Stakeholder committee chairs last week restored a MISO stakeholder governance group to manage matters related to the RTO’s stakeholder governance guide.
MISO’s Steering Committee, comprising stakeholder group heads, on Thursday approved the Stakeholder Governance Working Group’s (SGWG) charter that describes the group as an “open forum” for stakeholders to “oversee and manage” the RTO’s Stakeholder Governance Guide.
The guide lays out how the various committees, work groups and task forces are structured and how meetings should be conducted. The SGWG will conduct periodic reviews of the governance guide, address stakeholders’ suggestions to improve the stakeholder process and discuss concerns over meeting facilitation.
The working group will meet twice per year or as needed. Meetings are open to all interested stakeholders.
The SGWG was disbanded about seven years ago, leaving only members of MISO’s advisory and steering committees to propose and develop revisions to the governance guide. (See MISO Members Want to Revive Stakeholder Governance Group.)
MISO’s stakeholder relations group will request leadership nominations via email and schedule the first meeting later this month.
Reliability Subcommittee Chair Ray McCausland, with Ameren, proposed reviving the small stakeholder group last year and volunteered to chair it.
“I’m really excited to see this invigorated again,” said Steering Committee Vice Chair Sarah Freeman, who sits on the Indiana Utility Regulatory Commission. “It’s great to see so many stakeholders interested in how we conduct our business at MISO.”
Xcel Energy’s Carolyn Wetterlin, vice chair of the Cost Allocation Working Group, said it was reassuring to have the stakeholder community’s “governance geeks” back on the job.
Freeman said she would like to see the SGWG tackle how the Advisory Committee can have more input into tariff change filings before MISO sends them to FERC.
“I think the governance process has suffered to some extent because of the stakeholders that can talk about it,” McCausland said, a reference to the years that only Advisory Committee and Steering Committee members could direct governance guide changes.
The Smart Electric Power Alliance (SEPA) last week released its latest assessment gauging utilities’ progress and identifying actions to accelerate the industry’s transition to a carbon-free energy system.
SEPA recognized a dozen utilities in its 2023 Utility Transformation Challenge as being ahead of the curve in the clean energy transformation. Most of those are in California, with glowing reviews to Palo Alto Utilities, Pacific Gas and Electric, Sacramento Municipal Utility District and Southern California Edison.
The organization said Snohomish County Public Utility District in Washington and Portland General Electric in Oregon also made good progress.
On the East Coast, SEPA praised Vermont’s Green Mountain Power, New Jersey’s Public Service Enterprise Group and National Grid, which supplies New York and Massachusetts. Austin Energy, the Texas city’s municipal provider, and Minnesota-based Xcel Energy were the only commended utilities between the two coasts.
Those recognized had to complete SEPA’s Utility Transformation Challenge survey to be considered. The organization said it collected data from 118 utilities in 41 states, representing more than half of U.S. customer accounts.
SEPA said the utilities that made its final cut supply “a substantial percentage” of their retail energy with clean resources, including energy efficiency and demand response; have strong commitments to carbon reduction; feature publicly available climate-adaptation strategies; and have plans for an equitable energy transition.
It said it’s also noticing an asymmetrical transition to clean energy, though utilities have rolled out more aggressive decarbonization targets, better climate action plans, improved visibility into their distribution systems, and have made strides to a more equitable power system.
The group said 66% of utilities responding to its survey have expanded their clean energy sources and 80% have a carbon-reduction goal in place. SEPA said it expects those goals will take decades to achieve and recommended utilities establish interim reductions goals.
“Utilities will need to navigate supply chain disruptions, transmission and interconnection bottlenecks, the effects of natural disasters on resource acquisition and costs,” SEPA said, adding that utilities cited labor shortages and supply chain hitches for delaying new renewable energy. Those scuttled plans have led to 40 coal plants keeping 17 GW of capacity online past their planned retirement dates, SEPA said.
It said 69% of respondents are piloting or investing in early stage, carbon-free technology, including hydrogen, long-duration energy storage, floating offshore wind, tall wind turbines, small modular nuclear reactors, and carbon capture and storage.
SEPA said gridlocked interconnection queues have also hampered utilities trying to bring renewable generation online. It said PJM’s current backlog is preventing it from reviewing new interconnection requests until early 2026.
The organization also said droughts in the West contributed to a 14% reduction in hydroelectric generation from 2020 to 2021 and continue to threaten the carbon-free resource. SEPA warned that some utilities may be forced to purchase fossil-fired energy to replace the output.
To avoid that, SEPA recommended utilities use more demand-side management programs and pull together climate investment plans that consider the impact of climate change on operations.
