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November 8, 2024

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FERC Grants MISO Temporary Storage Waiver

FERC last week gave MISO a hall pass on ensuring offline energy storage resources (ESRs) can furnish certain types of energy reserves.

Thursday, the commission granted the RTO both a temporary waiver and removal of tariff language that states offline storage resources can provide supplemental reserves or short-term reserves. The waiver is effective Nov. 23, 2021, and the tariff edits took effect Dec. 7 (ER22-461 and ER22-462).

MISO said that in implementing its new short-term reserve product late last year, it discovered that its markets cannot clear those reserve offers from energy storage resources, which currently only participate as either Stored Energy Resource Type II (SER Type II) or Demand Response Resource Type II (DRR Type II).

The grid operator said since its systems currently cannot track energy storage’s state of charge, it can’t detect whether those storage assets are offline.

SER Type II is a temporary resource designation created in 2017 for use until no later than 2023, when MISO should have a full participation model in place for storage under FERC’s Order 841. SER Type II was modeled after MISO’s existing DRR Type II. (See FERC OKs MISO Plan to Expand Storage.)

The RTO has committed to phasing out SER Type II “soon after” storage resources have access to full market participation under MISO’s Order 841 compliance design. The grid operator will begin registrations for storage assets in early June and open full market participation to them sometime in September.

MISO said it would be “extremely complicated, costly and time-consuming to explore, develop, test and install a software solution” that would allow offline storage to provide short-term and supplemental reserves until its full storage participation model is up and running.

FERC called the waiver an “appropriate interim solution.”

The Solar Energy Industries Association (SEIA) protested MISO’s plan, arguing that it “must compensate offline storage resources for the services those resources provide.”

But the commissioners agreed that MISO shouldn’t have to incur steep costs and man-hours creating a temporary fix. It also said the RTO seemed to have acted in good faith.

“We disagree with SEIA’s arguments that MISO’s proposed tariff revisions are an attempt to limit storage resources’ ability to participate in the markets. We note that, in fact, MISO’s proposed tariff revisions are a temporary measure until such time when [energy storage resources are] fully integrated in MISO’s markets,” FERC said.

MISO’s short-term reserve product went live Dec. 7. It’s meant to source energy within 30 minutes where needed from both online and offline resources, while accounting for real-time transmission constraints. (See MISO Begins Software Build on Short-term Reserves.)

The grid operator has said the reserves will reduce make-whole payments, cut down on out-of-market commitments, make market pricing more transparent, and provide pricing signals that encourage a greater number of fast-start resources that can meet voltage and local reliability requirements more cheaply.

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Tri-State Reaches Settlement over Resource Plan

Tri-State Generation and Transmission Association has reached a settlement with more than two dozen of its members and other parties over the first phase of its 20-year, $21.3 billion plan to reduce its carbon dioxide emissions.

The Colorado-based cooperative said Wednesday that the “landmark” agreement, filed for approval with the Colorado Public Utilities Commission, sets near-term targets for greenhouse gas emission reductions before 2030 as part of its Responsible Energy Plan (20A-0528E).

Duane Highley (SPP) Content.jpgTri-State CEO Duane Highley | SPP

Tri-State CEO Duane Highley thanked the cooperative’s members, state officials, environmental advocates and labor representatives who worked on the settlement, which he called “a meaningful advancement in our efforts to transform our cooperative as we responsibly serve reliable and affordable power to rural communities, for our members and Colorado.”

The agreement includes “numerous and complex provisions” resolving Phase I of Tri-State’s electric resource plan (ERP) that it filed with the PUC in December 2020 as part of an ongoing proceeding.

Under the settlement’s terms, Tri-State agreed to reduce GHG emissions related to its wholesale sales in Colorado by 26% in 2025, 36% in 2026, 46% in 2027 and 80% in 2030. The amounts will be calculated based on the cooperative’s 2005 emissions baseline.

Tri-State also said it will report its progress on GHG emission reductions to the commission in its ERP annual progress reports going forward and conduct a competitive solicitation for new resources with in-service dates through 2026.

The parties, which included PUC staff, agreed to recommend the PUC approve Tri-State’s resource plan, subject to certain modifications in the settlement. They also agreed to an extensive set of modeling assumptions and inputs for the ERP’s second phase.

Tri-State expects the commission to review and consider the settlement’s approval during the first quarter this year.

