35 gas producing states, the Energy Information Administration reported in 2020, based on data collected a year earlier. Though opposed by some local governments as well as the Ohio Municipal League as a violation of the Home Rule provisions in the state constitution, passage of H.B. 201 was never in question. The bill cleared the Senate on a 25-7 party-line vote Thursday after passing the House 65-32 in May with all but two Democrats opposed.

A number of gas industry and manufacturing representatives testified on behalf of the legislation, including the Ohio Manufacturers’ Association, the American Petroleum Institute-Ohio, the Ohio Home Builders Association, the Ohio Oil and Gas Association, state and local chambers of commerce, and a utility workers local.

Encino Energy, currently the second largest producer of shale gas in the state, submitted testimony in favor, saying, “We believe it will benefit Ohio’s consumers, the state’s economy and the environment by protecting the consumers’ right to choose natural gas.”

The state’s gas distribution utilities began discussing legislation to prevent gas bans 18 months ago after several Ohio cities adopted resolutions endorsing a goal of 100% renewable energy.

The primary sponsor, Rep. Jason Stephens (R), represents rural Appalachian counties in southeast Ohio, which while not the heart of the state’s shale gas activity, do produce some natural gas.

“House Bill 201 is a very simple piece of legislation that preserves a customer’s right to choose the energy option that works best for them while making sure that every community in Ohio with natural gas maintains the ability for its citizens and its businesses to access this abundant source of Ohio energy,” Stephens said in opening testimony earlier this spring.

The bill “bars any political subdivision” from enacting any ordinance, resolution, building code, or other similar requirement that “limits, prohibits or prevents” any consumer from obtaining natural gas service or propane.

The legislation was opposed by the Ohio Mayors Alliance, the Ohio Environmental Council, the Natural Resources Defense Council and several other green groups.

Daniel Sawmiller, the NRDC Ohio energy policy director, called the legislation “underhanded” in a statement issued after the vote on Thursday.

“The gas industry has a simple goal: stop people across Ohio from getting clean and healthy energy in their homes. This underhanded bill takes away the longstanding authority of local governments to meet the energy needs of their residents in the safest, most common sense and cost-effective way. It would block local governments from shaping their permitting rules to encourage healthier, low emissions, all-electric buildings.

“Instead, Ohio communities would stay hooked on gas and be forced to pay for unwanted, costly and unnecessary fossil fuel infrastructure for decades to come. That’s wrong, and Gov. DeWine should veto this unfair legislation,” Sawmiller said in an email.

Home Rule Violation?

In testimony earlier this spring, Garry Hunter, general counsel for the Ohio Municipal League wrote: “I believe this legislation violates the Home Rule provisions of the Ohio Constitution and should not be adopted.”

The Ohio Mayors Alliance, representing mayors in more than two dozen of the state’s largest cities, also opposed the bill. “The importance of local self-governance and municipal home rules is a core principle of Ohio’s Constitution,” it said.

The constitution says, “Any municipality may frame and adopt or amend a charter for its government and may, subject to the provisions of section 3 of this article, exercise thereunder all powers of local self-government.”

Section 3 says, “Municipalities shall have authority to exercise all powers of local self-government and to adopt and enforce within their limits such local police, sanitary and other similar regulations, as are not in conflict with general laws.”

In written and oral testimony before committees, Randi Leppla, vice president of energy policy for the Ohio Environmental Council Action Fund, described the bill as “a solution in search of a problem.

“H.B. 201 would limit local governments from passing resolutions or making changes to city building and zoning codes that would limit or prohibit access to natural gas, despite the fact that no city in Ohio has passed a ban of this nature through resolution or building code updates.

“Proponents of this legislation specifically point to these types of bans on the coasts as the reasoning for passing such legislation, not because of any need here in Ohio,” she said.

According to the NRDC, Ohio would join Alabama, Arkansas, Florida, Georgia, Indiana, Iowa, Kansas, Kentucky, Mississippi, Missouri, Texas, Utah, West Virginia and Wyoming in passing such legislation. Similar legislation is still pending in Pennsylvania, North Carolina and Michigan. Arizona, Louisiana, Oklahoma and Tennessee approved similar legislation last year.