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October 20, 2024

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Ørsted New Jersey Wind Project Faces Local Opposition

New Jersey’s first offshore wind project, Ocean Wind, has encountered its most public challenge as it seeks an easement from the tourist town of Ocean City to run cables, buried three feet underground, to an inland substation. Thus far, the town appears to oppose the easement, and the project developer Ørsted has asked the New Jersey Board of Public Utilities (BPU) to step into the fray to approve the easement regardless of the town’s wishes in the matter.

The BPU recently agreed to hear the case and selected Chair Joseph L. Fiordaliso to oversee and rule on the issue.

The case is the first test of a new law, S3926, passed in July 2021, that allows for the siting, construction and operation of “wires, conduits, lines, and associated infrastructure” on public land if needed to connect an offshore wind project to the grid, despite any opposition from local authorities as long as they are consulted. The bill stipulates that the connecting infrastructure should be buried underground. (See NJ Lawmakers Back Offshore Wind Bills.)

Before the 5-0 BPU vote agreeing to hear the petition, Commissioner Upendra J. Chivukula acknowledged the potentially groundbreaking decision facing the agency as it evaluates Ørsted’s request to secure the easement rights. “This is a new precedent, and we are getting into areas where the board has not been before,” he said.

Ocean City officials did not respond to NetZero Insider emails and a phone call seeking comment.

In its petition, Ørsted asked the board to rule that Ocean Wind meets the requirements of S3926 and can therefore move ahead with siting the cables on the proposed route without the town’s approval.

The company is seeking a 30-foot-wide easement running the length of the island, which is about eight miles long, for a 275-kV cable that will connect Ocean Wind’s turbines, about 15 miles offshore, to the PJM grid at a substation at a now closed coal-fired power plant in neighboring Upper Township.

In its petition and related affidavits, Ørsted said it has held multiple public hearings to explain the project and has also had numerous meetings with Ocean City officials but has yet to secure the municipality’s agreement on the easements. The developer argues that it needs the easements to keep the project on track and meet its commitment to the BPU that the first phase of the project’s commercial operation would start May 1, 2024.

‘No Room’ for Cables

Approved in 2019, the 1,100 MW Ocean Wind project is the first of three offshore wind farms given the green light by the BPU, and as the first, its ability to overcome permitting and other obstacles may carve a path forward that will inform and shape succeeding offshore wind projects.

Aside from Ocean Wind, the BPU has awarded leases to the 1,148 MW Ocean Wind II, also an Ørsted project, with 25% held by PSEG Renewables Generation, and Atlantic Shores, a 1,510 MW joint venture between EDF Renewables North America and Shell New Energies US. The state expects to hold at least three more solicitations with a goal of deploying 7,500 MW of offshore wind capacity by 2035.

Ocean City Easement Proposal (Orsted) Alt FI.jpgOrsted has asked the New Jersey BPU to approve an easement running through the small coastal community of Ocean City, which will allow it to connect its offshore wind project to the grid. | Ørsted

Public sentiment about the Ocean Wind easement will be aired Monday when Ørsted holds an online public hearing focused on its proposal to run the cable under land that was improved under the state’s Green Acres program, which funds the creation and preservation of parkland.

Suzanne Hornick, an Ocean City resident and environmental activist, believes local opposition is strong, not only to the easement but to anything that would move the project forward.

“We do not want these cable bundles across our island,” said Hornick, who lives a few blocks from the proposed path of the cables. She is worried about damage to the ground and potential health hazards from electromagnetic fields emanating from the cables, she said.

“There’s no room here for that,” she said of the developer’s cable plan. “They want to come across our beach and our island, and the one main street in the middle of the island that gets you on and off… The area that they’re talking about is so narrow for such a huge cable.”

Local Opposition

Just how New Jersey will connect those 7,500 MW of offshore wind to the onshore grid will become increasingly important as the projects move through permitting and start construction. The BPU announced Monday that it has pushed back the date of its next solicitation, from September of this year to January 2023. The delay is partly to accommodate a BPU solicitation underway with PJM to help find solutions on how to upgrade the grid to handle the energy coming in from offshore wind projects. (See NJ Delays Third OSW Solicitation for PJM Tx, NY Bight Winners.)

The offshore wind projects, although warmly received by some environmentalists and public officials, have faced opposition from the fishing industry, which fears that the turbines will disrupt fishing areas and will create a dangerous environment for boats pulling nets. The tourism sector also has voiced concern that the sight of scores of turbines offshore could reduce the number of visitors coming to the state’s coast.

Similarly, local residents and property owners are worried about the impact for local properties resulting from construction to install cables and other equipment. (See NJ’s Offshore Wind Project Faces Criticism, Support.)

“Ocean City is a little, teeny … barrier island,” Hornick said. “The only thing that we have that maintains our quality of life and our community is our tourism.”

