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August 18, 2022June 14, 2023

Battle Lines Drawn on FERC Tx Planning NOPR

FERC’s proposed overhaul of its transmission planning and cost allocation rules received mostly supportive comments from industry stakeholders, but some criticized its requirements as overly prescriptive and said 20-year planning horizons could lead to speculative and unnecessary projects.

Stakeholders also disagreed sharply over whether the commission should reinstitute a federal right of first refusal (ROFR) for incumbent transmission owners.

More than 180 comments had been filed by utilities, public interest groups, industrial consumers, RTOs and ISOs and state officials by Wednesday’s 5 p.m. ET deadline (RM21-17). Reply comments are due Sept. 19.

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Congestion across regions is often higher than congestion within regions, suggesting interregional transmission could produce economic gains, Lawrence Berkeley National Laboratory found. | Lawrence Berkeley National Laboratory

The Notice of Proposed Rulemaking, approved by the commission April 21 on a 4-1 vote, would direct transmission providers to identify infrastructure needs on a long-term, forward-looking basis and propose a list of benefits on which they would base their selections of proposed projects.

The NOPR said the new rules would help planning entities prepare for the growth of renewables, new sources of demand such as electric vehicles and extreme weather events, expected to increase as climate change worsens. (See FERC Issues 1st Proposal out of Transmission Proceeding.)

As always, numerous commenters urged the commission to allow regional flexibility and not to impede innovations already being pursued.

The ISO/RTO Council (IRC), representing the six FERC-regulated grid operators, said “many” of its members already engage in “long-term planning … or have ongoing initiatives” to develop such procedures. MISO, CAISO, NYISO and SPP employ a 20-year horizon in at least some of their planning processes, while PJM uses 15 years and ISO-NE uses 10 years, the IRC said.

The IRC said the commission was “overly prescriptive” on some issues.

“The proposed rule is very focused on process but needs to provide more clarity on how these processes produce actionable results,” the IRC said. “Without discretion to adapt the scenarios, factors and benefits to regional circumstances, the final rule could end up leading to more conflict, rather than useful transmission planning for needed infrastructure. Instead of prescribing detailed procedures, the IRC believes that the final rule should state high-level, long-term planning principles that transmission planners must consider, and then authorize them to craft their own processes that are tailored to their regional needs.”

ISO-NE cautioned the commission against setting uniform implementation requirements for long-term scenario analyses or “hardwiring these details into the region’s tariff.”

“In ISO’s experience with transmission planning based on scenario analysis, these actions will limit the efficacy of the studies,” it said.

SPP added: “If the commission specifies requirements that are expansive in scope and prescriptive in detail, this could become duplicative with SPP’s current processes and initiatives and place unnecessary burden on the future state of SPP planning.”

20-Year Planning Horizon

Commenters — including Minnesota’s Public Utilities Commission and Department of Commerce, the SPP Market Monitoring Unit and the U.S. Department of Energy — endorsed FERC’s call for a minimum 20-year time horizon for transmission planning, with reassessments and revisions to the scenarios at least every three years.

“Traditional transmission solutions that benefit an entire region can take more than a decade to site, permit, and construct and require planning that is more than a decade into the future. Creating long-term scenarios that are at least 20 years into the future will capture power sector changes that occur during transmission development,” DOE said. “However, for the evaluation period, the department encourages the commission to consider requiring an evaluation of transmission costs and benefits over a minimum of 30 years after in-service dates rather than the 20 years proposed in the NOPR.”

But others, including the Nebraska Power Review Board, said any 20-year horizon should be used only for guidance and not to identify transmission upgrades.

“While there is no crystal ball when it comes to transmission planning for the future, PJM continues to believe a 15-year planning horizon allows for sufficient time to identify, plan, and obtain siting and permitting approval and to construct regional transmission facilities while reducing input assumption risks associated with a 20-year horizon,” the RTO said.

Calpine Hay Road Energy Center 2022-06-29 (RTO Insider LLC) Content.jpg

Calpine Hay Road Energy Center, Wilmington, Del. | © RTO Insider LLC

Industrial Energy Consumers of America, the American Forest & Paper Association, the PJM Industrial Customer Coalition and the Coalition of MISO Transmission Customers said “a 20-year planning horizon for new transmission has not been shown to be just and reasonable.”

