ISO-NE and NEPOOL last week asked FERC to approve changes to the Inventoried Energy Program to reflect recent volatility in the global natural gas market and gas contracting prices in the region.
The program was designed as a stopgap for longer-term market reforms to ensure winter reliability and is designed to pay resources for maintaining inventoried energy during the next couple winters. The RTO initially filed the program in 2019, and it was approved by FERC in 2020 to go into effect for the winters of 2023/24 and 2024/25.
Russia’s invasion of Ukraine last year led European nations to seek alternate sources to Russian gas, which has increased volatility greatly. Demand from Asia has also gone up in the interim, ISO-NE’s consultant Todd Schatzki of the Analysis Group said in testimony filed at FERC.
“Since the commission’s acceptance of the IEP, global energy markets have experienced dramatic and unprecedented changes in pricing levels and volatility,” ISO-NE said.
One of the most significant changes was to replace the fixed rate for resources procured in the IEP to an indexed rate that will be able to reflect any changed prices going forward, as the recent volatility is expected to last for the next couple winters. The initial program featured both a forward and spot rate, allowing resources to sign up ahead of time or during the winter, and both of those are moving to indexed pricing.
The forward rate FERC approved was $82.49/MWh for inventoried energy, but the new price will be based on a formula using the price for liquefied natural gas at the “Dutch TTF” (Title Transfer Facility), a proxy for European prices that have recently set the price of LNG in the entire Atlantic basin.
The formula also includes a liquidation price to reflect the possibility that New England generators might procure too much LNG, which would have to be sold after the winter season when prices are typically lower.
The base rate is capped at $288/MWh, which reflects the opportunity cost from participating in the IEP and liquidation costs and is based on the price needed to secure inventoried energy given real-world constraints.
The spot price now in place is just $8.25/MWh, but the RTO asked FERC to change that one-tenth of the applicable base payment rate, which is consistent with the current market design.
The updates also include changes to natural gas contract eligibility requirements and fuel allocation for shared fuel inventory, which are meant to be better aligned with current contracting practices in New England.
IEP participants will have to submit contracts that do not restrict when the gas can be called on during a day beyond the North American Energy Standards Board’s Wholesale Gas Quadrant scheduling and nomination standards.
The currently effective rules are also too restrictive, ISO-NE and NEPOOL said, because they require a level of gas delivery firmness that is not commercially available from the interstate pipelines that serve New England, so that part was updated to reflect market realities.
If a natural gas contract specifies an indexed strike price, then that specified index must be at one of the Northeast trading locations for which Platts publishes a daily value in order to ensure the contract in question reflects regional prices.
ISO-NE and NEPOOL asked FERC to make the changes effective June 6, which will ensure the rules attract inventoried energy for next winter given the increased volatility in natural gas prices. The new indexed rate will also make it easier for market participants to hedge their program costs.
“Without the proposed changes to reflect actual market prices and contracting practices, the current commission-accepted IEP runs the risk of providing insufficient incentives for participants to procure and provide inventoried energy when needed to ensure reliability on the coldest winter days, when fuel supplies are stretched to their limits,” the filing said. “Relying on well established and reliable price indices ensures that the IEP is providing accurate price signals reflective of the actual costs of providing the service, while avoiding overcompensation at the expense of regional consumers.”
A new report from NERC, WECC, and the California Mobility Center (CMC) suggests that electric utilities and the electric vehicle industry need to start working together to address the charging behavior of EVs during grid disturbances, which could have “catastrophic consequences … if left unchecked.”
The report stemmed from a working group that NERC, WECC and the CMC formed last June to assess the impact to grid reliability of the anticipated increase in EV charging loads across the U.S. (See NERC, WECC to Examine EV Charging Risks to Grid Reliability.) Additional participants in the EV Grid Reliability Working Group included representatives from Lawrence Berkeley National Laboratory, CAISO and the Electric Power Research Institute.
“The efforts of the joint EV Grid Reliability Working Group illustrate the benefit of proactive cross-industry collaboration to achieve a common reliability objective,” WECC CEO Melanie Frye said in a media release. “Building on the work of this group, we can now improve the tools and assessments needed to understand the reliability risks and mitigation strategies for a future with much higher levels of electric vehicles and high-power charging stations in the West.”
While the working group has multiple topics of research, the new report focused on a “relatively unexplored” aspect of EVs’ intersection with the broader power grid: their performance during short-duration grid disturbances lasting from milliseconds to several seconds.
EV charging presents new challenges to grid reliability, unlike traditional end-use loads such as lighting, resistive heating and cooking. These older applications “were considered grid-friendly because their electric characteristic is constant impedance.” This means that when voltage drops slightly, the devices’ power draw also falls, supporting “stable steady-state operation of the grid.”
By contrast, EVs and other “electronically coupled loads … seek to maintain either a constant current level or a constant power level regardless of system voltage or frequency.” While the constant current approach is considered grid-friendly, because it allows power consumption to drop when system voltage declines, constant power chargers are grid-unfriendly because during times of lower voltage, their current draw increases to maintain the power level.
Another factor in grid-friendliness of EV chargers is ride-through performance and their ability to dynamically respond during mild grid disturbances. Citing data from Pacific Northwest National Laboratory, the report’s authors identified grid-friendly and unfriendly responses to disturbances.