Overriding Home Rule

But Ørsted says the easements are necessary to apply for environmental permits for the project, as is the permission needed for the cable to run through land developed with state Green Acres funds. So far, however, despite discussions with the township stretching back to 2019, “Ocean Wind has been unable to obtain the required easements, consents and associated actions from Ocean City,” the petition said.

The company argues that if the BPU concludes that the easements, or rights of way, are “reasonably necessary for the construction or operation” of the project, S3926 allows the BPU to override municipal and county rules and issue its own order approving the easement.

Ørsted’s petition, however, argues that “in similar contexts involving public utility projects, both the Board and the courts of this State have long held that the welfare of the public generally transcends the municipal borders and local municipal concerns.”

The BPU’s intervention is “appropriate and important because local officials cannot be expected to balance local interests against the greater good of the public,” the petition says.

But others see S3926 as overriding New Jersey’s long-held tradition of home rule, which preserves the rights of local authorities to make decisions that affect their own back yards. Sen. Bob Smith (D), one of the bill’s sponsors, acknowledged the potential conflict but said the need to move swiftly to combat climate change made the measure necessary.

Ocean City officials voiced opposition to the bill before its passage. The township council voted 7-0 in June in favor of a symbolic resolution that said the law, if enacted, would “severely affect the ability of local governments to exercise home rule pertaining to the offshore wind farm project,” according to a local press report.

Hornick agrees. “We don’t have a choice anymore,” she said. “Our voices been taken away. And to me, that is the most un-American thing anybody could do.”

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California Addresses Electric ‘Affordability Emergency’

Joined by lawmakers and other state energy officials, the California Public Utilities Commission met Monday and Tuesday to deal with the looming crisis for ratepayers saddled with billions of dollars annually for fuel costs, wildfire prevention and the state’s switch to 100% clean energy.

The two-day session on electric and natural gas rates examined ways to control costs and to pay for major projects using public revenues rather than ratepayer funds. Panelists included wildfire experts, utility executives and ratepayer advocates.

“TURN is here today to declare a state of emergency, an affordability state of emergency,” Mark Toney, executive director of The Utility Reform Network (TURN), said during a panel on non-ratepayer sources of funding for infrastructure upgrades.

Toney called for a timeout on rate increases until the CPUC can come up with alternatives to pay for soaring capital costs for the state’s three large investor-owned utilities.

PG&E electric ratepayers, for example, were hit with a $1 billion rate increase in January followed by a $1.1 billion increase on Tuesday. Together, the increases work out to a 19% rate hike in the past two months or about $28 per month for average households.

The January spike resulted from a $671 million increase in FERC-approved transmission rates and a $284 million increase in PG&E’s general rate case for program costs, the CPUC said.

Investor-owned utility rates (The Utility Reform Network TURN) Content.jpgInvestor-owned utility rates have soared in recent years. | The Utility Reform Network (TURN

The additional increase this month came from natural gas prices that were $1.1 billion higher than PG&E had expected in 2021 and 2022. To cover the fuel costs, the CPUC approved a $769 million increase to PG&E’s Energy Resource Recovery Account (ERRA) and a $358 million addition for ERRA under-collection in 2021.

Southern California Edison and San Diego Gas & Electric have also seen significant rate increases

For SCE, the CPUC approved a January rate increase of 2.9%, working out to an average monthly bump of $3.99 in residential bills. The causes included the addition of $385 million to SCE’s general rate case for wildfire mitigation work, including vegetation management and installing covered conductor. Newer CPUC-approved increases for SCE, which take effect this month, reflect high natural gas prices and the recovery of $401 million in wildfire prevention costs.

Starting soon, SCE residential customers can expect an additional 7.7% bill increase, adding $11.48 a month on average. Between the January and March rate hikes, SCE residential customers will be paying nearly 11% more for electricity this year, or about an extra $12.50 per month.

San Diego Gas & Electric residential bills rose by 11.4% in January because of a $273.5 million boost to the utility’s revenue requirement, mostly based on high gas prices, and $38.5 million for transmission costs authorized by FERC, the CPUC said.

Billions of dollars more could be required to pay for infrastructure upgrades such as PG&E’s proposal to underground 10,000 miles of power lines to prevent wildfire ignitions. CAISO predicts new transmission may be needed to reach wind resources on the Great Plains and in offshore wind farms along the West Coast. Thousands of additional megawatts of solar, storage and other clean energy resources are required in coming years to achieve the state’s goal of supplying retail customers with 100% carbon-free energy by 2045, according to the CPUC and Energy Commission.

“We’re dealing with multiple imperatives right now: the imperative to decarbonize and stave off the worst impacts of climate change, the imperative to deal with some of the climate consequences that are already upon us, and the imperative to deal with rising costs,” Energy Commission Chair David Hochschild said. “We have to deal with all of those together. There’s not one we can leave off the list. This is the challenge ahead of us.”

Non-Ratepayer Funding

Among the major proposals discussed at the meeting were ways to use California’s large revenue surpluses to cover costs without adding to ratepayer bills or to pay for transportation and building electrification using fees for buying cars and homes.