FERC on Friday approved the tariff for the Western Power Pool’s Western Resource Adequacy Program, a groundbreaking reliability effort covering much of the Western Interconnection that is meant to ensure members have sufficient resources to meet summer and winter peak demands (ER22-2762).
The commission’s approval means the WRAP can move forward with its plans to begin a binding phase of the program by 2025, including penalties for members that fail to meet their obligations.
“Through increased coordination, we find that the WRAP has the potential to enhance resource adequacy planning, provide for the benchmarking of resource adequacy standards and more effectively encourage the use of Western regional resource diversity compared to the status quo,” FERC said in its decision.
At least 11 utilities had committed by December to joining the binding iteration of the WRAP. The nonbinding phase of the program has 26 participants, many of whom are expected to move into the next phase. (See Western RA Program Secures First ‘Binding’ Phase Participants.)
WPP has been developing the WRAP since 2020. The program initially was meant to address concerns that Northwest utilities had been increasingly and unknowingly drawing on the same shrinking pool of reliability resources, but interest in the effort spread quickly to other areas of the West.
WPP selected SPP to develop and operate the technical aspects of the program, providing the market’s forward-showing functions, modeling and system analytics, and real-time operations.
In a move that signified its expanding reach across the Western Interconnection, the Northwest Power Pool rebranded itself as the Western Power Pool in February 2022. The WPP board approved the tariff in August, sending it to FERC. (See Western Power Pool Board Approves WRAP Tariff.)
The commission responded in November with a deficiency letter that asked WPP to provide clarifications on the tariff filing, including about the program’s proposed requirement that participants secure transmission rights well in advance and about its intent to hire an independent evaluator to assess its performance. (See FERC IDs Deficiencies in Western RA Program.)
WPP responded to FERC’s questions Dec. 12, leading to the commission’s determination Friday.
FERC addressed a number of comments, protests and concerns, including questions about transmission commitments. The program’s forward-showing component requires participants to show they have sufficient capacity and 75% of the transmission necessary to deliver it seven months ahead of each summer and winter. Penalties will apply to those who do not.
The Northwest & Intermountain Power Producers Coalition (NIPPC) argued that the “required use of firm transmission contradicts the commission’s allowance for use of non-firm transmission in similar circumstances,” FERC said.
NIPPC also had “concerns with the 75% forward-showing transmission requirement, including the lack of support for the specific figure of 75%, the potential for market power being exercised by incumbent firm transmission rights holders and transmission providers, and the practical reality that transmission providers regularly release sufficient short-term [available transfer capability] well after the WRAP’s forward-showing deadlines to meet program needs.”
“NIPPC states that this will lead to regular requests for exceptions,” the commission said.
FERC disagreed with NIPPC’s protest. WPP’s forward-showing program “includes reasonable requirements to ensure deliverable resource adequacy, while also providing necessary flexibility to participants. Further, we find that the requirements of the proposed program can help to enhance price formation in the Western Interconnection by sending price signals to market participants regarding the availability of capacity and firm transmission service and the need for future market entry.”
With respect to the independent evaluator, FERC staff had asked WPP in November whether the evaluator’s report would be made public.
WPP responded that the evaluator’s annual reports are “intended to be made public” and proposed a tariff revision to explicitly state that the “independent evaluator’s annual reports shall be made available to the public, except to the extent that they contain information designated as confidential under this tariff, or information designated as confidential by the independent evaluator.”
FERC accepted WPP’s clarification and tariff revision.
“We recognize that for the commission, state regulators, participants and other stakeholders, the independent evaluator’s reports will be a key source of information and analysis on the WRAP’s operation,” FERC said. “Further, the WRAP is a novel design for the Western Interconnection, and as the program matures, the insight into its functioning will provide useful information and transparency to all stakeholders.”
In a news release Friday, WPP CEO Sarah Edmonds said, “We’re so pleased that FERC shared the industry’s appreciation for the value of a regionwide resource adequacy program and supported our vision for it. This is a critical step for the West to help ensure that we can achieve a clean energy future, without sacrificing reliability.”
The WPP will next make governance changes required by the tariff by seating an independent board of directors that it named in October.
“Our governance model, including an independent board of directors, is a critical piece of the WRAP,” Edmonds said. It “was demanded by our stakeholders and establishes the standard for regional organizations like this one.”
Duke Energy (NYSE: DUK) on Thursday reported higher earnings for the full year of 2022 because of higher electricity volumes, more favorable weather and rate case contributions.
The company reported adjusted earnings of $5.27/share, compared with $4.99/share in 2021, though unadjusted earnings came in at $3.33/share, compared to $4.94/share the previous year.