In the grid-friendly case, the charger reduced current nearly instantaneously and kept it low for a short time; the grid-unfriendly charger did not respond to the fault until it was already cleared and then immediately resumed consuming current without giving the grid a chance to return to normal voltage levels.
The report presented its data as a starting point for a larger conversation between grid planners and manufacturers of EVs and their charging infrastructure on how best to safeguard the reliability of the grid during the ongoing electrification of transportation. Part of this work is being done by NERC and its partners in industry, which are developing a “new aggregate EV charging load model that can be used in … grid reliability studies.”
The ERO is planning further work in this area, including outreach to EV manufacturers to discuss additional areas of collaboration. The report said that building a framework for information sharing between utilities and EV manufacturers is “a key objective of NERC’s present engagement with the … working group,” which CEO Jim Robb agreed with in the release.
“As the electrification of the transportation sector continues to grow, the North American grid must be prepared,” Robb said. “Collaboration, innovation and information sharing are critical if we are to be able to meet future demands successfully. NERC is committed to working with stakeholders to unify our efforts in these areas to advance our shared reliability goals.”
Washington low-carbon fuel standard (LCFS) credit prices will likely range from $35 to $45 per metric ton by 2025, according to a company that analyzes carbon markets.
Analysts from cCarbon provided their estimates during a webinar on March 29.
A 2021 law that went into effect Jan. 1 requires Washington fuel providers to reduce the carbon emissions from gasoline and diesel sold in the state to 10% below the 2017 baseline by 2028, followed by 20% reduction below the baseline by 2035. The bill excludes from those targets any fuel that is exported out of state or used by waterborne vessels, railroad locomotives and aircraft. The goals apply to overall vehicle emissions in the state and not to individual types of fuels. Northwestern Washington has five oil refineries.
The law includes interim annual goals for individual fuel providers. Providers whose total emissions fall below their targeted goals will receive credits, while those exceeding targets will be required to buy credits from the lower-polluting providers. The law applies to providers selling fuel in volumes greater than 360,000 gallons per year.
During the webinar, cCarbon associate Bikash Maharaj noted that California LCFS credits are currently priced at $66.70/MT, as the state seeks to reduce vehicle emissions to 20% below the 2010 level by 2030, while Oregon credits are going for $117, as that state looks to cut vehicle emissions to 37% below 2015 levels by 2035. British Columbia credits are currently priced at $334, as the province seeks to reduce its vehicle emissions to 20% below 2020 levels by 2030, he noted.
In an email to NetZero Insider, Mafer Barrera, cCarbon client insights and partnerships manager, said the company’s estimate of a comparatively lower $35-$45 price range for Washington’s LCFS credits is based on speculation that the state’s biofuel supply chain faces fewer economic pitfalls than California and Oregon. The lower estimate is also based on growth projections for zero-emission vehicles in the state over the next several years.
The purchase and selling prices will be decided solely by the market with no state government influence, Maharaj said during the webinar. The emission thresholds are expected to shrink by 0.5 to 1.5% annually, he said.
Washington’s 7.6 million vehicles emitted roughly 40.3 million MT of carbon in 2017, accounting for 39 to 45% of the state’s overall carbon emissions, according to various estimates. The state wants to shrink that by 4.3 million metric tons annually by 2038.
A Montana court last week invalidated an air quality permit and ordered construction to halt on NorthWestern Energy’s (NASDAQ:NWE) planned methane gas plant, citing insufficient analysis of greenhouse gas emissions.
The 13th Judicial District Court in Yellowstone County ruled April 6 that the Montana Department of Environmental Quality’s (DEQ) 2021 issuance of a permit for NorthWestern’s 175-MW Laurel Generating Plant did not fully evaluate the facility’s environmental consequences and was not within the law (DV 21-1307).
The Montana Environmental Information Center (MEIC) and Sierra Club challenged the DEQ permit, saying the 20-page environment assessment didn’t adequately consider greenhouse gas emissions and climate repercussions. They said the permit ignored the plant’s sulfur dioxide emissions, and it did not analyze water-contamination risks of drilling under the Yellowstone River to build a pipeline to Laurel.
The court said DEQ’s exclusion of the pipeline’s environmental impact was appropriate because the State Land Board has that purview. However, it agreed that the agency violated the Montana Environmental Policy Act by issuing the permit without considering the full environmental harm caused by the plant’s construction and operation.
The court found that DEQ “reasonably examined” the plant’s impact on regional sulfur dioxide levels, but it did not conduct a substantive analysis of the plant’s greenhouse gas emissions. The agency argued that because it cannot regulate carbon emissions, it should not have to evaluate those pollutants.
District Court Judge Michael Moses said that counter to DEQ’s claims, the agency was not absolved from analyzing emissions.
“DEQ misinterprets the statute. They must take a hard look at the greenhouse gas effects of this project as it relates to impacts within the Montana borders. They did not take any sort of look at the impacts,” Moses wrote.
The court determined that DEQ must take another “hard look” at the project.