“This discussion comes at an opportune time when the state general fund is experiencing large surpluses in the tens of billions of dollars,” CPUC Government Affairs Director Grant Mack said.

California has an estimated revenue surplus of $76 billion in the current fiscal year and $46 billion next fiscal year. The state received $25 billion this year through the American Rescue Plan Act of 2021, and the $1.2 trillion Infrastructure Investment and Jobs Act, signed by President Biden in November, appropriated $58 billion for clean-energy investment and energy efficiency, Mack said.

The flood of public funding could limit increases in electric rates, panelists said, though they cautioned that the surpluses may not last, based on California’s prior record of boom-and-bust fiscal years.

“I guarantee you we will not have a state budget surplus year in and year out,” Toney said.

Instead of relying on surpluses, he proposed paying for electric vehicle infrastructure and incentives with point-of-sale fees at dealerships instead of ratepayer fees. He also proposed funding building electrification in a similar way. Instead of spending hundreds of millions of dollars in ratepayer fees to electrify “10,000 homes here and there,” he recommended charging homebuyers a closing fee to pay for electric space and water heating upgrades.

In the realm of wildfire prevention, Michael Wara, director of the Climate and Energy Policy Program at Stanford University, said the state needs to better assess its spending to achieve the greatest impact.

For instance, he said, utilities are spending billions of dollars in ratepayer money to harden the grid and prevent wildfire ignition. Preventing ignitions is important but so is limiting the rapid spread of fires, he said.

Wara cited the 2018 Camp Fire, which spread so rapidly that it leveled the town of Paradise in hours, and last year’s Dixie Fire, which advanced so quickly at times that it eventually burned nearly 1 million acres.

“Wildfire risk also comes from how wildfires spread,” Wara said.

“It’s very expensive to reduce utility ignitions to zero” by installing covered conductor and burying lines “and we can only do that so quickly,” he said. “But if we get to a place where we can tolerate ignition safely [by reducing spread, for example] it might mean that we don’t have to make some of these incredibly costly, long-run infrastructure investments, because we’re managing the landscape in a way that creates safety.”

Last year, state investor-owned utilities proposed spending $8.5 billion in ratepayer funds on wildfire mitigation, he said. At the same time, the state plans to spend $1.5 billion in taxpayer revenues on fuel management and community protection and more than $4 billion on fire suppression.

To offset those costs, California could consider charging additional fees to ratepayers in high-threat fire areas because providing service there is more expensive, Wara said. While those residents could not feasibly cover their full cost of service, they could pay additional fees to cover fire prevention and suppression costs, he said.

A state fee that expired in 2017 charged many rural residents around $100 a year to help cover wildfire costs, so the precedent exists, he said. The purpose of such a fee is to protect ratepayers outside of fire zones, “particularly low-income people who do not live in high-risk areas,” Wara said.

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Washington Lawmakers Pass Bill to Green Public Buildings

The Washington Senate passed a bill Tuesday to require all “major” new publicly owned or leased buildings to be designed with all-electric energy systems in mind.

The House-originated bill (HB 1280) now goes to Gov. Jay Inslee for his signature.

The bill by Rep. Alex Ramel (D) passed the Senate 29-20, mostly along party lines. Ramel introduced the bill in 2021, when it passed the House but did not receive a Senate vote before the session ended. It sailed through the legislature unchanged this year.

As a greenhouse gas measure, the legislation requires that designers of public facilities with greater than 25,000 square feet of usable space, including schools, to consider all-electric systems and at least one renewable energy or combined heat and power system in their work. The bill also requires that these designs should include life-cycle cost analyses, the guidelines for which will be created by the Washington Department of Enterprise Services.

On Tuesday, Sen. Reuven Carlyle (D) and his chamber’s leader on environmental issues said, “We know that public leadership on this is important.”

In response, Sen. Shelly Short (R) and the GOP’s Senate leader on environmental issues, said the bill starts a slippery slope toward future actions, which she did not define or elaborate upon. “This seems like a piece that worries me as we go down the road,” Short said.

Sen. Mark Schoesler (R) framed his “no” vote as a protest against environmentalist efforts to tear down the four hydroelectric dams on the Snake River as a salmon recovery measure. He said it is wrong to require all-electric systems at the same time that hydroelectric dams are being targeted.

While breaching the dams has been discussed in the past two years — as well as off and on for the past 30 years — no solid studies or efforts have advanced beyond the speculation stage.

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Experts Warn Cyberwar Still Possible

For years, analysts have assumed that any Russian military action against its neighbors would be preceded by a major cyber offensive against the target country and its allies, aiming to disable its electricity and other utilities, along with government, military and civilian communications networks.

Nearly a week into Russia’s invasion of Ukraine, that threat doesn’t seem to have materialized. While the U.S. Cybersecurity and Infrastructure Security Agency (CISA) has noted an outbreak of “destructive malware … affecting Ukraine and other countries in the region,” Ukraine’s infrastructure appears largely intact. President Volodymyr Zelensky and his government certainly seem to have no problems keeping their smart devices charged and connected to the internet, rallying resistance to Russian tanks and bombers.