“We achieved results solidly within our updated guidance range while making significant progress on our strategic goals, responding to external pressures and delivering constructive outcomes across our jurisdictions,” CEO Lynn Good said during an earnings call.
The company is in the process of selling Duke Energy Sustainable Solutions, a non-regulated renewables developer that has 5,319 MW worth of projects spread around the country, and it took an impairment charge of $1.3 billion related to the sale.
“I think the thing to recognize on an impairment charge is it’s an accounting adjustment that’s really driven by the earnings profile of renewables where a lot of the profit sits in the early part of the life, [and] you then depreciate it over a longer period of time,” Good said. “So, when you make a decision to exit before the end of the useful life, you’ve kind of set yourself up for an impairment.”
Duke announced plans to sell its commercial renewables business in November, and it hopes to complete that process later in 2023.
While it is getting out of the business of developing competitive renewable projects, most of Duke’s expected spending in the coming years will be on shifting its regulated utilities to cleaner generation, with a $65 billion capital plan for all of its regulated businesses.
In North Carolina, the next steps for that capital spending have been laid out in the firm’s first carbon plan, which was approved by state regulators late last year. The state approved Duke to build 3,100 MW of solar and 1,600 MW of energy storage in the near term, with limited development activity for longer-term projects, including small modular nuclear reactors.
The North Carolina Utilities Commission also authorized Duke to plan for about 2,000 MW of new natural gas plants that Good said are needed for reliability.
“Through its order, the commission reinforced the importance of maintaining a diverse generation mix while conducting an orderly clean energy transition and was clear that ensuring replacement generation is available and online prior to the retirement of existing coal units is a shared priority,” Good said.
The carbon order supports Duke’s own capital plan, giving it the clarity that it needs to advance critical near-term investments, she added. Duke plans to spend $4.7 billion over the next three years, largely on transmission and distribution enhancements, though with some earmarked for the solar and storage approved by the NCUC.
While Duke is focused on solar and storage in the short-term, Good said the company would need to build 10 to 15 GW of “zero-emitting load-following resources in the late 2030s, or 2040s.
“That could be hydrogen; it could be small modular reactors; it could be [carbon capture, utilization and storage]; it could be longer-duration storage,” Good said. “So, the key being, again, though, we’re not going to invest until they are affordable for our customers, and we can invest at the commercial scale necessary to make a difference.”
Duke is spending time on small modular nuclear reactors because it is the largest “regulated” operator in the country and is in part of the world where the technology is generally viewed favorably, Good said.
The company has also worked with neighboring utilities in the Southeast on a hydrogen hub because Good expects it will have plenty of extra solar energy that could be used to produce the fuel.
“We’re not ready to put our finger on any specific technology as the solution,” she added. “But we are advancing our work, piloting, advising, working as actively as we can to make sure these technologies are developing at pace so that when we do need them and are ready to invest, there will be something that makes sense for our customers.”
NERC and the regional entities this week called FERC’s proposal for new reliability standards focused on inverter-based resources (IBRs) “complementary to the work the ERO Enterprise is presently undertaking,” while suggesting an alternative timeline to the commission’s plan (RM22-12).
The ERO was responding to the Notice of Proposed Rulemaking that FERC issued at its open meeting in November. The proposal asserted that the “impacts of IBRs on the reliable operation of the” bulk power system are not adequately addressed by current reliability standards. The commission proposed to direct NERC to develop new standards to address four specific topics: data sharing, model validation, planning and operational studies, and performance requirements for registered IBRs. (See FERC Addresses IBRs in Multiple Orders.)
In their response filed Monday, NERC and the REs agreed with the commission that IBRs could pose “elevated risks … to reliable operation of the BPS if not addressed appropriately,” pointing out that the ERO “has taken an active role in developing reliability guidelines … and other materials to raise awareness of possible IBR risks and provide industry with best practices to mitigate those issues.” They also said that FERC’s suggested topics “align very well with NERC’s identification of risk areas,” although the ERO did suggest refining some aspects of the commission’s proposals.
NERC and the REs balked, however, at FERC’s suggested timelines for developing the standards and proposed an alternative plan.
Under the NOPR, once FERC approved the ERO’s standards development and implementation plan — due 90 days after the NOPR is approved — NERC would have 12 months to submit its proposed standards to address registered IBR failures to ride through frequency and voltage variations. After another 12 months, NERC would have to submit standards concerning data sharing, model validation, and planning and operational studies; and 12 months after that, the final standards, addressing post-disturbance ramp rates and phase-locked loop synchronization, would be due.