“This project is one of NorthWestern Energy’s largest projects in Montana. It is up wind of the largest city in Montana. It will dump nearly 770,000 tons of greenhouse gases per year into the air. The pristine Yellowstone River is adjacent to the project,” Moses said. “This project will have a life of more than 30 years. That amounts to in excess of 23 million tons of greenhouse gases emissions directly impacting the largest city in Montana that is less than 15 miles down wind. To most Montanans who clearly understand their fundamental constitutional right to a clean and healthful environment, this is a significant project.”
NorthWestern Energy did not respond to RTO Insider’s request for comment concerning the next steps it will take.
The MEIC and Sierra Club worked with the Thiel Road Coalition, a local group of landowners. The groups celebrated the ruling.
“My business, my family and my home will be directly impacted by NorthWestern’s proposed project. We have raised our concerns every step of the way, and state and local governments keep ignoring us,” Thiel Road Coalition’s Kasey Felder said in a press release circulated by MEIC. “We were worried we would get a ‘Braveheart’ ending to this story. It’s a relief to know the scales of justice are still in balance, and the little guy can be heard.”
“For too long it’s felt like a David versus Goliath battle. I’m so tired of the government and NorthWestern ignoring us. We live here. We have raised concerns time and time again about the impacts of this plant,” Carah Ronan, another coalition member, said. “When the government breaks the law and refuses to listen to the folks who live in the area, we have nowhere else to turn but the courts. We are thankful that the courts are willing to side with average Montanans who are just concerned about their health, property, businesses and future generations.”
With hours to go until the end of their 2023 legislative session, Maryland lawmakers on Monday passed the Promoting Offshore Wind Energy Resources (POWER) Act (S.B. 781), committing the state to developing 8.5 GW of offshore wind by 2031.
After the House of Delegates passed the bill on April 4, with amendments from its Economic Matters Committee, a conference committee was quickly formed Monday and hammered out final changes, removing some of the amendments. The bill was approved first in the Senate by a vote of 35-12 and then in the House of Delegates, 101-38. (See Maryland Lawmakers Vote to Raise Offshore Wind Target.)
In addition to more than quadrupling the state’s 2-GW pipeline of projects in development, the bill now headed to Gov. Wes Moore’s (D) desk would require the Maryland Public Service Commission to ask PJM to set up a State Agreement Approach planning process for offshore wind transmission, similar to New Jersey’s agreement with the grid operator. However, the bill calls on the PSC to reach out to other PJM states to evaluate regional transmission cooperation that could help it meet its offshore wind goals, according to the legislature’s analysis of the bill.
The PSC or PJM will have to issue one or more competitive solicitations for transmission projects by July 1, 2025. Additional solicitations could be issued after that if needed.
The bill requires PJM or the PSC to study specific transmission solutions, including one that uses an open-access collector system to allow for the interconnection of multiple offshore wind projects at a single substation.
One of the House amendments to the bill states that such studies must also “demonstrate net benefits to ratepayers in the state when compared with an alternative baseline scenario under which 8,500 MW of offshore wind capacity is connected to PJM Interconnection independent of an offshore wind transmission project.”
Such an alternative scenario might connect offshore projects to PJM via individual radial lines as opposed to networked transmission linking multiple projects to onshore substations. Industry experts increasingly favor networked, meshed HVDC systems as the most flexible and efficient for offshore transmission. (See OSW Developers Look to Europe on Meshed HVDC Tx.)
Moore is expected to sign the bill, after voicing his support for its 8.5-GW goal at the recent Business Network for Offshore Wind (BNOW) International Partnering Forum in Baltimore. The new target would produce “enough energy to power nearly 3 million homes” and provide opportunities to rebuild and expand steel manufacturing in the state, he said. (See U.S. Wind Industry Set to Take Off.)
Industry Response
Industry response was immediate and celebratory, heralding both the bill’s clean energy and economic benefits.
“The POWER Act establishes a comprehensive strategy to plan, connect and deploy offshore wind at the scale necessary to support supply chain investments and decarbonize Maryland’s economy at the lowest possible cost to Marylanders,” said Evan Vaughan, deputy director of the Mid-Atlantic Renewable Energy Coalition.
The law will allow the state to reclaim “national leadership in offshore wind [by] establishing a first-in-the-region initiative to proactively plan a 21st century transmission grid,” Vaughan said.
BNOW CEO Liz Burdock agreed that “the POWER Act repositions Maryland back into a leadership position, and with the federal government opening up new lease areas next year, offers the state a rare opportunity to attract major manufacturing and supply chain investment.
”Maryland must capitalize on this opportunity by moving quickly from legislation to execution and commercialization,” she said.
“The POWER Act is a real game changer for Maryland,” said Jeff Grybowski, CEO of Maryland-based offshore wind developer US Wind. “It sets a path for the people of Maryland to reap the benefits of huge amounts of clean energy in the coming years. It also tells the entire offshore wind industry globally that Maryland is back big time as a major player. Companies looking to invest in offshore wind have to seriously consider Maryland.”
Echoing Vaughan, Nick Bibby, Maryland state lead for Advanced Energy United, hailed the bill’s regional approach to transmission planning, saying it “will improve the transmission infrastructure planning process to improve grid efficiency and resiliency, lower utility bills for homes and businesses, and create good-paying jobs that connect Maryland to wind and solar resources.”