Likewise, while CISA is currently in a “Shields Up” posture and has called for critical infrastructure operators to be vigilant, the agency still says it sees “no specific or credible cyber threats to the U.S. homeland” despite having warned in January that such attacks might be imminent. (See Utilities Warned of Cyberattacks amid Russia Tensions.)

But experts say it would be a mistake for cybersecurity professionals to label Russia’s cyber capabilities an empty threat. The fact that the country apparently has not deployed its arsenal doesn’t mean the arsenal is bare, they say, and with the invasion just days old, there is plenty of time for the country’s leadership to reconsider its strategy and bring out the big guns.

“It’s no different than any other wartime tactic; once you reveal your playbook, there’s going to be a countermeasure … attached to it,” Betsy Soehren-Jones, Fortress Information Security’s chief information officer, told ERO Insider. “You’ve got to be strategic in how you push out those playbooks, and it just hasn’t been time yet.”

Fortress CEO Alex Santos agreed with Soehren-Jones, likening the Kremlin’s cyber offensive forces to its hypersonic missiles. The world has known of the technology for years; Russia test-fired the system shortly before the invasion into Ukraine began; and the fact that Russian President Vladimir Putin has not yet used it is no guarantee that he will not do so.

Santos suggested that Russia’s strategy so far indicates a “calculation that they can take and achieve their military objectives with their traditional weapons,” rather than exposing their more advanced cyber capabilities to the eyes of foreign intelligence agencies. If the conventional attack fails to reach its goals and economic sanctions begin to bite, then Putin may decide to move more aggressively against both Ukraine and those supporting it, including the U.S., he warned.

“One of the things that Russia has historically done is … surveillance and harassment and sowing seeds of misinformation. You might say that SolarWinds was that kind of attack,” Santos said, referring to the 2021 incident in which hackers — identified by the U.S. as Russia’s Foreign Intelligence Service — planted malware in the SolarWinds Orion network management software used by thousands of organizations around the world.

“We may see sort of a gradual campaign over time of them continuing their programs of meddling [and] death by a thousand cuts kind of thing,” he continued.

Questions About Ukraine’s Cyber Defenses

Ukraine’s readiness in the event of a major cyber offensive is still considered an open question by many in the industry. The country seems to be holding its own against the WhisperGate and HermeticWiper malware, which cybersecurity professionals identified earlier this year and which CISA and the FBI warned about last week. Ukrainian government officials are also attempting to organize an international network of hackers to strike back against Russia in cyberspace.

But industry watchers remain concerned about Ukraine’s capacity to resist a major, well resourced operation like the ones that targeted the country’s power grid in 2015 and 2016. (See Six Russians Charged for Ukraine Cyberattacks.) Robert M. Lee, CEO of cybersecurity firm Dragos, warned in a media briefing last week that he feared the investment in needed cybersecurity improvements since then has been severely lacking.

“I’m not saying there hasn’t been good work. But that stuff isn’t related to their infrastructure. Do I think they are building up more knowledge about what to do? Sure. Do I think that their infrastructure and the defensive ability of those infrastructure companies are in any better place than they were in 2015? No, I do not,” Lee said. “I think that if Russia, as an example, wanted to take down the electric system in Ukraine, they would be much more prepared to do so than … in 2015 and 2016.”

The situation may be brighter in the U.S. Santos called NERC’s Critical Infrastructure Protection (CIP) standards “the most robust cyber regulatory construct” among any other utility sector, and NERC has been quick to reassure the public of the Electricity Information Sharing and Analysis Center’s (E-ISAC) preparedness to quickly coordinate a response to potential attacks.

“Security of the grid continues to be a key priority for NERC, the U.S. and Canadian governments, and industry,” the organization said in a statement on Monday. “The continued coordination across our industry helps ensure vigilance and allows us to respond quickly should the need arise — we know nearly 400 million North Americans are counting on us.”

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NJ Delays Third OSW Solicitation for PJM Tx, NY Bight Winners

New Jersey will delay its third offshore wind solicitation from September 2022 to January 2023 to allow it to incorporate proposed transmission projects now being reviewed by PJM.

PJM received 80 proposals in response to a transmission solicitation it issued last year at the request of the New Jersey Board of Public Utilities (BPU). Under PJM’s state agreement approach (SAA), New Jersey would commit to paying 100% of the cost of the transmission but could seek to allocate some costs to other generation projects that use the additional capacity. (See PJM, NJ Seek FERC OK for OSW Tx Process.)

“The updated schedule allows for the SAA process to be completed and the outcome incorporated into the third solicitation guidance documents,” the BPU said in announcing its delay Monday.

The BPU said it expects to determine later this year, which, if any, of the 80 submissions — which include “ready-to-build offshore wind transmission solutions to deliver offshore wind energy to the existing power grid” — it will approve.