The ERO observed that the commission’s proposed timeline does not seem to account for the fact that NERC already has standards development projects underway that touch on the issues FERC raised in its NOPR. The ERO suggested that “these projects should be prioritized and addressed on a faster time frame,” and that the NOPR’s timeline be rearranged to reflect the work that can be done earlier.
Under the ERO’s suggested timeline, after FERC approves the standards development and implementation plan, it would have:
12 months to submit standards addressing comprehensive ride-through requirements and other known causes of IBR tripping, post-event performance validation and disturbance monitoring data for registered IBRs;
24 months for standards addressing data-sharing issues other than disturbance monitoring data and data and model validation for registered and unregistered IBRs and distributed IBRs (IBR-DERs); and
36 months for standards addressing planning and operational studies for registered and unregistered IBRs and IBR-DERs.
The ERO concluded by reminding the commission of its ongoing work to identify new “issues and challenges associated with IBRs [that] may continue to require attention for years to come,” including commissioning processes for IBRs and security concerns that may not be adequately addressed by current standards. The organizations said that they are “not requesting any specific commission action on these areas at this time,” but they sought to remind FERC of the “breadth of the challenges” in this space.
NERC is also working on another order issued at FERC’s November meeting: a work plan detailing how it will identify and register owners and operators of IBRs that are connected to the BPS and “in the aggregate have a material impact” on reliable operation but are not currently required to register with the organization (RD22-4). That is due Feb. 15.
Soaring natural gas prices drove up wholesale electricity costs in the CAISO energy market by roughly $4 billion in December and January, making it one of the more expensive periods in recent years, an ISO report said this week.
About $3 billion of that amount came in December, when natural gas prices in California far outpaced the national benchmark Henry Hub in Louisiana. On Dec. 21, for example, spot prices at Henry Hub averaged $6.14/MMBtu, while those in California reached $53.59/MMBtu, nearly nine times more, the U.S. Energy Information Agency reported.
High natural gas prices impacted large swaths of the West in December, including the Desert Southwest and the Pacific Northwest.
“Next-day natural gas prices for Western hubs reached a maximum value of about $57/MMBtu on Dec. 22,” a day when CAISO’s wholesale costs surged toward $300 million, far beyond its standard cost of $50 million, the CAISO report said.
“Prices for other Western hubs traded at similarly elevated levels across the month of December … [while] Henry Hub prices remained comparatively low,” it said.
In the fourth quarter of 2022, total electricity costs in CAISO reached $7.4 billion, just short of the third quarter’s $7.6 billion total during a severe heat wave that brought CAISO to the verge of ordering rolling blackouts Sept. 6 and pushed electricity prices past $2,000/MWh. (See CAISO Reports on Summer Heat Wave Performance.)
The third quarter costs reflected “summer conditions where record-high demand levels were settled at relatively higher prices given the tight supply conditions,” the report said. “The cost of fourth quarter of 2022 came fairly close to the same level of the third quarter, at about $7.4 billion, even though electric demand was lower.”
“This is a twofold and threefold increase relative to the fourth quarters of 2021 and 2020, respectively,” it said.
The sudden and largely unexplained jump in energy prices in California and the West led Gov. Gavin Newsom to urge FERC to act. In a letter Monday to FERC Chair Willie Phillips, Newsom asked the commission to “immediately focus its investigatory resources on assessing whether market manipulation, anticompetitive behavior or other anomalous activities are driving these ongoing elevated prices in the Western gas markets.”
Wholesale natural gas prices directly affect electricity costs because California relies heavily on gas-fired power plants, which often act as the marginal unit setting the price for all units clearing CAISO’s day-ahead and real-time markets. The gas costs are passed on to ratepayers by the state’s investor-owned utilities, doubling and tripling bills for millions of customers, especially in Southern California.
“California’s residential customers are, consequentially, suffering the economic burden of extreme and unexpectedly high gas and electric utility bills,” Newsom wrote.
The California Public Utilities Commission, state Energy Commission and CAISO held a joint meeting Tuesday to try to understand the factors that led to the extraordinary price hikes. Market analysts and utilities weighed in, citing conditions such as an El Paso Natural Gas pipeline that exploded in Arizona in August 2021, impacting one supply line to California, and CPUC limits on storage at Southern California Gas Company’s Aliso Canyon, where a massive methane leak occurred in October 2015.
A cold snap in December increased heating demand from residential customers in California and across the West, panelists said.
In his letter to FERC, Newsom said the cold weather certainly “exacerbated” the gas price increases but lower-than-normal temperatures and other “known factors cannot explain the extent and longevity of the price spike,” which began in late November and lasted through January.
“It is clear that the root causes of these extraordinary prices warrant further examination,” he said.