NRG Energy (NYSE:NRG) said a 20-year planning horizon should be “only for purely informational purposes and not as a basis to mandatorily allocate investment costs.” It said a 10-year maximum planning horizon was more appropriate when applying involuntary cost allocation.

“While it is true that transmission development takes time and thus can be served by a longer view forward, it is also true that identifying a transmission project solution up to 20 years in the future could prove to be problematically speculative,” said the Electric Power Supply Association (EPSA). “A longer view could also lock in a specific approach to the detriment of any other solution that could be developed on a more timely basis or close the door to options for a transmission project that does not reach the final phase of development, which is all the more likely decades out. This could also prove to be short-sighted based on the pace of technological change.”

WIRES, which represents transmission providers and developers, said FERC should allow variances from the 20-year requirement “in order to account for regional differences or circumstances that would render such a timeline inappropriate.”

Non-profit GridLab said the NOPR “conflates the planning horizon with the time horizon over which benefits and costs are calculated in benefit-cost analysis (BCA).”

“FERC should clarify the distinction between the two … while maintaining requirements for a 20-year planning horizon and a 20-year period for BCA. The main benefit of a longer planning horizon will likely be capturing changes in transmission value (benefits) over a longer time horizon, which assumes that the value of regional transmission will look very different in the 2030s than it does today. There is indeed evidence that this will be the case, though some of the forces driving change in regional transmission value will increase value (e.g., growth in wind and solar generation, increased risk of extreme events), while others will decrease it (lower cost energy storage, growth in distributed energy resources). The balance can only be determined through rigorous planning and risk assessment.”

Grid-enhancing Technologies

FERC’s support for grid-enhancing technologies received wide support, but the Los Angeles Department of Water and Power (LADWP) said the commission’s singling out of technologies such as dynamic line ratings (DLRs) and advanced power flow control devices (APFC) “seems inappropriate.”

“Transmission providers should have the range of available technologies for evaluation of solutions to meet economic, reliability and security needs in their respective regions,” LADWP said. “A rule that specifically calls out certain technologies as solutions is in danger of being biased, prescriptive and incomplete.”

ISO-NE said FERC should not mandate use of DLRs in lieu of transmission. “This technology cannot substitute for transmission facilities needed to solve system needs,” it said.

Potomac Economics, which performs market monitoring for MISO, NYISO, ISO-NE and ERCOT, said the commission should also require transmission providers to consider transmission switching and network optimization in addition to DLR and APFC. “Like GETs, network optimization can allow a transmission operator to circumvent a limiting transmission facility and substantially mitigate the associated congestion. In this case, investing millions in upgrading such a facility could prove wasteful and inefficient,” it said.

The Working for Advanced Transmission Technologies (WATT) Coalition, a trade group supporting GETs deployment, asked the commission to be more prescriptive, saying it should “specifically require evaluation of APFC for thermal overloads that fall within 50% of the line rating” and for network upgrades for new loads.

Right of First Refusal

There was also no consensus on the commission’s proposal to allow incumbent transmission owners a federal ROFR on regional projects on the condition that they partner with an unaffiliated company with a “meaningful level of participation and investment” in the project. (See ANALYSIS: FERC Giving up on Transmission Competition?)

Among those opposing the proposal were Electricity Consumers Resource Council, which represents large industrial consumers, and EPSA.

“Rather than less independence and accountability, there must be more independence and accountability in regional transmission planning processes to ensure that all options are offered and assessed to meet expected cost and time parameters pursuant to the planning process,” EPSA said.

“Because competition serves to discipline costs, allowing the incumbent transmission utility to exercise a ROFR, even if done in partnership with another entity, could expose load to higher costs,” said the Pennsylvania Public Utility Commission. “To the extent that FERC determines that the elimination of the ROFR by Order No. 1000 resulted in transmission providers focusing on local projects rather than regional projects, the solution is not to appease incumbent transmission owners’ reluctance to engage in competition from nonincumbent transmission developers, by restoring the ROFR. … Such a mechanism clearly grants preferential treatment to the incumbent transmission providers and discriminates against competitive transmission developers, in violation of the principle of an ‘open’ transmission planning process, as articulated in Order No. 890.”