Jon Goldin-Dubois, president of Western Resource Advocates, said Tri-State “has come a long way” in “committing to near-term, enforceable reductions in climate-changing greenhouse gas pollution.”

“This agreement will make significant progress in accelerating emission reductions in the West, all while reducing costs for customers and supporting communities most impacted by the transition,” he said. “We have much work to do, but Tri-State is to be commended for taking these steps to maximize near-term emission reductions, the most important action society can take to avoid the worst impacts of climate change.”

Goldin-Dubois was one of several environmental advocates and members quoted in Tri-State’s press release announcing the settlement. Those groups are among those that have previously criticized the cooperative for its reliance on coal-fired energy.

Colorado lawmakers passed legislation in 2019 requiring utilities to cut CO2 emissions by 80% from 2005 levels by 2030 and 100% by 2050.

In January 2020, Tri-State responded with its Responsible Energy Plan to shut down more than 1.1 GW of coal-fired resources, transition to a cleaner energy portfolio and ensure compliance with Colorado’s environmental regulations. (See Tri-State to Retire 2 Coal Plants, Mine.)

Tri-State said it added 304 MW of wind energy last year, and it plans to add six additional solar projects by 2024. It said renewable energy will account for 50% of its 42 members’ consumption that year and 70% by 2030.

The settlement agreement’s additional modeling will include continued analysis of the retirement date for Craig Station Unit 3, which previous modeling validated would retire by 2030.

United Power to Exit Tri-State?

While Tri-State works to clean up its fuel mix, it may also lose one of its largest members.

United Power, which accounts for about 20% of Tri-State’s business, filed with FERC in December its intention to withdraw from Tri-State, effective January 2024 (ER21-2818).

United made its termination contingent on FERC’s determination that the exit fee to leave the association is just and reasonable. Last November, the commission accepted Tri-State’s methodology for calculating membership exit fees, subject to a refund hearing set for May, and also opened an inquiry under Section 206 of the Federal Power Act. (See FERC Accepts Tri-State’s Exit Fee Calculation.)

“Tri-State will work with United Power, as it would with any other member, through the contract termination process to support an orderly withdrawal,” Highley said in a statement. “The contract termination tariff approved by the FERC ensures that any utility member’s withdrawal does not harm the remaining members of our cooperative or Tri-State.”

Kit-Carson-Windpower-(Tri-State)-Content.jpg

Tri-State’s Kit Carson Windpower facility | Tri-State

United has said its exit fee should be between $200 million and $300 million. Tri-State has set the amount at $1.5 billion.

Two of Tri-State’s members have already paid the exit fee and left the association. As many as eight other members have asked the co-op what it would cost them to exit their contracts.

Kit Carson Electric Cooperative departed in 2016, paying $37 million, and Delta-Montrose Electric Association left in 2020, paying $136.5 million. (See Tri-State, Delta Officially Part Ways.)

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DOE-DOT Joint Office to Begin Rollout of EV Infrastructure Funds

The Joint Office of Energy and Transportation will take the first steps in rolling out the Infrastructure Investment and Jobs Act’s (IIJA) $7.5 billion in funding for a national electric vehicle charging network next month when it releases a guidance document to help states submit plans for the federal dollars.

Announced Thursday at the National EV Charging Summit, the guidance document “will really be the beginning of a very deep collaboration where states are developing EV development plans, but we at the federal government level, the joint office, will be working very closely to support the states, provide them with the data — the information, the know-how — in that process,” said Michael Berube, the Department of Energy’s deputy assistant secretary for sustainable transportation.

The goal will be to get the state plans submitted and approved, and then to get the first federally funded chargers installed this year, Berube said. “But our point really is, let’s get it right. Let’s make sure we have a good national plan.”

While not providing specifics, Polly Trottenberg, deputy secretary at the Department of Transportation, said the guidelines would reflect the joint office’s goals of equity, accessibility, reliability and affordability and include standards and requirements for industry partners to follow.

“The initial focus is really building out those national [charging] corridors coast to coast,” Berube said. “We’re going to make sure we’re hitting all the communities — rural spaces, urban spaces, everywhere there are interstates and major travel corridors — so that will provide a certain backbone of access and equity.”