Former FERC Chair Richard Glick said Wednesday that an industry report on the estimated value of additional transmission during December’s Winter Storm Elliott only underscores what many already know: Transmission capacity makes a big difference.
It can also produce savings.
“When you reduce congestion, you’re able to bring in less costly power from other regions, and that has a big impact, certainly on prices,” Glick said Wednesday during a webinar focused on the report. “That’s a big deal because when we have these extreme weather events, we know prices are at their highest sometimes. But secondly, transmission also helps with grid resilience and reliability. Another reason is [regions] might not be experiencing that same weather at the same time … Empower[ing] other regions is a big positive.”
Glick brought up ERCOT’s problems importing power from other regional operators during the deadly 2021 Winter Storm Uri because of its lack of interconnections with its neighbors. Hundreds of Texans died without power during that storm. At the same time, MISO successfully wheeled power from PJM to SPP to help the latter grid avoid Texas’ woes.
“Transmission support not only from a consumer perspective, but also for keeping the lights on,” he said.
According to a report released Wednesday by the American Council on Renewable Energy (ACORE), “modest investments” in some regions’ interregional transmission capacity would have saved electricity customers nearly $100 million during December’s five-day storm.
ACORE, which hosted the webinar, said expanding transmission ties by 1 GW between regions would have generated significant cost savings for consumers and reduced outages during the storm. It said that Duke Energy’s Carolinas region and the Tennessee Valley Authority would have yielded savings of $85 million and $95 million, respectively, had they been able to import enough power to prevent rolling blackouts.
‘Bigger Than the Weather’
The report studied transmission benefits by comparing LMPs within RTOs and ISOs and at interfaces with non-organized market areas during each hour of the Dec. 22-26 storm. The analysis conservatively used hourly average LMPs instead of prices at five-minute intervals, as current practices for scheduling transactions between regions include market seam inefficiencies that limit the ability to use transfers to address short-term fluctuations in price.
“Making the grid bigger than the weather is the key to making our power system more resilient,” said Michael Goggin, a vice president at Grid Strategies and the report’s author. “Basically, the solution here is making the grid bigger than the weather. If the grid is bigger than that event, that allows you to get that demand diversity because [regions are] not all peaking at the same time. You could bring in generation from areas where the gas supply wasn’t interrupted or the generators didn’t have failures.”
Goggin said a bigger grid is also the solution to higher penetrations of wind and solar, with the side benefit of full resource adequacy.
“If you go across a large enough area, particularly with wind, the correlation between any two wind plants drops to almost zero. They’re just experiencing different weather at different times … kind of mitigating and canceling out the variability of wind,” he said. “More importantly, you get the resource adequacy benefit. If it’s not windy here, it’s going to be windy somewhere else, and having the transmission allows you to move that power between those areas.”
ClearPath CEO Rich Powell agreed. He said the country will need “tremendously” more wires and pipes — for natural gas, hydrogen, carbon-capture — as part of an enabling infrastructure to build a net-zero economy by 2050.
“My guess is that we’re going to need a lot of renewables built on public lands further west just because we’re seeing so much opposition growing, especially in the middle of the country that’s already very dense on wind,” he said. “My suspicion is we’re going to have to build more of that further west on public lands, which itself is going to imply more long-distance transmission.”
Powell is hopeful early hearings in Congress on permitting reform proposals might be a sign of optimistic developments but allowed that “we’re at the beginning of that journey.”
ACORE CEO Greg Wetstone lamented the loss of an investment tax credit for high-voltage transmission, a victim, he said, during final negotiations over the Inflation Recovery Act (IRA).
“That is the one piece that is really important and ended up on the cutting room floor,” he said. “That kind of incentive would be helpful … [in] getting the investment we need to better connect the grid.”
Wetstone said the tax credit is one of three areas that have seen real progress in the last two years but aren’t “over the finish line.” He listed FERC’s proposal for more proactive transmission planning addressing extreme weather and siting and permitting language that a congressional parliamentarian scratched from the IRA under budget reconciliation rules.
“We need more help, more clarity in order to get these lines built,” he said. “We’re potentially in the game with this Congress to get something done in siting and permitting.”
‘Geographic Opportunity’
Glick reminded his fellow panelists that the commission’s joint task force with state regulators has been focused on interregional transmission capacity. The group holds its sixth meeting Feb. 15.
“One thing we kept them coming back to is the need for more interregional transfer capacity or transmission capacity,” he said. “Is there a need for some sort of minimum requirements between regions or something like that?”
“Interregional transmission continues to be a key missing ingredient for U.S. grid reliability in the face of increasingly frequent extreme weather events,” Wetstone said, calling for action on proposed “pro-transmission” policies and reforms in Congress and at FERC.