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FERC approved the transmission planning NOPR in April. | © RTO Insider LLC

NRG said FERC should withdraw the proposal “and instead eliminate formula ratemaking and other aspects to its regulatory scheme that have caused transmission developers to avoid regional projects.”

Transmission owners and the Edison Electric Institute expressed support for a renewed ROFR.

“Although in some instances, the lack of a ROFR may have arguably increased the number of innovative and/or cost-effective transmission options for consideration, it has also caused delays and limited opportunities for dialogue between transmission developers, market participants and RTOs/ISOs, in addition to not delivering regional transmission projects under the time frames necessary to meet increasingly aggressive climate targets,” WIRES said.

NEPOOL said it does not have a formal position on the conditional ROFR but noted it has previously advocated for competitive processes for transmission development. “To the extent the final rule provides for a conditional ROFR, the commission should maximize the opportunities and requirements for competitive processes to be used within that construct,” NEPOOL said. “This objective could be achieved potentially through guidelines for the criteria to be used in establishing joint ownership and development of regional transmission facilities.”

The Minnesota agencies noted that the state’s legislature has backed a state ROFR and said FERC’s joint ownership model “would create additional complexity but is not likely to provide the anticipated innovation and cost-control benefits.” (See Courts Uphold Minn. ROFR, MISO Cost Allocation.)

“Continuing to clearly align the responsibility to construct, own and maintain the high-voltage transmission system in our state with the related decision-making authority that has been given to the responsible utilities remains the best ownership model, at least for now,” they said.

States’ Roles

State regulators and others urged FERC to let states take a central role in planning.

ISO-NE noted that the New England States Committee on Electricity’s role in determining the range of scenarios to be plugged into the grid operators’ studies. Therefore, ISO-NE said, “the states should be responsible for determining whether to move forward with transmission and the associated cost allocation method, with the ISO playing a supporting, technical role.”

FERC should “explicitly authorize or allow for … greater state involvement in all aspects of policy-based transmission planning — not just the criteria for selecting and methodology for allocating costs of long-term transmission facilities,” ISO-NE said.

“FERC should reframe long-term regional transmission planning as an informational process with no attendant project selection or construction obligations unless the affected state regulators first support such actions consistent with their regulation of the public utilities subject to their respective jurisdictions,” said the Alabama Public Service Commission.

The National Association of State Energy Officials praised FERC’s creation of the Joint Federal-State Task Force on Electric Transmission as a “welcome advancement of federal-state coordination.”

But it said “FERC’s engagement on these issues needs to include additional state agencies, such as state energy offices.”

August 18, 2022June 14, 2023

NJ BPU Approves Report on Costs of Energy Master Plan

A study released Wednesday by the New Jersey Board of Public Utilities of the ratepayer impact from the state’s ambitious Energy Master Plan concluded that clean energy-conscious residents could see a 16% cost reduction under the plan.

But one board members immediately rejected the report, saying it ignored key costs.

The report, by The Brattle Group, sought to address the long-running concern from business groups, Republicans and others that the state had never calculated the cost of the state pursuing an aggressive set of climate change policies outlined in Democrat Gov. Phil Murphy’s 2019 Energy Master Plan.

Brattle quantified the total energy cost in 2030 for average customers, compared to the cost in 2020, and then assessed the 2030 ratepayer cost in various scenarios. They included the cost to ratepayers who adopted no energy efficiency or clean energy measures, those who adopted some measures — such as switching from a gasoline-powered vehicle to an electric vehicle — and those who embraced all available clean energy initiatives.

BPU President Joseph Fiordaliso | New Jersey Board of Public Utilities

The report found that the average non-low-income residential customer spent approximately $4,800/year in 2020 for electricity and natural gas bills and fuel costs for driving a non-electric car. Without any changes to their energy use, that figure would rise 16.7% to about $5,600 in 2030. About half the increase would be from the cost of the state adopting clean energy measures and the other half from inflation, the report concluded.

But the same customer in 2030 would save an equivalent amount if the they drove an EV, electrified their home and adopted energy-efficiency measures, the study concluded.