Transportation Secretary Pete Buttigieg and Energy Secretary Jennifer Granholm launched the joint office in December to oversee the rollout of the EV charging funds from the IIJA. Trottenberg said $5 billion will go to “formula” grants to help the states implement their EV charging plans and $2.5 billion to a discretionary grant program.

The discretionary funds are intended, in part, for communities “where otherwise private investment wouldn’t go,” Berube told reporters after the announcement. The priorities include environmental justice issues and “those people that don’t have EV charging at home because those are problems and that’s really where government can come in to help solve some of those issues,” he said.

“We’re going be looking for ideas from the public sector, the states on innovative services to provide charging for people in that situation,” Berube said. “Is it DC fast-charging in their community? Is it Level 2 overnight charging? Is it street charging or at least at the multiunit dwelling facility? So, there is not a one-size-fits-all.”

Collaboration across federal, state and local agencies and the private and nonprofit sectors was itself a central theme of the half-day summit, which was organized by the National EV Charging Initiative, a coalition of regional and national groups, private companies and labor.

Working with utilities to ensure grid reliability, especially as the number of EVs and chargers increase, is also part of the joint office’s vision, Berube said.

“We have some test cases looking at smart charging management to have both EVs and the grid working together … to basically make sure that as we add EVs, which will be the largest new load on the grid, we do it in a way that can be managed as a managed load,” he said. “That is a lot of the Level 2-type charging, workplace charging, home and community-based charging. Deploying that smart charger technology at the grid side and the charger side will be one key aspect of the sector.”

The other big focus for the joint office will be highway charging facilities with fast chargers that can be upgraded continually, Berube said. With fast-charging technology hitting 150 kW and even 350 kW, the highway network “will really start to get the future EVs that are in the 300-mile range chargeable in that 15-minute window,” he said. “That’s the vision.”

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NYPSC Mandates Meshed Offshore Tx Grids

The New York Public Service Commission on Thursday unanimously approved requiring offshore wind project developers to provide “mesh-ready” transmission plans in their bids for state solicitations, as recommended by the commission’s power grid study a year ago (Case Nos. 15-E-0302; 18-E-0071; 20-E-0197).

The commission’s order seeks detailed plans from Con Edison for a wind energy interconnection hub, particularly on the availability of points of interconnection in lower Manhattan for up to 6 GW of offshore injections.

“The order will complete the requirements established by the Accelerated Renewable Energy Growth and Community Benefit Act of 2020 and ultimately improve the utility of the state’s entire renewable energy portfolio,” said PSC Chair Rory Christian.

OSW proposals that integrate energy storage will receive extra scoring weight under the order, and a new technology working group will test and deploy advanced transmission technologies. The PSC scheduled a virtual technical conference on Jan. 27 for utilities to present an overview of the proposed coordinated grid planning process.

The Initial NY Power Grid Study Report released last January by the state’s Department of Public Service and the New York State Energy Research and Development Authority (NYSERDA) recommended that transmission planners focus on beefing up the infrastructure needed to import 6 GW of offshore wind energy into New York City. (See NY Grid Study Pushes Meshed OSW Tx, Coordination.)

Details and Costs

“The power grid study suggests that constructing an offshore grid network may have significant advantages in terms of operational flexibility, reliability and ratepayer benefits,” Robert Rosenthal, general counsel to the commission, said in testimony.

Under prior orders related to offshore wind, the commission required NYSERDA solicitations to include direct or radial lines to the point of interconnection. A single radial configuration could result in the energy from the project not being deliverable with advanced system in an outage situation, he said.

By contrast, projects with a meshed grid would be connected to each other in the ocean, from which a number of transmission lines will be interconnected to the onshore grid. Rosenthal said. If one line is down, he said, the energy can be diverted to another line.

“As the power grid study recommended, the order directs that NYSERDA modify its offshore wind procurement requirements to include mesh-ready design, primarily because the cost of modifying projects on the design team is small in comparison to the cost of a future retrofit,” Rosenthal said.

In addition, the power grid study highlights the significant constraints that impact the possible undersea transmission cable routes into New York Harbor, including the anchorage areas and navigation channels that occupy an area known as the Narrows.

Coordinated state planning for the use of this corridor into New York City is critical, says the order, which directs staff to collaborate with other state agencies to develop plans for cable routing and report on their progress no later than Sept. 1.