N.Y. Bight Winners Invited to Participate

The delay also will give developers that won leases in the Bureau of Ocean Energy Management’s (BOEM) auction in the New York Bight last week more time to prepare bids to win offshore wind renewable energy certificates (ORECs) in the New Jersey solicitation, the BPU said. BOEM provisionally awarded leases for six projects totaling 5.6 GW of capacity off the coasts of New York and New Jersey. (See Fierce Bidding Pushes NY Bight Auction to $4.37 Billion.)

The BPU plans to award 1.2 GW in ORECs in its third solicitation, with the award targeted for the fourth quarter of 2023. In its first two solicitations in 2019 and 2021, the BPU awarded ORECs totaling 3.7 GW: 2.2 GW to Danish developer Ørsted’s Ocean Wind I and Ocean Wind II projects, and 1.5 GW to Atlantic Shores, a joint venture between EDF Renewables North America and Shell New Energies US. (See NJ Awards Two Offshore Wind Projects.)

The Atlantic Shores partnership also won one of the six New York Bight projects, agreeing to pay $780 million for a 79,351-acre lease that the companies said could provide 1.5 GW of capacity. BOEM estimated the site’s capacity at 924 MW, based on 3 MW/sq km. Ørsted said it was not involved in any of the six winning bids in the BOEM auction.

7.5 GW Target

New Jersey hopes to award a total of 7.5 GW of ORECs by 2027.

BPU President Joseph L. Fiordaliso said the shift in solicitation date to January 2023 “takes into account two exciting and important milestones in offshore wind in our region.”

“With 80 proposals for transmission solutions submitted in response to the SAA solicitation, adjusting our timeline to allow for the selection of the optimal transmission solution will inform our next solicitation for offshore wind projects,” he said. “Coupled with the new lease areas in the New York Bight, developers will now have ample time to put together thoughtful and cost-effective proposals.”

The BPU launched its SAA project to solicit ideas on how to upgrade the grid to allow for integration of wind energy, how to extend the onshore grid to bring it closer to offshore wind generators and what upgrades are needed on interconnections between offshore substations to create an offshore grid, or “backbone.”

The bidders include a subsidiary of Consolidated Edison (NYSE:ED), which submitted a proposal for a 2.4-GW transmission “backbone.” PSEG, which owns a 25% share of Ocean Wind I, said it has submitted several proposals with Ørsted for offshore transmission, collectively named Coastal Wind Link. (See NJ Wind Port Draws Offshore Heavy Hitters.)

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MISO Seeking New Transmission Cost Allocation for Major Buildout

A month after filing a cost-allocation method for its long-range projects, MISO is on the hunt for a better approach to funding major transmission builds.

During a cost-allocation committee meeting Monday, the RTO opened the floor to stakeholder input on a new funding mechanism for the next round of long-range projects.

Staff have repeatedly said the separate-but-equal postage stamp rate divided between MISO Midwest and MISO South is meant to be temporary. The RTO has filed for FERC approval to use that design for the first two collections of projects from its long-range plan. (See MISO Finalizes Long-range Tx Cost Sharing Plan.)

MISO’s Jeremiah Doner said the grid operator is committed to applying a more permanent, “granular” cost allocation for future long-range projects.

“We want to have something with longevity in place,” Doner told stakeholders during the meeting.

Michigan Public Service Commissioner Dan Scripps, who chaired the committee, said the discussion on additional benefit metrics and quantifying them will continue well into 2023.

MISO envisions a new cost allocation for the third and fourth cycles of its multiyear long-range transmission plan. The planning will occur in four parts, with the first two focusing on the RTO’s Midwestern footprint and more immediate needs. (See MISO Long-range Tx Plan Overlaps with SPP Study.)

The third planning cycle will include transmission needs in MISO South. The fourth and final cycle will include MISO’s Midwest and South regions and solutions to increase transfer capability between the subregions.

The RTO will complete its first cycle of long-range projects in June and begin studying prospective projects in the second cycle in late spring or summer.

“We’re going to have to spend some time on what granularity means from a benefits perspective,” Doner said of cost-allocation talks for the third and fourth project batches.

He predicted that defining new reliability benefits will probably be most challenging. He said it’s easy to define reliability that satisfies NERC requirements, but it’s harder to pin down reliability that benefits regions, hardens the grid and leaves the system better positioned for extreme weather events.

Some stakeholders asked how the RTO will reconcile different allocations in the two halves of the long-range planning effort. Staff said cost-allocation methods morph over time.

“It’s a fair question. It’s a little hard to answer that from where we sit today,” Doner said.

Stakeholders are already advocating for a wider range of benefits in a new allocation design.

“If we’re really going to have a more granular cost allocation in place, we need to quantify more benefits,” Sustainable FERC Project’s Lauren Azar said. “As we’ve said ad nauseum, our current benefit metrics only identify a narrow slice of the benefits. So, there are a lot of free riders on our system.”