“It has been exceptionally difficult, if not impossible, to develop interregional transmission under the current planning processes and related rules,” he added.
“There’s quite a bit of interest among not only FERC commissioners but also state commissioners about moving forward,” Glick said. “It’s not easy to figure out who decides what gets built and who pays for all those issues, but I’m optimistic that you’re going to eventually see something.”
“The weather is getting bigger and bigger, and the grid is not keeping up with it,” former FERC and Texas commission staffer Alison Silverstein said. “We are seeing patterns where the wind goes bonkers as the front comes in, and then it dies off as the front is leaving. Being able to play the geographic opportunity is extremely valuable. We need to be able to build diversity, and we need to be able to build customer survival while all these dynamics and expansions are taking place. So it’s an extraordinary challenge and opportunity.”
That may come at the RTO/ISO level. MISO said that while it didn’t have the chance to fully review the report, the findings appear to support the grid operator’s efforts to develop more transmission to maintain reliability and manage the uncertainty and volatility of extreme weather events. The RTO pointed to its work on its four planned long-range transmission portfolios, noting that the benefits from the first tranche of projects are greater than the $10 billion costs.
In an email to RTO Insider, spokesperson Brandon Morris said MISO is a strong supporter of interregional transmission planning and “has worked diligently to improve our operations and planning with our neighbors.”
“Strong interconnections are foundational for the grid of the future,” he said. December’s winter storm “was a recent example of the benefits of interregional transfer capacity — at times during that event we were importing power from our neighbors, and at other times we were exporting power to support them.”
PJM and SPP declined to comment on the ACORE study. An SPP spokesperson said staff is currently evaluating its response to the latest winter storm to understand its impacts and how they can be mitigated in the future.
The Rhode Island Public Utilities Commission on Thursday held a conference on the issues surrounding natural gas distribution infrastructure as the state moves toward a net-zero future.
Chairman Ron Gerwatowski said the event was an unusual one for the PUC: an open dialogue and listening session, rather than a contested proceeding.
The discussion stems from Rhode Island’s 2021 Act on Climate, which mandates net-zero climate emissions by 2050. The scope of the resulting PUC docket on gas distribution was published only a month ago, after a public comment period.
Gerwatowski outlined the complexity of the path ahead, given the state’s (and region’s) heavy reliance on natural gas to heat homes and generate electricity.
“We can create legal mandates, but no one can amend the laws of physics to instantly mandate the emissions away,” he said.
But the Act on Climate mandates change, so the PUC must find ways to eliminate most or all such emissions in the state, he added. Imposing a moratorium on new natural gas hookups and creating regulatory pathways to abandoning the natural gas system will be among the options on the table, he said.
The goals are mandated, but the exact path to reach them is not, Commissioner Abigail Anthony noted.
“This is really big deal,” Commissioner John C. Revens Jr. said. It was good that so many talented people with so many different perspectives were in the room, he added, because the process needs to be community-driven.
The potential impacts of this transition, and who gets stuck with the tab, were the focus of most of the panelists.
Michele Leone, vice president of gas for Rhode Island Energy, spoke of the utility’s ongoing modernization of its 3,200 miles of gas mains, replacing about 65 miles per year. She did not give a price tag, but Mackay Miller of consulting firm ERM said completion could take 15 more years and cost more than $1 billion.
“The rate base of the entire gas network would likely reach its peak at the final year of pipe replacement,” Miller said. “So the risk of unstable economics for customers is real.”
As customers start electrifying their homes and businesses in larger numbers, the cost of the gas infrastructure falls on an increasingly small number of ratepayers. If electrification is carried out only in the homes of people who can afford to pay for it themselves, the gas infrastructure costs fall on the low- and middle-income customers least able to afford them. And if the costs of stranded gas assets are folded into electric rates, it is a disincentive to the overarching goal of electrification.
Dan Aas of Energy and Environmental Economics (E3) recalled a study of these dynamics that the firm performed in California.
“One potential concern is that as gas rates may increase as utilization of this stuff falls, you could have an economic, or rather, uncontrolled exit of customers from the system,” he said, “which raises some challenges as far as sustainability of the system financially but also significant equity challenges.”
This risk of uncoordinated departures from the gas system needs to be considered in any regulatory review of the future of natural gas, Aas said.
Jeff Makholm of National Economic Research Associates said he is skeptical of the entire concept of natural gas being abandoned because it is such an affordable and reliable fuel.
“We don’t know what the state is going to look like in 2050,” he said. The idea that natural gas will be largely eliminated is “at best unknown, at worst naive,” he said.