Maximize Opportunities
Other amendments to the bill include a call for the state to “maximize the opportunities” for obtaining federal funds for offshore wind and transmission projects by aligning its labor and domestic content standards with those in the Infrastructure Investment and Jobs Act and Inflation Reduction Act.
Provisions in the two laws either require projects to pay prevailing wages and offer registered apprenticeship programs. Tax credits provide bonus incentives for ensuring clean energy projects include made-in-the-U.S. materials and components.
Here are some other key sections of the bill:
Transmission proposals could include upgrading the existing grid, extending the transmission grid both onshore and offshore, interconnecting between offshore substations, adding energy storage, and using high voltage direct current converter technology to support potential weaknesses in the transmission grid.
The PSC will have to pick one or more transmission proposals by Dec. 1, 2027, and then work with the developers, PJM, FERC, potentially other states, and other stakeholders to ensure the lines get built. If the solicitation does not lead to any beneficial or cost-effective proposals, the PSC can end it without picking one and would then have to notify the legislature of its decision by Dec. 1, 2027.
The bill also includes language for the 2 GW of offshore wind developments that have already cleared earlier procurements, allowing developers to ask the PSC for an exemption to the requirement that they pass along to ratepayers 80% of the value of any state or federal grants, rebates, tax credits, loan guarantees or other benefits. Developers must prove that the exemption is needed to meet their contractual obligations.
The Public Utilities Commission of Ohio is preparing to consider formal comments on the findings of independent audits of extra customer charges collected in 2020 by three utilities buying electricity from Ohio Valley Electric Corp.’s (OVEC) coal-fired power plants, often at above-market prices.
The action by the PUCO to accept formal comments on the performance audits came two days after the Sierra Club, the Ohio Environmental Council and other groups publicly demanded action by the regulator.
2019’s Ohio Clean Air Act, better known as HB 6, added surcharges to ratepayer bills to subsidize the OVEC plants. The provision was added to the controversial bill, aimed primarily at subsidizing FirstEnergy’s (NYSE:FE) nuclear plants in the state, to ensure its passage.
When former Ohio House Speaker Larry Householder (R) was indicted on federal racketeering conspiracy charges in connection with the bill, state lawmakers in 2021 revoked the nuclear subsidy but rejected several bills seeking to eliminate the OVEC subsidy, known as the “legacy generation rider.”
AEP Ohio (NASDAQ:AEP), AES Ohio (formerly Dayton Power & Light) (NYSE:AES) and Duke Energy Ohio (NYSE:DUK) are the largest investor-owned companies that jointly own OVEC and have contracted to buy a percentage of the power generated by its two 1,000-MW plants at whatever it cost to produce. The plants were designed and built in the early 1950s. OVEC offers most of their power into the PJM market.
The agreement between OVEC and the three utilities is also designed to work in reverse, producing customer credits if OVEC’s costs were less than market prices. That happened in 2022 when the companies added modest credits to customer bills, reflecting the lower price of coal compared with natural gas during the period.
The surcharge raised total customer bills in the state by $114.7 million in 2020 and $72 million in 2021 but reduced the total amount paid by customers of the three utilities by $28.5 million in 2022, according to PUCO figures obtained by RTO Insider.
The performance audits were done for the PUCO by Boston-based London Economics International. The company audited each company’s monthly OVEC-connected charges from Jan. 1 to Dec. 31, 2020. The audits have been available in a PUCO docket, but the agency has only now called for comments, which are due May 5.
The performance audits found that “overall … the processes, procedures and oversight were mostly adequate and consistent with good utility practice.” They also found that one component of fixed costs that each of the three utilities listed appeared to be similar to a “return on investment,” something not permitted by a company operating in a deregulated market.
Following the March 9 conviction of Householder and a former state Republican Party chairman, two Democratic state representatives introduced a new bill to eliminate the OVEC charge and require the utilities to reimburse customers for past collections. The bill is in committee, but no hearings have been set. (See Householder Convicted in FirstEnergy Bribery Case.)
“Initially the subsidy was imposed by the PUCO. And now the subsidy is a state law courtesy of the infamous House Bill 6 and utility lobbying,” said J.P. Blackwood, spokesman for the Ohio Consumers’ Counsel. “Consumers should not be forced to pay AEP, Duke and AES for this corporate welfare. Ohio is supposed to be a deregulated state for power plants, meaning there should be no subsidies at consumer expense for these AEP/Duke/AES coal power plants.”
The Ohio Manufacturers’ Association noted in a study released on March 24 that customers have already paid nearly $400 million to the three utilities for their ownership in OVEC and can expect to pay a total of $850 million by 2030 unless HB 6 is revoked in its entirety.
FERC on Friday conditionally approved a PJM proposal to revise its approach to accrediting intermittent and hybrid resources under its effective load-carrying capability (ELCC) model, a change that aims to more accurately model roadblocks to delivering capacity from those generators during peak conditions (ER23-1067).
The new rule caps the hourly output that can be incorporated in the ELCC calculation at the resource’s individual capacity interconnection rights (CIR) level and creates a transitional process where generators can temporarily receive higher accreditation while they undergo a re-evaluation of the value of their capacity contribution.