Currently, long-range cost allocation project benefits must support state or federal energy policies; address NERC issues and show reliability benefits across multiple zones; and demonstrate multiple types of economic value across multiple pricing zones with at least an overall 1:1 benefit-to-cost ratio over the first 20 years of service.

Several stakeholders said transfer capability could be a good resilience measure because the ability to flow power has been crucial during past winter storms. They also revived the debate on whether new generation should bear a portion of new transmission costs.

MISO will hold another cost-allocation workshop April 26.

“We’ve got some work ahead of us,” Scripps said, closing the meeting.

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Large New York Consumers Oppose National Grid Transmission Upgrades

A group of large electricity consumers opposes National Grid’s (NYSE:NGG) petition to New York state regulators to allow development of and cost recovery for 19 transmission upgrade projects (Case Nos. 20-E-0197 and 20-E-0380).

National Grid subsidiary Niagara Mohawk Power’s November 2021 petition to the Public Service Commission included a 2030 Regional Plan and also sought approval of cost deferrals and surcharge recoveries from its approximately 1.6 million electric customers.

But “it is not clear that all, or even many or any, of the proposed projects truly are needed at this time,” Multiple Intervenors (MI), an ad hoc group of more than 50 large commercial, industrial and institutional energy consumers, said Monday. MI was party to a recently concluded electric and gas rate proceeding for Niagara Mohawk.

None of the 19 projects was included in the $3 billion electric capital expenditures in a three-year rate plan approved in January, the group noted.

“Thus, the proposed projects either were not subjected to the typical scrutiny attendant in rate proceedings or, perhaps in certain instances, were subjected to such scrutiny and ultimately excluded from the long list of proposed projects used to justify the utility’s negotiated level of capital expenditures,” MI said.

National Grid argued in its petition that “each of the company’s Phase 1 solutions were designed after assessing existing reliability-based transmission projects – those projects already requiring upgrades to address condition issues, enhance storm resiliency, or improve operational performance – to minimize the cost to unbottle renewable energy,”

Under the New York Public Service Commission’s new transmission planning rules, Phase 1 projects are traditional utility investments that address system reliability or resilience issues, while Phase 2 projects are primarily intended to facilitate the state’s environmental targets. (See New York Adopts Groundbreaking Tx Investment Rules.) National Grid said it assessed existing reliability-based projects based on their ability to improve renewable energy deliverability as designed or improve deliverability if redesigned.

Nat Grid Phase 1 (National Grid) Content.jpgThe table summarizes the capital investment, including cost of removal, and operating cost estimates, incremental right of way requirements and improvements to the import/export capability (headroom) of each region. | National Grid

MI countered that the proposed projects would expose customers to near-term and long-term rate impacts.

“The impacts that would flow from the proposed authorizations should not be evaluated in a vacuum,” MI said.

In addition to the more than $3 billion in budgeted electric capital expenditures approved through fiscal year 2025, the commission previously has authorized tens of billions of dollars in customer collections for various clean energy programs and initiatives, and wholesale energy prices have jumped substantially in 2022, MI said.

“Because customer funds are far from limitless, and rising energy costs have significant, negative impacts on economic activity, the commission needs to ensure that Niagara Mohawk’s electric rates are shielded from capital expenditures that are not truly necessary for safe and reliable electric service,” MI said.

The group also opposes the approval of cost deferrals and surcharge recoveries, saying there is no clear urgency to start and complete all of the upgrades proposed now during a major expansion of Niagara Mohawk’s normal electric capital expenditures budget and while large-scale renewable generation development is occurring at a slower pace than previously had been anticipated.

“Quite simply, the commission needs to proceed very cautiously, else future electric rates and prices will become less affordable for customers and even less competitive with other regions, thereby harming state and local economies that still are reeling from the effects of the COVID-19 pandemic,” MI said.

National Grid said the 2030 Regional Plan “represents timely solutions to excessive renewable energy curtailments or ‘bottling,’ which leads to the undesirable effect of chilling generation investments, increasing energy prices and continuing to rely on the generation commitment and dispatch of fossil-fueled resources.”

The Alliance for Clean Energy New York (ACE-NY) supports National Grid’s petition, noting that the utility deems several of the Phase 1 upgrades as needed to enable further upgrades that will alleviate constraints threatening renewable development.

“Indeed, Grid points to the high-execution risk that Phase 1 upgrades pose to subsequent Phase 2 upgrades if Phase 1 upgrades are not approved” in a timely manner in certain areas of the state, ACE-NY said. “National Grid emphasizes it has staged the deployment of both Phase 1 and Phase 2 projects to provide benefits in the time frames needed for current and planned renewable generation development.”

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California PUC Sets Biomethane Targets

The California Public Utilities Commission established biomethane procurement goals for the first time Thursday to help reduce methane emissions from landfills, dairies and natural gas use.

The decision requires gas utilities to substitute a portion of natural gas with biomethane, mostly derived from landfills, which emitted 21% of methane statewide in 2019, according to the most recent figures from the California Air Resources Board (CARB).