Mesh-ready costs (NYDPS) Content.jpgMesh-ready costs for 230 kV, including transformation | NYDPS

 

The order acknowledged a recommendation in the power grid study for interconnections to use 320 kV direct current or DC cables to maximize the capacity that can be carried through the available corridors, and it requires the use of DC transmission as part of future offshore wind solicitations.

“I will caution that we aren’t over the hump by any stretch, and in fact we’re really at the starting gate,” said Commissioner Diane X. Burman. “We still have to set up a hub, to look at siting, and we have to address the supply chain challenges.”

With all the talk of offshore wind and community solar, very little attention has been paid to the transmission needed to make new generation assets work for the grid and which will allow decarbonization to be a reality, said Commissioner John B. Howard.

On the issue of cost there are two parts: how much it actually costs to do these projects and who should pay, Howard said.

The mesh grid for offshore will be not so much a technological challenge as a bureaucratic and regulatory challenge. Making the mesh grid work along the Northeast coast will require cooperation from neighboring states as well as neighboring RTOs on cost allocations, and a large share of planning and funding will fall to the federal government, he said.

Any cost analysis should include the full amount of what it may cost to taxpayers or ratepayers, and particularly for the issues surrounding the Con Ed hub, which may incur billions of dollars in costs and trigger “well over $100 million of windfall potentially to the city of New York,” Howard said.

“We have tried to slay this dragon as best we can, but it would have been far better for all New Yorkers had these issues of transmission and system integration fees been articulated at the front end of our desire to decarbonize our system,” Howard said.

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California PUC Postpones Net Metering Plan

The California Public Utilities Commission is delaying its consideration of a highly controversial plan to slash rooftop solar credits amid an outpouring of criticism, including from Gov. Gavin Newsom and former governor Arnold Schwarzenegger.

The proposed decision, released in December, would reduce electric bill credits for homeowners with rooftop solar arrays by up to 80% and add a monthly grid charge to their bills. (See California PUC Proposes New Net Metering Plan.)

Opponents, led by the solar industry, contend it will decimate rooftop solar adoption. Proponents, including the state’s large investor-owned utilities, argue utility-scale solar is more cost-effective and can serve far more consumers.

The CPUC said in its proposed decision that the current net-metering scheme unfairly shifts costs from homeowners who can afford rooftop solar to those who cannot.

It “negatively impacts nonparticipating customers, is not cost-effective and disproportionately harms low-income ratepayers,” Administrative Law Judge Kelly Hymes wrote.

The proposal was widely expected to be taken up at the commission’s voting meeting on Jan. 27, the earliest date on which it could be heard under commission rules, but the CPUC’s agenda for the meeting does not include the item.

In a recent press conference, Newsom said he thinks the plan needs more work. (See CPUC Takes Heat on Rooftop Solar Plan.)

And in a New York Times opinion essay published Jan. 17, Schwarzenegger criticized the plan as a threat to solar adoption.

“California has more rooftops with solar panels than any other state and continues to be a leader in new installations,” he said. “But a proposal from the state’s public utility commission threatens that progress. It should be stopped in its tracks.”

The state’s generous net energy metering (NEM) rates are credited with helping to install roughly 1.3 million residential arrays. NEM offsets customer bills at full retail electricity rates, which are much higher than current solar costs.

In an email Thursday, CPUC spokesperson Terrie Prosper said the commission felt it was too soon to vote on the proposed decision.

“We have two new commissioners, one of whom has not started yet,” Prosper wrote. “Comments from parties on the proposed decision have just been received for this extremely important policy matter. We will provide more information once a schedule has been determined.”

Newsom appointed his former energy adviser, Alice Reynolds, as the new president of the CPUC in November. (See Calif. Governor Names Next CPUC President.)

In December he appointed John Reynolds (unrelated to Alice), a lawyer and former CPUC staff member, to fill the seat vacated by Commissioner Martha Guzman Aceves. Reynolds previously worked as managing counsel to self-driving car company Cruise in San Francisco. He has not yet begun work at the commission.

Guzman Aceves, the lead commissioner on the proposed net-metering plan, left the CPUC to become head of the EPA’s Region 9 in December, at about the same time that former CPUC President Marybel Batjer retired. (See Biden Appoints CPUC Commissioner to Head EPA Region 9.)

The CPUC’s two new members, Newsom’s critique and the largescale public outreach campaign by the solar industry now leaves the plan in limbo.