PJM’s current practice of including hourly output above a resource’s CIR rating in its ELCC analysis when setting accreditation has been the source of much of the contention over the two years and is the subject of an ongoing complaint with FERC (EL23-13). (See Stakeholders Challenge PJM in Capacity Accreditation Talks.) The approved proposal was the result of a long development process that culminated in stakeholders approval in January. (See PJM Stakeholders Endorse Accreditation Changes for Renewables.)
“We agree with PJM that reflecting a resource’s deliverable megawatts in PJM’s model of the resource’s expected output guarantees that the modeled output will not exceed the resource’s studied deliverability and aligns with the requirement that a capacity resource’s sell offer cannot be greater than its CIR megawatt value,” the commission said in its order.
In its filings, PJM stated that the shift was based on a reconsideration of the assumption that historical system conditions can be used to effectively estimate the future reliability contribution of intermittent resources. Instead, it posits that decarbonization is likely to change system conditions to a degree that the ability to evaluate future outputs and curtailments is uncertain. The revisions also change the accredited unforced capacity (AUCAP) analysis to adjust actual output to account for curtailments.
For combined resources, such as hybrids, the output of the variable component in the ELCC calculation will be capped at the overall generator’s deliverable megawatt value minus the effective nameplate capacity of the limited-duration component, such as a battery. PJM argued that the status quo risks overcounting the output of the intermittent portion of the generator and cause the combination resource’s ELCC output to exceed its deliverability.
Because the new methodology will effectively reduce the accreditation for intermittent resources and require existing and planned generators to re-enter the interconnection queue, which has been beleaguered by long review times, the revisions include a transitional process through which generators can request a higher temporary accreditation and take advantage of existing transmission headroom.
To participate in the transitional study process, the additional capacity a generator is seeking to deliver must be available without any physical modifications to the facility, and the headroom must not be claimed by another generator’s CIRs. The studies will be conducted prior to each future BRA and continue until PJM has completed the process of transitioning to the new methodology for studying interconnection requests.
The commission identified inconsistencies between the filing’s description of the transition mechanism and the proposed revisions to PJM’s Reliability Assurance Agreement (RAA). It required that the RTO submit a compliance filing within 30 days aligning the two.
Protests
The proposal originally included a requirement that generators seeking to enroll in the studies apply by March 3, but by approving the filing with an April 10 effective date, the commission extended the application time frame and encouraged PJM to consider lengthening it further should it pursue its stated intention of delaying the 2025/26 Base Residual Auction and future capacity auctions.
An association of clean energy industry groups opposed the filing, arguing that closing applications for the transition studies violates a Federal Power Act provision requiring RTOs provide at least 60 days’ notice of any proposed changes and does not provide generators enough time to determine how much additional capacity they should request. It argued that PJM should instead include a new window for applying for the transition studies prior to each BRA.
PJM responded by stating that the stakeholder process included significant discussion of the process and “more than ample notice of the timing.” It also said more than 400 study requests have been submitted, which it said is evidence that generators had sufficient time to apply.
FERC said that, “should PJM determine to make a filing with the commission to delay the 2025/2026 BRA, we encourage PJM to consider extending the deadline for submitting a request to increase a resource’s CIRs as well.”
The Natural Resources Defense Council protested the proposal on the basis that it represents undue discrimination against ELCC resources by requiring them to pay for higher transmission costs to recover the accreditation that would be lost under this proposal, when in the past thermal generators have had interconnection costs passed to load under what it describes as similar circumstances.
“PJM’s proposal does not require any ELCC resources to pay for upgrades to ensure reliability; PJM is offering ELCC resources the opportunity to request additional CIRs to increase their accredited UCAP,” FERC said. “The interconnection queue is PJM’s existing process by which all resources request and receive CIRs. Thus, PJM’s proposal is not unduly discriminatory; it simply reflects existing processes that are designed to achieve different goals.”
Clements Dissent
In opposing the filing, Commissioner Allison Clements argued that the proposal will reduce generators’ ability to deliver capacity that is currently able to be provided to the transmission system and requires them to re-enter the transmission queue at the back of the line, potentially creating scenarios in which generators that could provide their status quo capacity with minimal upgrades wait years to find that they’re now being asked to pay substantially higher transmission upgrade costs. By reducing the accreditation for both intermittent and combined resources, she said, the order risks increasing capacity costs, sending inefficient price signals and over-procuring capacity.
“In other words, owners of existing ELCC resources whose requests for a higher amount of CIRs could have already been processed at low cost find themselves sent to the back of a slow-moving line that will take years, fighting to purchase at a potentially much higher price the same capacity deliverability they could’ve already gotten, or arguably have already purchased,” Clements wrote.
She also argued that the April 10 deadline provided too little notice for generators, likely creating an “ill informed mad dash into the interconnection queue.”
“Rewarding this approach allows regulated entities to strong-arm market participants into compliance actions prior to a commission determination, meaning that proposed rules that are not just and reasonable or are unduly discriminatory will shape commercial decisions before the commission can opine on them,” Clements wrote. “While an order ultimately rejecting a proposal as not just and reasonable or unduly discriminatory would give market participants some relief from having to comply with a rule that does not past muster under the Federal Power Act, it would not return to them the time and money spent complying with the proposed unjust and unreasonable or unduly discriminatory rule in advance of the commission’s determination.”