“The key here is energy efficiency,” BPU President Joseph Fiordaliso said at the board’s meeting Wednesday, shortly before it voted 3-1 to accept the report. ”The report we’re accepting today demonstrates that energy costs will be reduced for those ratepayers who embrace energy efficiency and electrify their homes and vehicles.”

Commissioner Zenon Christodoulou, who only joined the board Monday, did not vote on the report, nor on any other items at the meeting, saying he still needed time to become fully informed of the issues.

Calculating Costs

BPU Commissioner Dianne Solomon | New Jersey Board of Public Utilities

Commissioner Dianne Solomon voted against accepting the report, saying it was unusable as an aid to drafting policy.

“After reviewing the extensive stakeholder comments on the rate impact study, it is clear that there is agreement on all sides that the impact study missed the mark,” she said at the meeting. “No one should contemplate using this study to inform policy decisions on future BPU and utility programs.”

Solomon said the report “fails to provide to us as commissioners or the ratepayers we serve with the information that this report was supposed to give.” Specifically, it ignores some key factors that will contribute to consumer costs under the state’s clean energy strategies, such as capital costs.

Solomon’s concerns echoed those of business groups at a March 29 public hearing at which Brattle officials outlined their proposed framework for the study. The Chamber of Commerce of Southern New Jersey, for example, argued at the meeting that the report would not consider the capital costs needed to electrify a property.

At the same hearing, environmentalists argued that the report would exclude an estimation of benefits of clean energy, such as the reduced health care costs and the repair costs avoided because bouts of extreme weather would be less serious if carbon emissions were cut. (See Brattle Study of NJ Energy Master Plan Cost Under Scrutiny.)

Future Study

At a press conference after the meeting Wednesday, BPU staff defended the report, saying the board had from the start said it would focus only on the ratepayer impact.

BPU Chief Economist Ben Witherell presenting the Brattle Group report | New Jersey Board of Public Utilities

“We agree that there needs to be additional analysis on the capital costs,” said Abraham Silverman, chief counsel for the BPU. “But you need to have a good understanding of what the benefits are before you can treat the capital costs appropriately.

“For example, if you’re trying to calculate a return on investment … you need to know both the capital costs, and you need to know the benefits. So this is the first step in this process. We have identified now what are the savings associated with the investment.”

BPU Chief Economist Ben Witherell, who presented the report at the meeting, said the board would be looking at capital costs in the future. But the first step is what “most stakeholders were interested in, which was: what are the ratepayers going to be paying for their monthly energy bills to support these policies and programs.”

Low-income Ratepayers

The Energy Master Plan calls for the state to reach 100% clean energy by 2050, mainly by improving energy efficiency and shifting to clean energy generation, mainly wind and solar. It includes a goal of developing generate 7.5 GW of offshore wind power by 2035, with about half that to be generated by three projects so far approved in two solicitations. Another three solicitations are expected, with the first to take place early next year.

The state also has sought to position itself as an offshore wind industry hub, committing $500 million to $550 million to the creation of the New Jersey Wind Port, a logistics and manufacturing hub in South Jersey, and seeking to set up a “flagship” research and development center, both of which would serve not only New Jersey’s industry but also those of neighboring states.

It has also created several programs to incentivize the purchase of EVs, trucks and buses, and to stimulate the installation of electric chargers across the state.

Eric Miller, New Jersey energy policy director for the Natural Resources Defense Council, welcomed the report and said the limitations of its scope were not important.

“Overall, we think that’s a really positive report,” he said. “It’s good to see confirmed that customers who participate in the clean energy transition, whether it’s using an electric vehicle, participating in energy efficiency programs or electrifying their space and water eating, stand to see really big benefits by doing so.”

One especially encouraging element of the report is its conclusion that an aggressive escalation in the state’s approach to carbon emissions reduction would only increase the cost to ratepayers slightly. The report found that if the state shifted from the Energy Master Plan goal of reaching 100% clean energy by 2050, to an “ambitious pathway” of reaching that goal by 2035, the additional annual energy cost for the typical ratepayer would be only about 2% higher.