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FERC Proposes New Cybersecurity Standard

FERC on Thursday issued a Notice of Proposed Rulemaking that would have NERC to expand its Critical Infrastructure Protection (CIP) reliability standards to cover internal communications (RM22-3).

The proposed standards would require registered entities to implement internal network security monitoring (INSM) for high- and medium-impact bulk electric system cyber systems (BCS), correcting what FERC staff called a “gap in the security standards” during Thursday’s open meeting.

Currently the CIP standards require a utility to monitor communications from the inside of its electronic security perimeter (ESP), the electronic border around the internal network to which BCS are connected, to the outside. The NOPR seeks to expand this monitoring to communications within the ESP, allowing “the earliest possible alerting and detection of intrusions and malicious activity” into the “trust zone” — the utility’s internal computing environment that is protected by the ESP.

As defined in FERC’s order, INSM is not a single process or piece of software but rather a set of practices for gaining visibility into an entity’s own system. It includes tools such as antimalware, intrusion detection and prevention systems, and firewalls; this software can have both passive, information-gathering applications, or active functions that block malicious network traffic.

FERC’s order was motivated by recent cyberattacks, most prominently the SolarWinds hack of 2020. The hack of SolarWinds’ Orion management software, used by thousands of public- and private-sector organizations around the world (including FERC itself), left many of those entities with malicious code inside their systems. (See FERC, E-ISAC Report Details Reach of SolarWinds Compromise.) Last April the U.S. accused Russia’s Foreign Intelligence Service of perpetrating the original attack and later leveraging their access to gain network privileges to SolarWinds’ Microsoft 365 and Azure Cloud environments.

Because the compromised software came via Orion’s official update channel, the SolarWinds attack “demonstrated how an attacker can bypass all network perimeter-based security controls traditionally used to identify the early phases of an attack,” FERC staff said. Adding INSM to the CIP standards would give all entities the means to detect and respond to suspicious activity by software within the network by, for example, recording normal network traffic and using it as a baseline to flag anomalous activity for further investigation.

“If [the hackers] do get in … you’d have enough awareness about that early to be able to take quick action to alleviate any concerns that might exist,” FERC Chairman Richard Glick said in a press conference following Thursday’s meeting. “Sometimes people get into your system using these perfectly legitimate pieces of software … and so, companies need to be vigilant not only about hackers getting in [but also] if people figure that out, let’s make sure that we have our defenses on internally to be able to address that as quickly as possible.”

For now, FERC is only proposing to add INSM to high- and medium-impact BCS because those systems are defined in the CIP standards, while low-impact systems are not; this distinction makes it difficult to apply CIP requirements to low-impact BCS because there is much more variety among these systems.

However, staff said in Thursday’s meeting that they “are seeking comments on the usefulness and practicality” of requiring INSM in low-impact systems, along with potential challenges of implementing INSM in general, what hardware and software capabilities would be needed to achieve the NOPR’s security goals, and what is a reasonable time frame for developing and implementing the new reliability standards.

Comments on the NOPR are due 60 days after its publication in the Federal Register.

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Massachusetts Transit Bill Seeks Fast Track for Electrification

Legislators and environmental advocates spoke Thursday on behalf of a bill that would speed up a Massachusetts Bay Transportation Authority plan to electrify its bus fleet by 2040.

The bill (S2292) would set a new full-fleet electrification target for 2030 — with interim targets — and direct MBTA to purchase only electric vehicles starting next year.

Gov. Charlie Baker’s decision to back away from the Transportation and Climate Initiative and new obstacles to building the New England Clean Energy Connect project are “serious blows” to the state’s ability to meet its climate goals, Sen. Brendan Crighton, co-sponsor of the bill, said during a Joint Transportation Committee hearing.

The bill on public transit electrification, he said, would put the state “back on track.”

Under the proposed legislation, MBTA would have to ensure all garages for the authority’s 1,100 buses be ready to support an all-electric fleet by 2029. The Massachusetts Department of Transportation, which oversees the MBTA, already has a plan in place for transitioning state transit buses and facilities through 2040, setting new and modernized facility openings every two years along with bus purchases to match facility capacities.

To meet the faster timeline in the bill, MBTA would have to “think creatively,” Rep. Steven Owens (D), who co-sponsored a House companion bill (H3559), said in hearing testimony. The authority could look at “currently underutilized” facilities as “swing space” while new construction is underway, he said.