But others are ready to make the transition now.
Jennifer Wood, executive director of the Rhode Island Center for Justice, displayed maps where areas of high poverty, low rates of homeownership and high rates of childhood asthma heavily overlap one another.
“In these heavily impacted census tracts, when properties are going to be renovated or mechanical systems are going to be replaced, weatherization and abandonment of gas heating should be the goal starting today,” she said. “And all financial incentives and penalties should be designed to achieve that goal.”
The benefits of decarbonization should be extended first to those communities that for a century have paid with their health for fossil fuel use, Wood said. The cost should be borne most by those who have suffered the effects of fossil fuel emissions least.
“Please don’t pursue low-hanging fruit; do hard things,” she said.
Ben Butterworth, director of climate, energy and equity analysis at the Acadia Center, said the benefit of decarbonization is societal, and its costs will likely need to be borne societally, rather than strictly by ratepayers.
Paul Roberti, chief economic and policy adviser to the state Division of Public Utilities and Carriers, said Thursday’s conversation was an important start given the enormous technical, legal and economic considerations involved in meeting the goals of the Act on Climate.
“The division believes the pace of any policy changes should be guided by two words: ‘orderly transition,’” he said. “What I mean by ‘orderly’ is that any chosen set of policies safeguard two of the bedrock principles in our system of regulation: reliability and affordability.”
Roberti repeated a message conveyed in some way in almost every discussion of decarbonization: “We need to get our electric grid situation in order before we encourage or demand customers switch from gas to electric.”
Toward the end of the conference, Gerwatowski noted that he had heard many diverging viewpoints.
“I don’t think anybody said anything here which you could say, ‘No, that’s not true,’” he said. “Or maybe there was something someone would quibble with. But the idea of the general comments everybody made was, ‘Yeah I agree,’ but then they collide.”
The PUC expects to publish the next step in the docket Friday. It will try to form a stakeholder committee similar to the one formed to look at modernization of electric rates in 2016.
Massachusetts kicked off the year by giving new life to a longtime goal of many climate and clean energy advocates in New England: developing a Forward Clean Energy Market.
The FCEM idea has been floating around New England since at least 2016, when it was put forward by renewable energy companies.
It has evolved into a proposal that the Massachusetts Department of Energy Resources (DOER) put out in the first week of January, relying on help from consultants at the Brattle Group and Sustainable Energy Advantage. (See Massachusetts Floats FCEM Proposal.)
“Our current market structures and the current procurement process, although they provide a lot of incentives, it’s difficult to scale those both in size and speed,” Joanna Troy, Massachusetts’ director of energy policy and planning, said in a recent webinar.
That’s why the state has put forward the regional plan, aiming to accelerate the development of clean energy sources to help Massachusetts and the region’s other states meet their ambitious goals.
But with the document now out and making the rounds, the question floating around New England’s energy stakeholders is: “Now what?”
As the state tries to advance its plan to start a regional clean energy market, it will have to face down a heavily bureaucratic stakeholder process, a cautious grid operator, and the general inertia of a region that remains way behind on its decarbonization goals.
The key to Massachusetts’ proposal, energy and climate experts say, is that it remains flexible and gives states some leeway to transition their own existing, patchwork clean energy incentives into a regional market over time.
“It’s tailored to the fact that the region has a bunch of renewable energy decarbonization goals that have different flavors to them,” said Pete Fuller, a consultant at Autumn Lane Energy Consulting.
“What the DOER and their consultants have done here is to try to meet the region where it is and create a platform … that will enable the region to meld existing policies and objectives into this new platform. I’m very encouraged by that,” Fuller said.
The proposal includes four types of clean energy certificates with varying degrees of resource specificity; plus it would allow states to offer their own individual RECs or other existing incentives on the regional platform.
That would let the New England states access the market without necessarily making any changes to their existing statutes — at least at first.
Susannah Hatch, director of clean energy policy at the Environmental League of Massachusetts, echoed that understanding of the FCEM plan’s design.
“It’s an additive feature to existing markets currently being administered by ISO-NE, which would still allow states to explore procurements outside of it,” she said.
But she said she’ll be watching closely to see how the market would address the fact that sometimes cost isn’t the overriding factor in procuring energy.
“Renewable energy sources are not apples to apples,” she said. “We definitely want to make sure that the market incentivizes a balanced renewables portfolio for New England.”
Big Governance Questions to Answer
What’s prevented FCEM from moving from concept to reality is primarily a complex set of questions about how the market would be governed.
To what extent would ISO-NE be involved? Would the market be FERC-jurisdictional? How would the states share control of its design and operation?