Miller also cited as important the report’s conclusion that the state should prepare to step up its incentive programs to include low-income residents.

The report found that a low-income resident — one with an annual income of $35,000 — would spend 7.3 to 10.8% of their salary on energy in 2020, rising to 9 to 12.5% in 2030 if they did not embrace relatively expensive energy-efficiency and clean energy methods.

“This implies that energy assistance programs targeting low-income customers may be necessary to help with upfront costs of electrification and energy-efficiency improvements,” the report says. “These programs may range from providing rebate assistance for the purchase of efficient appliances and electric vehicles, to on-bill financing for income-qualifying customers to be able to undertake projects with high initial capital cost requirements.”

August 18, 2022December 13, 2023

NERC FAC Approves Final 2023 ERO Budgets

VANCOUVER, Canada — At its quarterly meeting on Wednesday, NERC’s Finance and Audit Committee (FAC) approved the final business plans and budgets for NERC and the regional entities. With the FAC’s approval, the budgets will now go to NERC’s Board of Trustees for approval at its meeting on Thursday.

The final budgets are largely the same as the drafts that NERC unveiled in May after what board members on Wednesday called “the most comprehensive budget process” to date at the ERO. (See NERC Plans Big Budget Hike for 2023.) Only NERC and WECC’s final figures differed from those provided in the original versions. NERC’s overall projected budget now stands at $101 million, up from $100.8 million in the draft because of higher operating expenses. WECC’s final budget is up from $31.7 million to $31.8 million because of lower projected savings in some categories.

NERC posted the drafts for comment on its website. The organization received five comment submissions from Electricity Canada, Ontario’s Independent Electricity System Operator, the ISO/RTO Council’s Standards Review Committee, the National Rural Electric Cooperative Association, and other industry organizations. The ERO’s responses to the comments were incorporated into the final versions.

Comments from stakeholders followed three major themes, Andy Sharp, NERC’s vice president and CFO, said at the FAC meeting.

First, stakeholders encouraged the ERO to continue improving the development process for the business plans and budgets through “metrics that support budget assumptions and demonstrate effectiveness.” Sharp said the FAC is committed to “engaging and collaborating … for ideas” on effective metrics.

The total ERO Enterprise budget, including the regional entities and WIRAB, is set to rise to $250.1 million in 2023, a 10.1% increase over the 2022 budget. | NERC

Stakeholders also sought more collaboration in technology and cybersecurity investments, calling for increased transparency around investments like the ERO’s Align software tool and Secure Evidence Locker, and alignment between these investments and reliability metrics.

The third major theme concerned reducing the need for budget and assessment increases through improved efficiencies, reflecting concern about the economic pressures on the industry. (See ERO Warns Inflation, Cyber Investments to Keep Boosting Budgets.) Stakeholders’ suggestions in this area included using contractors instead of full-time equivalents, reassessing annual salary increases, and increasing use of virtual meetings, which have proven to reduce travel and related costs.

Sharp acknowledged the suggestions, promising that the ERO will seek to reduce burdens on the industry.

He also reminded listeners that some of the advanced projects that NERC is working on require a high level of expertise.

“We do continue to want to leverage subject matter experts in the industry, but we also want to remain sensitive to the level of demand we’re placing on you, especially in these scarce or high-demand resource areas, [and] reducing duplication with other organizations,” Sharp said.

Brian Evans-Mongeon, president of Utility Services, said that while he was happy with the ERO Enterprise’s willingness to incorporate industry feedback into its budget process, staff should also keep in mind the burdens placed on smaller organizations that lack the resources of larger companies.

“We very much appreciate the … openness and the collaboration, but we just want to make sure that that collaboration comes forward so that we can all meet these priorities in the most cost-effective way, because it’s going to require effort across the board,” Evans-Mongeon said. “And that means support from the smaller organizations as well, and they’re going to have to figure out how to match this.”

August 18, 2022

MISO Rejects Call for Penalty-free Queue Exits

MISO is resisting clean-energy developers’ calls to allow penalty-free generator interconnection queue withdrawals for certain projects bogged down by SPP’s affected system studies.

The grid operator contends that respite for some projects is unnecessary because it already has provisions to extend commercial operation dates, and it offers chances at penalty-free withdrawals.