Methane is a more potent greenhouse gas than carbon dioxide, though it is shorter-lived in the atmosphere. Burning biomethane results in open-air emissions.

“Tackling methane and other short-lived climate pollutants is critical given our climate crisis,” Commissioner Clifford Rechtschaffen, the lead commissioner in the proceeding, said in statement. “This decision will reduce emissions from some of the state’s leading methane sources.”

The state has a mandate, under Senate Bill 1383 passed in 2014, to reduce short-lived climate pollutants such as methane by 40% below 2013 levels through 2030.

Senate Bill 1440, adopted in 2018, required the CPUC to “consider adopting specific biomethane procurement targets or goals for each gas corporation so that each … procures a proportionate share … of biomethane annually.” The state’s two largest gas corporations under CPUC jurisdiction are Southern California Gas and Pacific Gas and Electric.

The CPUC decision requires gas companies to purchase a total of 18 Bcf of biomethane annually by 2025 — potentially diverting 8 million tons of organic waste from landfills each year. Most of the waste would come from compost and the chipping and grinding of trees and other vegetation, the CPUC said.

The decision also establishes a midterm goal of procuring 73 Bcf of biomethane per year by 2030, representing about 12% of residential and small-business gas use. Utilities must secure a percentage of the total based on their proportionate share of the market.

Biomethane from dairies is already incentivized under other state programs, so it can be used only to fulfill the 2030 target after a gas utility procures enough biomethane from landfills to meet the 2025 target, the CPUC said. The decision limited dairy biomethane to 4% of the total for the 2030 goal. Dairies emitted 54% of methane in California in 2019, CARB said.

State law requires landfills to capture or destroy methane, including through burning the gas to break it down, but they continue to emit large quantities of methane.

A recent NASA study found that 30 large “super emitter” landfills produce about 40% of the total point-source emissions detected in a survey of more than 300,000 industrial facilities, dairies and landfills.

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FERC Orders Negotiations in Duke-Muni Contract Dispute

FERC on Monday conditionally approved Duke Energy Progress’ (NYSE:DUK) proposed changes to its supply contract with the North Carolina Eastern Municipal Power Agency (NCEMPA) but ordered the two parties to negotiate over how the pact should be changed to reflect the latter’s use of batteries to shave its demand charges (ER22-682).

NCEMPA, which serves 32 cities and towns with municipal electric distribution systems, asked FERC in 2019 to issue an order declaring that its “full requirements” power purchase agreement with Duke permitted it to use battery storage to reduce the munis’ load during the peak hour each month that is used to determine capacity charges. FERC granted NCEMPA’s request in September 2020 (EL20-15), a ruling that was upheld by the D.C. Circuit Court of Appeals in January. (See DC Circuit Upholds FERC on Duke-Muni Battery Dispute.)

The capacity charge — based on NCEMPA’s pro rata share of the demand on Duke’s system during the one-hour coincident peak (CP) — is intended to cover Duke’s fixed costs and provide a return on its infrastructure investments.

New Contract Sought

DEP responded to the commission’s 2020 order by seeking to reopen the PPA, telling FERC that a revised rate design was needed because of statements by NCEMPA members announcing their intention to procure enough storage to reduce or eliminate their capacity charges “by superficially reducing or eliminating their demand only during the single CP hour of the month.” Since December 2020, NCEMPA and its members have issued solicitations for almost 150 MW of battery storage, DEP said.

The company said NCEMPA’s peak shaving was shifting capacity costs to four other wholesale requirements customers and that DEP’s retail customers also could be harmed because they pay a portion of the fixed costs.

DEP’s revised PPA would replace the current 12-CP methodology with a process that compares NCEMPA’s CP demand with its monthly non-coincident peak (NCP). In any month in which NCEMPA’s NCP exceeds its CP by 200 MW or more, the difference between the CP and the NCP minus 200 MW would be added back to the CP for setting demand charges.

The company told FERC the amended PPA is needed because “DEP’s system planning can no longer merely assume that the monthly coincident peak is the appropriate proxy for each customer’s use of the system.

“DEP’s limited visibility into NCEMPA’s intended time and magnitude of load management and demand cost mitigation measures creates real-time operational problems in so far as DEP must ramp (expensive and carbon-intensive) generation to meet NCEMPA’s anticipated load only to have NCEMPA members deploy demand cost mitigation measures, creating temporary and artificial load reductions to which DEP must quickly respond in real time,” it said, adding that the operational challenges will increase as it integrates more solar onto its system.

The company also proposed to change the nearly one-year notice period for proposed changes to the PPA. It currently gives the parties 60 days to reach an agreement on an amendment; if they are unable to agree, a 240-day informal dispute resolution process follows. DEP proposed shortening the notice and negotiation period from 300 days to 60 days, saying the current contract allows one party to “effectively hold the change hostage for almost a full year.”

NCEMPA protested, saying Duke’s proposal would penalize the development of distributed energy resources and that it violates cost-causation principles because the 200-MW threshold is arbitrary. It also complained that DEP would apply a cost allocation method that deviates from the conventional 12-CP method only to NCEMPA.