The Massachusetts proposal recognizes the difficulty of answering those questions and puts forward a preliminary plan that includes creation of an independent nonprofit governed by representatives of the six states, which would work alongside ISO-NE and have the ability to propose rule changes to FERC.
But it also mentions possible alternatives and says the states will keep studying.
“The fact that Chapter 1 of the report is governance highlights the importance of that topic and hopefully jumpstarts those conversations so that we can begin to resolve this stuff and put some real certainty to a structure, rather than the sort of speculative conversations we’ve been having,” Fuller said.
As far as ISO-NE is concerned, the ball is fully in the states’ court.
ISO-NE spokesperson Matt Kakley said the grid operator is “reviewing the proposal and awaiting further guidance from the New England states on whether this is a path they’d like to pursue.”
Fuller said the RTO is a “cautious beast.”
“And they are very anxious that the states lay out a clear plan and really provide a definitive direction,” he said. “Once the states do that, then I think the ISO will engage, and I think we can all get into problem solving.”
Troy said that the state’s priority is getting feedback from the public.
After that, she said, Massachusetts will “continue discussion within the NESCOE setting with other states before determining what or if an additional NEPOOL or process would be necessary.”
The Midwest faces several new risks in 2023, including cybersecurity threats and supply chain difficulties, according to the Midwest Reliability Organization’s 2023 Regional Risk Assessment, released Monday.
MRO prepares its risk assessment each year as a supplement to the ERO Enterprise’s publications, such as NERC’s Long-Term Reliability Assessment (LTRA), State of Reliability Report and Reliability Risk Priorities Report, focusing on the risks specifically facing utilities in MRO’s footprint. The report was developed by MRO staff with input from the regional entity’s three advisory councils: Compliance Monitoring and Enforcement (CMEP), Reliability, and Security.
NERC’s LTRA, released in December, identified the Midwest as one of the areas at highest risk of energy shortfalls in the coming decade, largely because of generation retirements “outpacing the new resource additions and not keeping up with resource adequacy criteria.” (See NERC Warns of Ongoing Extreme Weather Risks.)
MRO’s new report echoed this warning, specifying that the new generation being introduced is both “dispersed [and] variable” and “perform much differently than conventional resources.” The consequence of the first issue is that reserve margins for the region’s utilities are becoming tighter; the second means that new modeling assumptions are needed to account for the difference in the new assets’ performance.
These factors were among the eight “most likely and impactful” risks of the 17 that MRO staff identified in the latest risk assessment. Also included in the highest risk category are:
generation unavailability during extreme cold weather;
insider threats;
overhead transmission line ratings;
phishing, malware and ransomware; and
supply chain compromises.
The report’s authors ranked each of these risks as posing a moderate or major risk to bulk power system reliability, and either “possible” or “likely” to occur. MRO said that these risks “will be focus areas for 2023 mitigation action plans … to help improve or develop controls and increase awareness of these risks within MRO.”
The report also adds three risk areas that were not included in last year’s risk assessment: compromise of sensitive information by malicious actors; increased penetration of internet-connected devices on utility systems increasing the risk of remote infiltration; and availability of necessary materials and equipment because of supply chain disruptions, such as those caused by the COVID-19 pandemic. MRO considered each of these risks possible but posing a minor threat to grid reliability.
Six of the 14 risks that were found in both this year’s and the previous year’s assessments changed their ranking in the new report, with most increasing in either impact or likelihood. Bulk power model assumption accuracy and energy reliability planning both increased from “possible” to “likely” because of “limited mitigating actions” since last year.
Line ratings went from a minor to moderate risk because of “uncertainty introduced by FERC Order 881,” which requires the use of ambient-adjusted ratings for short-term transmission requests for all lines impacted by air temperature. (See FERC Denies Rehearing, Clarifies Order 881 on Line Ratings.) An “increasingly challenging job market” caused the “tightening supply of expert labor” risk to increase from “possible” to “likely,” and the “inadequate [inverter-based resources] ride-through capability” decreased in impact but increased in likelihood.
Only one risk dropped in both impact and likelihood: “misoperations due to human errors” was ranked as “possible” but with “negligible” impact, thanks to “guidance provided by an ERO and FERC report on protection system commissioning programs and the limited impact of a single misoperation on the bulk power system.”
“The risks highlighted in this report provide valuable insight to the challenges the industry faces and the policies and regulations that will help define a variety of proposed solutions,” MRO COO Richard Burt said in a press release. “This report and others published by the ERO Enterprise underscore the need for multiple stakeholders to work together in a coordinated and collaborative fashion towards the common goal of reliable and secure power grid.”