“Interconnection customers are already afforded a three-year grace period from the documented [commercial operation date] to bring a resource commercial,” Ryan Westphal, Interconnection Process Working Group liaison, told stakeholders Monday during an IPWG teleconference.

Westphal said MISO will also offer penalty-free exit after projects receive their affected system study results. However, projects that already have signed a generator interconnection agreement with MISO cannot back out without risking paid per-megawatt milestone fees.

In June, Clean Grid Alliance asked the RTO to consider penalty-free withdrawals or longer extensions for advanced-stage interconnection projects already in limbo while waiting on potentially expensive network upgrade costs from SPP’s study results. (See Clean Grid Asks MISO for Penalty-free IC Exits.)

CGA’s Rhonda Peters said upgrades from the affected system studies (AFS) can be staggering and upend once-promising generation projects.

MISO and SPP have rolled out a new, “first ready, first served” queue priority for generation projects that could affect system impact studies on the seams, affected-system studies and cost assignments for network upgrades. The initiative replaces the grid operators’ previous practice of first studying projects with the earliest queue entry dates. That practice didn’t account for a project’s preparedness. (See FERC OKs New Queue Priority for MISO, SPP Seams Studies.)

Batches of projects that entered MISO’s queue in 2018 and 2019 were left out of the new priority. Staff said those project cycles are destined for GIAs before the changes take effect.

Upon hearing CGA’s pitch for free-and-clear withdrawals and extensions, staff expressed concerned that allowing the penalty-free exits could potentially harm lower-queued projects. MISO usually keeps departing interconnection customers’ milestone fees to minimize the costs of network upgrades on lower-queued projects.

Peters argued that the AFS-assigned upgrades can go as high as $100 million, a figure no one initially expects.

“This is such an extreme level of uncertainty, and it’s such a tough situation for these projects to be in,” she said. “This is unprecedented. The level of uncertainty that these projects face is so extreme that no one could have ever predicted it.”

Peters advocated again for a limited waiver for 2018 cycle projects affected by system impact studies.

Staff pointed out that developers can always seek individual waivers of interconnection procedures through FERC.

Invenergy’s Sophia Dossin said generation developers are in a “Russian roulette situation with these massive, project-killing upgrades.”

Other stakeholders argued that SPP keeps delaying its final batches of system impact studies, making affected system upgrades even murkier.

August 18, 2022November 1, 2023

MISO Pledges Review of On-hold Stakeholder Ideas

MISO is refreshing its longstanding “parking lot” of improvement ideas submitted to the grid operator, some of which have been in a holding pattern for the better part of a decade.

The RTO has conducted an internal review on how it handles issues relegated to the parking lot until MISO stakeholder committees deem it’s time to reexamine them. Some stakeholders have said topics they’ve brought forward can languish on the list.

Alison Lane, stakeholder relations lead, said during a Steering Committee teleconference Wednesday that MISO will now refer to inactive recommendations and will commit to their biannual reviews, beginning in 2024.

Staff will go before its large stakeholder committee meetings with a review and cleanup of the suggested improvements, Lane said. MISO will keep the issues that advance its imperative reliability work or that can be handled within the next three years and are supported by “the state of the industry’s” policies and technologies.

MISO currently has 36 issues in the parking lot, some of which are more than seven years old. Staff said some of the proposals have already been addressed with FERC rulemakings, as is the case with Order 2222 and allowing aggregators of distributed resources into the wholesale energy markets.

“We have every intention of being much more diligent on parking lot items” Lane promised earlier this year.

The parking lot designations were used under the RTO’s Integrated Roadmap process, where stakeholder input was used to annually prioritize a list of market tasks and improvements. MISO ended the practice last year. (See MISO Keeps Reduced Schedule for Rest of 2022.)

The grid operator is also encouraging a more standardized method for stakeholders to submit new issues that they think deserve MISO’s attention. After the roadmap process was scrapped, stakeholders said in public meetings they were left wondering how to broach ideas for improvements.

Staff stressed that stakeholders who want their ideas discussed in public meetings should complete its issues submission form. From there, the item is either directly considered by a stakeholder group or, when the assignment is less clear, the Steering Committee determines which stakeholder groups will take up the issues for consideration.