The California Public Utilities Commission on Thursday approved rules for its Microgrid Incentive Program, a $200 million effort to support the development of microgrids in communities prone to extended blackouts from wildfires, earthquakes and line outages.
The approved decision allocated funds to the state’s three large investor owned utilities — $79 million for Pacific Gas and Electric, $83 million for Southern California Edison and $17.5 million for San Diego Gas & Electric — to “build complex projects that can operate independently for extended periods and serve multiple customers in disadvantaged and vulnerable communities,” the CPUC said in a statement.
Selected microgrid projects can receive up to $15 million each.
“The Microgrid Incentive Program will provide valuable support to disadvantaged and vulnerable communities towards ensuring they are not left behind in the broader statewide resiliency effort,” Commissioner Genevieve Shiroma, who led the proceeding, said in the statement.
“These communities tend to be located in more electrically isolated areas with greater distances to essential services, experience more outages, and have less accessibility to entities with backup power. This program will also provide the funding and education many communities need to meaningfully participate in the program.”
Disadvantaged and vulnerable communities eligible for the grants include those in areas at high risk of wildfires or that have experienced public safety power shutoffs, the intentional blackouts that utilities use to prevent their equipment from starting blazes. Also eligible are locations prone to damaging earthquakes and those with lower levels of reliability because they are served by one of the worst-performing circuits in a utility’s system.
The Blue Lake Rancheria microgrid, in an area that meets all the requirements, is often cited as an example of the value of microgrids in California. It uses a 420-kW solar array and battery storage to power a hotel and casino with electric vehicle charging, a convenience store gas station and water systems used by nearby residents during frequent outages, including to keep cell phones charged. It was funded by a California Energy Commission grant last decade.
The CPUC proceeding began in 2019 in response to Senate Bill 1339, which required the commission to “facilitate the commercialization of microgrids for distribution customers of large electrical corporations” and to “develop separate large electrical corporation rates and tariffs … to support microgrids.”
Thursday’s decision also directed PG&E, SCE and SDG&E to conduct outreach and consult with potential program applicants, and to help successful applicants develop community microgrids. It requires the utilities to post handbooks to their websites within six months to “guide applicants through the program and explain how potential projects will be evaluated.”
The utilities must submit quarterly status reports to the CPUC until the funds run out.
ALBANY, N.Y. — Natural gas is in the crosshairs of New York’s decarbonization drive, but the fossil fuel will likely remain indispensable to the state’s energy portfolio for years to come, even as it contributes to climate change.
So, until the transition is accomplished, it is critical to leverage every molecule of gas as efficiently as possible, panelists argued during the April 4-6 NY Energy Summit.
The state’s Climate Leadership and Community Protection Act (CLCPA) codified decarbonization goals, including 70% renewable energy generation by 2030 and zero-carbon electricity by 2040, while New York City’s Local Laws 97 and 154 effectively will ban installation of new gas systems in buildings starting in 2024.
And as New York’s Tale of Two Grids notes, upstate regions’ power needs are almost entirely supplied by renewable resources, while downstate is run almost exclusively by fossil fuels, particularly natural gas.
“New York was a pioneer in using gas, and so it is no surprise that it is now pioneering aggressive climate goals that reduce methane,” Chris Stolicky, chief of gas system planning and reliability at the New York Department of Public Service, said during his “Future of Natural Gas” presentation.
“The catch to this is that if you lose gas service, it’s a very big deal” because it “delivers three times as much BTU content and energy to customers than other resources,” so if New York wants to “offset that heating load with electric versus natural gas, [the state] needs to deliver three times as much energy,” Stolicky said.
Cooperation is Key
Natural gas is targeted for its global warming effects, both from methane leaks before combustion and carbon dioxide emissions during combustion. But as Stolicky noted, New York continues to rely on it for more than 40% of its energy needs, and the United States has become the largest gas producer in the world.
On top of that, there was a widespread push to replace oil-burning equipment with cleaner-burning gas until relatively recently. New York now “wants to stop that train … and find a better way to generate energy because there’s a lot of emissions and impacts,” Stolicky said.
This is not expected to be easy, particularly in the densely populated downstate regions.
Therefore, “as the last firewall” between policymakers and consumers, Stolicky and his team act as the “gas ISO for New York,” and look to balance system reliability and affordability with environmental concerns by bridging cooperation between stakeholders.
“A well planned and strategic transition of the gas system will require coordination across multiple sectors,” he said.
Stolicky said an integrated planning process involving customers, NYISO and state agencies enables gas utilities to forecast peak demand, keep costs low without compromising reliability, and educate ratepayers about an industry whose operations influence their daily lives but has “not always been transparent.”
Stolicky said his agency remains committed to New York’s decarbonization, but there are challenges ahead and stakeholders need to “buckle down and work hard collectively” to overcome them and bring the state to its net-zero goals.
New York utilities argue they are well positioned to tackle these challenges because of their existing network of assets, extensive knowledge about grid operations, and ability to invest in new technologies to replace natural gas.