An estimated $4.5 billion is needed to complete the necessary facility upgrades, according to MBTA, and the authority has yet to identify full funding for its first two modernization projects. There are opportunities for federal funding to fulfill some of the needed funding, Owens said.

Massachusetts will receive $2.8 billion over five years from the Infrastructure Investment and Jobs Act to improve the state’s public transportation, according to testimony from Pete Wilson, senior adviser for the Transportation for Massachusetts advocacy coalition. In addition, the Federal Transit Administration has $7.6 billion in competitive fleet electrification grant opportunities.

The FTA grant program “provides funding to replace, rehabilitate and purchase buses and related equipment and to construct bus-related facilities, including new facilities and rehabbing old facilities to accommodate low-emission or no-emission vehicles,” Wilson said.

A goal for the 15 regional transit authorities in Massachusetts to transition their bus fleets to electricity by 2035 is included in the bill.

Rail Transition

The bill sets a timeline for MBTA to move its commuter rail service, which is under contract to Keolis America, to electricity by 2035. A mandated two-phase approach for upgrading rail service would include switching five lines by 2027.

In 2019, MBTA’s Fiscal and Management Control Board adopted a plan to transform the rail system to what it called a “largely electrified, decarbonized” system in its 2020 annual report.

The authority’s existing rail fleet has 101 diesel-powered locomotives, the board said in a June 2021 productivity report. While the board has not set a specific timeline for upgrading the fleet and associated facilities, it started work last year on locomotive procurements for one of MBTA’s rail lines.

As part of its review of options for transitioning the fleet, the board identified a combination of battery-electric and overhead electricity technologies as “the best value approach,” the report said. The board estimated that a full, systemwide rail transformation would cost $28.9 billion.

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FERC Rejects Calls to Shut Down Weymouth Compressor

FERC declined to take action against Enbridge’s Weymouth Compressor Station on Thursday, finding that there is no new information to justify reversing the agency’s 2020 order approving the contentious Massachusetts project (CP16-9-012).

The decision came with promises from the agency’s Democratic majority that it will change how FERC certifies natural gas infrastructure, but chairman Richard Glick acknowledged that would be “cold comfort” to the local opponents who have been challenging the plant for years.

“Although I believe this is the correct conclusion as a legal matter, I don’t take any joy in that conclusion,” Glick said. “In my opinion, the commission should never have approved the proposal to locate the compressor station where it is.”

FERC’s decision on Thursday was the culmination of a February 2021 order setting a paper briefing to examine several blowdowns — unplanned releases of gas — which occurred shortly after the agency approved the project to enter operation in September 2020.

The commissioners’ review found that there were no new facts sufficient to reverse the initial approval, despite the wide range of environmental and public health concerns with the project. “On the record before us, we are unable to find that the public interest requires setting aside the authorization order or imposing additional or different mitigation measures,” the commission wrote in its order.

“We’re restricted by the law,” Glick told reporters after the meeting, pointing to FERC’s issuance of a certificate that was subsequently upheld by the D.C. Circuit. “The legal approaches to remedy the situation really weren’t there.”

But the Democratic majority promised to attempt to avoid that outcome for future projects.

Commissioner Allison Clement called for “swift, common sense and legally compelled” changes to the agency’s pipeline infrastructure certification process.

“The original culprit in this proceeding was not the decision to take a pause and consider changed circumstances, but the inadequate certification policy statement and environmental consideration under which a certificate was originally awarded,” she said.

Glick called on the Pipeline and Hazardous Materials Safety Administration to keep a “watchful eye” on the facility, and on Enbridge to “take its obligations as a corporate citizen seriously and take a hard look at any and all options to address the community’s concerns.”

Commissioner Willie Phillips said that while he agreed the commission had no authority to reconsider its approval of the compressor station, he was troubled by it. “Residents living near the Weymouth compressor station are burdened by multiple industrial facilities. And sadly, this pattern of consolidating industrial activity in such communities is neither isolated nor unique,” he said. “… I hope that it will help the commission better engage with these vulnerable communities in the future.”