August 18, 2022

California Legislature Asks CAISO to Report on Regionalization

A measure that asks CAISO to report to California lawmakers on Western regionalization efforts and the potential benefits of greater interstate collaboration cleared the State Legislature last week, with some saying it could renew discussions of an RTO developed by the ISO.

“There is considerable potential for additional benefits for California consumers through further regional collaboration,” and the state should “collaborate, coordinate on policy, and share systems and resources with our neighboring Western states when opportunities for mutual benefit exist,” Assembly Concurrent Resolution 188 says.

“The legislature should have current and comprehensive information on the impacts to California of expanding the existing independent system operator into a regional organization that manages wholesale electricity markets, transmission planning and other services across a broader Western region.”

Introduced by Assemblymember Chris Holden and co-authored by 75 lawmakers, ACR 188 passed the Senate and Assembly without opposition on Aug. 8 and 11 respectively. It asks CAISO to produce a report by Feb. 28, 2023, that summarizes recent studies on the impacts of expanded regional cooperation and identifies features that could advance the state’s energy and environmental goals while “reflect[ing] the impact of regionalization on transmission costs and reliability for California ratepayers.”

Transmission and resources needed to fulfill the 100% clean energy goal of 2018’s Senate Bill 100 should be covered, as should mandates by Colorado and Nevada requiring transmission owners to join an RTO by 2030, it said.

CAISO said the request signaled a growing interest in regional efforts.

“We’re encouraged that compiling the many existing studies on this, as well as highlighting the other market efforts in the West, will foster a better understanding of the issues and how we might move forward collaboratively,” Stacey Crowley, CAISO’s vice president of external affairs, said in a statement.

Potential Benefits

In the resolution, lawmakers cited a study published last year that found an RTO covering the entire U.S. portion of the Western Interconnection could save the region $2 billion in annual electricity costs by 2030 and cut carbon dioxide emissions by 191 million metric tons. A group of Western states led the study, financed by the U.S. Department of Energy.

A subsequent study released in July by Advanced Energy Economy (AEE) looked at regional economic effects. It concluded an 11-state Western RTO could generate roughly $19 billion to $79 billion in additional gross regional product by 2030 and could help create 159,000 to 657,000 permanent jobs at an average total compensation, including benefits, of $73,000 a year. (See Study Tallies Economy-wide Benefits of Western RTO.)

AEE said the resolution “kickstarts discussions about California’s role in improving the Western power grid in collaboration with other states in the region.”

“ACR 188 sets the stage for California to engage substantively with its neighbors, and it’s great to see the legislature recognize the importance of regional collaboration when it comes to our energy grid and achieving state goals,” AEE Managing Director Amisha Rai said in a news release.

Prior regionalization efforts involving CAISO fizzled in 2016, 2017 and 2018, as California lawmakers balked at making changes to the ISO’s governance that could open its Board of Governors to out-of-state members. CAISO is a public benefit corporation created by the legislature and led by five gubernatorial appointees from California.

Even as California has been unwilling to share CAISO leadership, many parties in other Western states are unwilling to participate in a California-dominated RTO.

Acknowledging the standoff, the resolution said CAISO’s report should examine “collaboration between states on energy policies to maximize consumer savings while respecting state policy autonomy.”

Western Resource Advocates said the resolution “sends an important signal that regional electric grid collaboration should respect individual states’ autonomy and include governance provisions that allow significant engagement by states across the West.”

Speaking for CAISO, Crowley said, “Perhaps today there’s more general understanding of how a regional market would benefit ratepayers and the overall reliability, while at the same time respecting the policies set by each state in the West.”

Regional Cooperation Efforts

CAISO’s multistate Western Energy Imbalance Market has shown the economic benefits of regional cooperation by securing more than $2 billion in benefits for its members since it began in 2014, the resolution notes. Members from California and other Western states make up WEIM’s Governing Body.

The ISO is engaged in a stakeholder process to expand the real-time WEIM to a day-ahead market with the potential to increase resource exchanges across the West. On Tuesday it posted a revised straw proposal on the extended day-ahead market (EDAM) initiative and has scheduled stakeholder meetings for Aug. 28 and Sept. 7-8. (See CAISO Issues EDAM Straw Proposal for the West.)