Leverage Every Gas Molecule
During the Transmission & Distribution Plans & Investment panel, moderated by RTO Insider’sRich Heidorn Jr., Christopher Raup, vice president of energy policy and regulations at Consolidated Edison (NYSE: ED), and Tom Vaccaro, director of transmission business development at National Grid (NYSE: NGG), made their case for why utilities are well positioned to help New York’s transition.
Both panelists emphasized how state utilities committed to collaboratively decarbonize through the Coordinated Grid Planning Process (CGPP). They said that the plan will maintain reliability, expedite renewable development and deployment, keep utilities competitive and not hurt ratepayers.
Leaving “no stone unturned” the CGPP plan offered by New York’s utilities would operate via a “meaningful iteration” process that integrates stakeholders while “striking a balance between coming up with new information and getting [interconnection] processes done as quickly as possible so that [stakeholders] can iterate again,” said Vaccaro.
New York has a “high voltage” problem, said Vaccaro, explaining that the grid is “running at 345 kV, which is very high compared to what you would typically see for bulk power at the utility distribution level.” The utilities’ CGPP proposal would solve this issue by integrating transmission planning at all grid levels so utilities “can build things for customers that are less expensive.”
Additionally, after Superstorm Sandy, utilities have actively worked with state agencies and other stakeholders to develop climate modeling that predicts extreme weather impacts on the electric system, according to the panelists.
Utilites “take lessons from climate change vulnerability studies and reflect those in the infrastructure that [they] build out and operate,” said Raup.
“All of us utilities have a shared [decarbonization] vision with the state and NYISO,” and the cooperation initiated by the CGPP “hopefully removes some roadblocks and expedites these processes,” Vaccaro said.
Vaccaro fielded a question about how the state’s utilities are strategizing fossil fuel infrastructure as the state presses to make it obsolete.
“We’re not going to be able to do everything at once” but will “leverage the remaining life out of our gas system” since New York’s electrification may face future challenges, he said. Utilities plan to “use [gas] equipment for as long as [they] can before transitioning out.”
Raup added that hydrogen could be used in existing gas infrastructure after 2040 and “could help fill the valleys when the sun isn’t shining, or the wind isn’t blowing.”
Hydrogen: A Natural Gas Substitute?
Hydrogen is still in development as a clean and economical energy source but likely has a future in New York as the technology improves.
Green hydrogen was frequently cited “as a tool to reduce greenhouse gas emissions” in the Climate Action Council’s Scoping Plan.
More recently, the state, as part of the seven-state Northeast Regional Clean Hydrogen Hub, applied to be designated as a national hub for hydrogen.
“I envision hydrogen infrastructure across the U.S. with pipelines in different municipalities all shifting their waste to go to hydrogen gasification,” Joe Bushinsky of the Regional Hydrogen Infrastructure Development at Mitsubishi said during the Hydrogen Hubs: Financing, Revenue Structures & Incentives panel.
Introducing this technology to scale “is a challenge, but it is doable” he said. “There is a market for [hydrogen] but a lot of things have to fall into place.”
One potential opportunity, Bushinsky said, “is to take waste and instead of putting it into landfills and waiting years for it to produce renewable natural gas to instead move it to syngas to produce hydrogen.”
Pete Budden, a green hydrogen advocate with the Natural Resources Defense Council, tempered expectations, saying hydrogen “is an incredibly useful and important tool in our decarbonization toolbox,” but “can be a distraction from more cost-effective solutions.”
“Hydrogen is an indirect greenhouse gas,” Budden said, referring to how atmospheric leakages prevent methane decay, so it “should not land into gas distribution networks” because that blending is “where we are most worried about leaks.”
Michel Delafontaine, president of Alternative Aviation Fuels, agreed, saying “blending is not going to be the project that drives these infrastructure demands” and hydrogen’s best application will be decarbonizing transportation or energy-intensive industries such as steelmaking.
But he pointed out that some utilities, SoCal Gas for example, have been studying how to safely blend hydrogen into their gas networks.
“There are opportunities for these infrastructure projects” to help gas utilities decarbonize since it can “act as an enabler” to defer consumer costs by expanding capacity, Delafontaine said.
Moderator Michelle Detwiler, executive director of the Renewable Hydrogen Alliance, added that Hawaii Gas has been “blending hydrogen into their syngas residential distribution systems at about 20% for 46 years with no deleterious effects.”
The push to phase out natural gas as quickly and completely as possible in New York is countered by the need to maintain its infrastructure as long as needed.
Jessica Waldorf, chief of staff and director of policy implementation at the Department of Public Service, touched on this during her presentation. “There are many paths to achieving the outcomes envisioned in the climate act,” she said, and a “one-size-fits-all approach is unlikely to meet the diversity of needs across the state.”
A new report from Oregon’s Global Warming Commission (OGWC) says although the state is a long way from meeting its 2035 greenhouse gas reduction target, it should nonetheless advance that goal by five years.
The Oregon Climate Action Roadmap to 2030 says the state is expected to meet its goal of reducing economywide GHG emissions to at least 45% below 1990 levels by 2035, but cautions that “there is a great deal of work that needs to be done before then.”
And despite the workload, the OGWC calls for the state to accelerate its 2035 GHG-reduction target to 2030 because “the best available climate science indicates the need to go further and faster to avoid the worst impacts of climate change.”