Republicans on the commission took a different perspective, saying the review improperly reopened the commission’s 2017 approval of Enbridge’s Atlantic Bridge Project — a $452 million expansion of the company’s Algonquin Gas Transmission and Maritimes & Northeast Pipeline systems — of which the compressor station’s construction was a part. (See Atlantic Bridge Project Approved by FERC.)

Commissioner James Danly acknowledged that after receiving the certificate in 2017, Enbridge had to return to the commission for approval to proceed with construction and commence operations. But he said those conditions were to ensure the company met its requirements “rather than a potential opportunity for a re-litigation of the public interest determination made in the certificate.”

“I didn’t think the proceedings should have been initiated,” said Commissioner Mark Christie. “… I think it certainly does add to the growing uncertainty … about whether this commission is going to stand behind certificates.”

Reactions from Mass.

A spokesperson for Enbridge said that the company is “pleased with FERC’s decision not to advance a reexamination of matters which have already been extensively reviewed as part of a multiyear public process.”

In Massachusetts, frustrated opponents pledged to continue to fight the compressor.

“Doing better going forward isn’t going to help the people of Weymouth living right now in the shadow of this dangerous fossil fuel facility,” said Sen. Ed Markey (D-Mass.) in a statement. “We’re going to fight with legislation, with the agencies, and shoulders-to-shoulder with local leaders and grassroots activists to get the compressor station shut down once and for all.”

The agency’s promise to change its process did not fall on deaf ears.

“Weymouth is yet another example of why FERC reform must happen this year. This whole situation is deeply unfair to the folks around the compressor station. Even if FERC concludes that its hands are tied here, it can prevent the next Weymouth — and must,” wrote Gillian Giannetti, a senior attorney at the Natural Resources Defense Council, on Twitter.

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New Jersey Tightens Appliance Energy Use Standards

New Jersey Gov. Phil Murphy signed bills Tuesday tightening energy efficiency standards on more than a dozen household and commercial appliances and limiting rates for electric vehicle charging stations in residential neighborhoods.

Supporters of the efficiency standards bill, A5160/S3324, said the measure — the first update in 15 years — would save water and energy. NJPIRG, a public interest advocacy group, said the reduced greenhouse gas emissions would be equal to removing 72,000 vehicles from the road.

“Common appliances like lamps and fans shouldn’t needlessly waste energy, and this new law will make sure they don’t,” said Rachel Vresilovic, associate for NJPIRG.

The 17 appliances covered by the new law, which takes effect immediately, include showerheads, which the law prevents from exceeding a flow of two gallons a minute. The law also requires toilets and urinals to meet federal water consumption standards and a waste extraction test set by the American Society of Mechanical Engineers. Air purifiers, commercial fryers and commercial ovens, water coolers and steam cookers must meet their respective Energy Star program requirements.

A second bill signed by Murphy on Tuesday, A-2360/S-3285, requires that electric utilities set the cost of electricity for EV charging stations outside of residential units at a level that is no higher than the rates for home chargers. Sponsors of the bill said it aims to ensure that real estate developments don’t charge residents the higher, commercial rate for electricity rather than the residential rate.

Three bill sponsors, Assembly members Annette Chaparro, Robert Karabinchak and Gordon Johnson, said the bill would remove the confusion that can arise when a residential development contains a charging station that levies a commercial rate for the electricity and another charger nearby that charges a residential rate.

“Families who have electric cars should have access to more affordable charging rates and not have to worry about using a higher priced charging station outside their home,” the Democrat lawmakers said when the Assembly backed the bill on Jan. 10. “Residents should not be wary about owning an electric car due to potential confusion at their residential charging stations. It is clear, if a person is at their own residence, they should pay a residential rate”

Cutting Transportation Emissions

The legislation was among 100 bills signed by Murphy on the day of his inauguration for a second, four-year term after a narrower than expected victory over Republican Jack Ciattarelli. In his first term, the governor staked out an aggressive agenda to reduce fossil fuel use, with goals to cut greenhouse gas emission levels to 50% below 2006 levels by 2030, and 80% below 2006 levels by 2050.

Although the policies have earned Murphy the support of environmentalists, he hardly mentioned climate change in his inauguration speech, except to note the economic development spurred by initiatives such as the state’s offshore wind projects.

Henry Gajda, public policy director for the League of Conservation Voters, called the energy efficiency bill “momentous” when it received Assembly approval with a 52-25 vote on Jan. 10. “The cleanest and cheapest energy is the energy we don’t use.”