Ruling

FERC voted 4-1 to conditionally approve the revised PPA, effective March 1 and subject to refund pending settlement judge procedures.

The commission noted it has “previously accepted modification to a 12-CP methodology where the applicant sought to address cost shifting due to load-control measures.”

“Here, DEP has presented arguments that its current demand allocation method may fail to appropriately align costs with beneficiaries given the changing operational conditions on DEP’s system,” FERC said. “We find these arguments persuasive.”

The commission also dismissed NCEMPA’s argument that the revised PPA is unduly discriminatory, saying, “DEP’s departure from the 12-CP methodology … is not novel.

“Each of DEP’s wholesale customers has negotiated unique terms in their respective agreements based on their individual circumstances,” it said.

But the commission said it wasn’t convinced that DEP’s adjusted capacity charge calculation and 200-MW threshold are just and reasonable. It also said DEP’s proposal to modify its notice provisions from 300 to 60 days is “not adequately supported.” NCEMPA said it would consider some reduction in the duration of the informal process but that 60 days was too short for it to secure the necessary governing board consideration and approval.

Dissent from Clements

Dissenting was Commissioner Allison Clements, who said the commission should have rejected DEP’s proposal without prejudice and that the majority’s order “sets too low a bar for the filing party’s proposed rate to become effective as the hearing process moves forward.”

Clements said DEP failed to demonstrate how its rate proposal reflects its transmission planning. She also questioned why DEP doesn’t use NCP demands in allocating costs for all DEP customers.

“At minimum, a five-month suspension period is warranted in this case,” she said. “To the extent that the hearing process stretches beyond the 15-month refund period, NCEMPA risks being subjected to unjust and unreasonable or unduly discriminatory charges without any recourse.”

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Draft Study Weighs Tradeoffs of CO2 Pricing, FCEM for ISO-NE

A new draft study evaluating ways to decarbonize New England’s power sector finds multiple advantages for carbon pricing, but also significant tradeoffs that underscore the tough choices facing policymakers.

The draft of the Pathways Study, commissioned by ISO-NE and written by the consulting firm Analysis Group over the last year, was presented to the NEPOOL Participants Committee on Tuesday.

It looked at four policy approaches: a status quo scenario in which the New England states continue their unilateral clean energy policies; a forward clean energy market (FCEM) to compensate non-emitting resources; a net carbon pricing plan to price emissions from generators; and a hybrid approach which combines the latter two.

In theory, all four approaches can achieve “substantial” levels of decarbonization, the draft report says, but they come with unique challenges and costs.

Policy approaches (Analysis Group) Content.jpgThe differences between the policy approaches laid out in the study | Analysis Group

Net carbon pricing would be cost-effective, a standard which the report says the other solutions fall short of. It would “create price signals that incent all substitutions that can reduce emissions,” it says.

Carbon pricing would also result in the lowest social cost, a 28% decrease from the cost of the status quo. Importantly, however, it wouldn’t be the cheapest option for consumers; that prize goes to the hybrid plan, which would reduce customer payments, unlike the others.

Carbon pricing would also be the most feasible approach to develop, the report says, because policymakers have more experience creating that type of design than something like the FCEM.

“While there is experience with market-based systems for environmental attributes … the FCEM would involve certain policy design elements that have not been used previously and would likely require significant time and effort to develop,” the report says.

However, carbon pricing is less well-suited to coordinating individual state policies and clean energy targets.

ISO-NE has been a supporter of carbon pricing but has struggled to find consensus in the stakeholder process and particularly among state policymakers. (See ISO-NE: States Must Lead on Carbon Pricing)

NESCOE, representing the New England states, has opposed the concept of incremental carbon pricing administered by the grid operator, arguing in 2020 comments to FERC that “consumers could be exposed to costs exceeding several billions of dollars each year.”

Locational marginal prices (Analysis Group) Content.jpgThe distribution of locational marginal prices under each of the possible policy solutions | Analysis Group

 

The hybrid approach involves combining a carbon price sufficient to provide revenue adequacy for existing clean energy resources (like the Millstone nuclear plant, used as an example in the report) with an FCEM that provides incremental compensation only to new clean energy resources. It’s a “completely novel” approach and the report raises questions about its feasibility for that reason.

One other issue found with the FCEM and hybrid approaches is storage “churning,” in which battery owners “consume otherwise-curtailed variable renewable energy and earn net revenues through energy losses,” the report says. The conditions leading to that inefficiency would be caused by frequent and large negative LMPs, which occur in those two scenarios.

In effect, the storage resources would be being paid to generate clean energy credits for clean energy resources even though the energy wouldn’t be replacing carbon-intensive generation.

Another advantage the report finds for carbon pricing is that it would provide incentives for fossil fuel generators to reduce their carbon-intensity when it’s cost-effective to do so, although the scope for those emissions reductions is “limited given current technologies,” it finds.