“The new Roadmap to 2030 reflects that urgency and demonstrates that it is not only feasible to achieve the state’s 2035 goal by 2030, but doing so will also provide substantial economic and health benefits for Oregonians,” OGWC Chair Catherine Macdonald said in a statement accompanying release of the report on Friday.
Oregon’s GHG targets are set out in Executive Order 20-04, which former Gov. Kate Brown (D) issued in 2020 after Republican state senators walked out of the legislature to prevent a vote on a bill establishing a cap-and-trade program for the state. The order directed state agencies to implement policies to help reduce GHG emissions to at least 45% below 1990 levels by 2035 on the way to an 80% reduction by 2050.
The roadmap is the product of the Transformational Integrated Greenhouse Gas Emissions Reduction (TIGHGER) project, a yearlong effort that convened the OGWC, state officials, consultants and various stakeholders to address the fact that Oregon’s existing planned actions on climate change would not be sufficient to meet state targets. Those actions include three major efforts being led by the state’s Department of Environmental Quality, including:
implementation of the Climate Protection Program (CPP), designed to drive down emissions from stationary sources, transportation and natural gas by setting declining caps on GHGs;
an expansion of the Clean Fuels Program (CFP), which will decrease the carbon intensity of fuels sold in the state by 25% by 2035; and
a program to reduce GHG emissions from electricity generation 80% by 2030, 90% by 2035 and 100% by 2040.
Other state actions include the Heat Pump Rebate Program, the Community Renewable Energy Program and adoption of California’s Advanced Clean Cars II and Advanced Clean Trucks rules. (See Groundbreaking California Clean Truck Rules Win EPA Waiver.)
Despite existing efforts, Oregon’s 2020 GHG emissions totaled 58 MMTCO2e, 13% above its target of 51.3 MMTCO2e (a 10% reduction from 1990 levels). Emissions rose further, to 61 MMTCO2e, in 2021, 19% above the 2020 goal. The roadmap “is aimed at ensuring Oregon does not miss its next GHG emission reduction goal,” the commission said.
Relying on analysis from the TIGHGER process and OGWC discussions, the roadmap recommends six “overarching strategies for maintaining and increasing Oregon’s climate action ambition,” including:
supporting “robust and continuous implementation” of the state’s existing climate programs and regulations, such as the CPP and CFP;
adopting updated GHG goals consistent with the best available science;
advancing a set of new climate actions based on the TIGHGER analysis to help the state accelerate its GHG reduction goal to 45% below 1990 levels by 2030, rather than 2035;
supporting “further study and analysis to continue to guide effective climate action over time;”
strengthening “governance and accountability” to ensure the state meets its targets; and
positioning the state to “take full advantage” of federal money directed at climate action.
‘Scientific Imperative’
The roadmap fills out those strategies with 26 “sub-recommendations” containing more concrete actions.
“For example, policies supporting the development and availability of transmission could help alleviate a potential barrier to achieving the clean electricity targets in HB 2021,” the report says.
The roadmap also urges the state to ensure that programs benefit environmental justice communities that suffer a disproportionate burden from the impacts of pollution.
Some of the most challenging recommendations fall under the second strategy that seeks to update the state’s GHG goals. They include clarifying that Oregon’s policy is to pursue GHG reduction actions consistent with the goal of limiting the global temperature rise to 1.5 degrees Celsius. That would entail reducing emissions to at least 45% below 1990 levels by 2030, followed by reductions of at least 70% by 2040 and 95% by 2050.
“[A] 2050 goal of 95% below 1990 levels would be consistent with the leadership our neighbors to the north [Washington] and south [California] are showing, better reflect the existing ambition of some of Oregon’s key climate programs, and result in the strongest emissions reductions — which is ultimately the scientific imperative,” the report says.
Under the third strategy — advancing new climate actions — the OGWC lists an extensive set of recommendations that include a 50% improvement in energy efficiency of industrial facilities not covered by the CPP by 2050; exceeding Advance Clean Truck targets by 2035; boosting rooftop solar output to 16.3 TWh by 2035; increasing Amtrak ridership; and implementing congestion pricing on highways in metropolitan areas.
To improve accountability for achieving GHG targets, the report calls for an increased role for the OGWC itself. They include boosting dedicated staff by one full-time equivalent (FTE) from the current 0.3 FTE; expanding the list of OGWC’s non-voting members to include representatives from additional state agencies, such as the economic development agency Business Oregon, the Department of Fish and Wildlife, and the Oregon Health Authority; and expanding the OGWC’s voting membership to include a youth representative and an expert in environmental justice.
The roadmap also calls for additional funding for the OGWC to create and maintain a dashboard and clearinghouse for tracking climate action, emissions and carbon sequestration data.
The OGWC additionally recommends that Oregon agencies coordinate their efforts in pursuing funds from the federal Infrastructure Investment and Jobs Act and Inflation Reduction Act.
“The amount of federal funding that is coming available for climate, clean energy, and natural and working lands projects is unprecedented and presents a huge opportunity for Oregon,” the roadmap says. “Many of these programs will be competitive in nature — meaning Oregon will be competing with other states for limited funds. Oregon will need to be ready to apply for these funds with credible, well thought out programs and projects.”