A key element of Murphy’s strategy is to cut emissions from transportation, which accounts for about 40% of the state’s carbon emissions. The measures include offering subsidies for the purchase of electric trucks and cars, and a mandate that EV vehicles account for a steadily increasing proportion of trucks sold in the state. The state is also seeking to encourage the transition to EVs by increasing the number of charging stations through subsidies and rules to encourage private investment.(See NJ’s EV Charger Rules Face Scrutiny.)

Bill sponsor Sen. Linda Greenstein, commenting after the EV-charging bill secured the support of the Senate Environment and Energy Committee in December, said it would help the state meet its goal of 2 million EVs on the road by 2035.

“By decreasing the price of charging for residents living in developments, this bill will aid in removing some key barriers that currently exist when purchasing and using electric vehicles,” she said.

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‘Buy America’ Hampers Martha’s Vineyard E-bus Plan, Official Says

Battery storage is a key part of the 10-year plan to transition the Martha’s Vineyard Transit Authority (VTA) bus fleet to electricity, but the Federal Transit Administration’s Buy America requirements and industry growth pains have been a challenge on that journey.

VTA has 1,400 kWh of utility-scale battery storage at its operations center as part of a microgrid that enables grid-parallel and grid-independent battery-electric bus (BEB) charging, according to Administrator Angela Gompert.

The authority awarded NEC subsidiary NEC Energy Solutions, based in Westborough, Mass., a contract in 2018 for the storage units. The batteries, however, did not meet the Buy America requirement under the FTA’s guidelines for purchases made with federal assistance, Gompert said on Tuesday during a Green Energy Consumers Alliance webinar.

Under the Buy America Act, a state or local government authority can only use federal assistance on transportation projects if their steel, iron or manufactured goods are produced in the U.S.

“Currently, there are no battery storage vendors that meet the Buy America requirements,” Gompert said. To purchase the batteries, she added, VTA diverted some state funding to the project.

Gompert believes manufacturers need to catch up to the realities of the current U.S. market.

“If there’s a battery vendor that really gets up-to-speed quickly with what the existing requirements are for using federal funds for transit agencies, certainly they’ll get a lot further,” she said.

In 2020, NEC ES announced it was backing out of the storage market, and LG Energy Solution acquired the subsidiary last fall.

Gompert says the change in the vendor’s circumstances created a “huge nightmare” that VTA is still working through. NEC ES, however, continues to support the three storage units, she said.

Three storage units “strengthen” transit operations, providing flexibility, resilience and the ability to store renewable energy generated on site. To support the transition of its 32-bus fleet from diesel to electric, the authority also installed eight solar canopies with 700 kW of generating capacity at its operations center.

“We have seen demand response savings from using the battery storage units, and they increase the distribution of our overall efficiency when charging all of the fleet at the same time,” she said.

As a component of the microgrid, storage makes grid-independent charging possible. The microgrid decides whether charging will be grid-to-bus, grid-to-battery, solar-to-battery or solar-to-bus, and if necessary, buses can charge from a backup diesel generator, Gompert said.

Other Challenges

VTA has replaced 16 of its diesel buses with BEBs manufactured by Los Angeles-based BYD, and there is one charger for each bus.

“Our operations maintenance center is fully ready to complete the buildout for all chargers for all our vehicles,” Gompert said. “Our next phase will be putting in some Level 3 charging as we expand into fleet replacement with our paratransit vans and minibuses.”

Malvern, Pa.-based Momentum Dynamics won a contract to install inductive (i.e., wireless), in-road charging pads along VTA’s bus routes, and construction is underway on the first pad site in Edgartown, she said. All the BEBs currently in service have charging pad retrofits for using the wireless charger.

The technical aspects of transitioning to BEBs and building the systems to support them have been a “heavy lift” for the authority because of the organization’s comparatively small size, Gompert said. VTA procured its BEBs, chargers, batteries, microgrid components and solar facilities under separate contracts and managed development and integration of the elements individually.

New energy-as-a-service models, Gompert said, could help other transit authorities with their BEB programs.

“Coordination of the partners and the system components is done as part of [energy-as-a-service] agreements,” she said.

Component software and hardware updates also present a challenge for the organization. If those updates are not well coordinated, the systems “can get out of sync,” which becomes “problematic,” Gompert said.