“The extended day-ahead market is expected to achieve cost savings through a more efficient day-ahead commitment of generating units, including the displacement of resource commitments within one balancing authority area when more economic resources can be committed in other balancing authority areas instead,” the resolution says.

CAISO is facing competition from other entities that are moving to increase regional planning or form a Western RTO.

SPP has been promoting its Markets+ offering in the Western Interconnection, attracting interest from utilities seeking a range of market services that stop short of a full RTO. (See related story, BPA Commits to Funding Markets+ Development.) It is planning to establish a Western version of its eastern RTO, called RTO West, with Markets+ participants as likely members.

Spanning much of the Western Interconnection, the Western Resource Adequacy Program (WRAP) promises to be another significant player in regionalization efforts. Started by the Northwest Power Pool — which recently changed its name to the Western Power Pool (WPP) to reflect its wider reach — the program is meant to address reliability concerns in the Western Interconnection. It has already attracted participants in an area spanning from British Columbia to Arizona and east to South Dakota.

WPP has not signaled intentions to expand the WRAP’s offerings beyond resource adequacy, but it appears increasingly as a possible platform for incrementally developing a Western RTO that could compete with SPP and CAISO.

August 18, 2022

DOE Opens $45M Challenge on Grid Cybersecurity

The Department of Energy issued a $45 million challenge Wednesday for the development and commercialization of tools and technologies to protect U.S. electric, oil and natural gas production and delivery systems from cyberattacks.

The goal is to build on grid upgrades funded through the Infrastructure Investment and Jobs Act and the recently signed Inflation Reduction Act by integrating “greater cyber defenses into our energy sector,” DOE said in a press release. Up to 15 projects could be funded, with a focus on research, development and demonstration of new cybersecurity technologies, the press release said.

Eligible proposals must apply to electricity generation, transmission, or distribution (including energy management systems and electric vehicles) or oil and natural gas production, refining, storage or distribution.

“As DOE builds out America’s clean energy infrastructure, this funding will provide the tools for a strong, resilient and secure electricity grid that can withstand modern cyberthreats and deliver energy to every pocket of America,” Energy Secretary Jennifer Granholm said.

The $45 million from the DOE Office of Cybersecurity, Energy Security and Emergency Response will be targeted at “tools and technologies that enable energy systems to autonomously recognize a cyberattack, attempt to prevent it and automatically isolate and eradicate it with no disruption to energy delivery,” the press release said.

Other areas of focus for the funding include:

building cybersecurity and resilience into technologies through a “cybersecurity by design” approach, which identifies “key cybersecurity features and risk considerations from the start;”
protecting systems through the broad-scale adoption and standardization of encryption;
developing tools and technologies to detect and prevent ransomware attacks at the hardware, firmware and software levels; and
developing software to serve project owners and operators that can be tested “across a full range of attacks in both testbed and real environments.”

Funding will also be provided for two demonstration projects in which developers will team up with asset owners and operators to field test technologies “purpose built for the operational technology environment, capable of adapting to and surviving a cyberattack and have been made available to the energy sector.”

‘Interoperable, Scalable, Readily Manageable’

Both the Infrastructure Investment and Jobs Act and the Inflation Reduction Act provide funding for grid upgrades and building and transportation electrification that will likely accelerate digitization of the U.S. electricity system, which will make the grid smarter and more efficient while also providing more targets for cyberattacks.

The IIJA’s $7.5 billion in funding for EV chargers is aimed at putting 500,000 chargers along U.S. highways, potentially making them a huge target for cyberattacks. The IRA provides funds to help low-income families buy electric home appliances, again opening millions of points of entry for cyber criminals.

The DOE funding opportunity announcement (FOA) is structured to promote both technical innovation to prevent and mitigate cyberattacks, and commercialization and integration strategies to get the new tools and technologies adopted by utilities, grid operators and other energy stakeholders.

The FOA lays out a two-step structure for applicants: a research and development phase focused on innovation, and a demonstration phase, which requires applicants to provide a plan for commercialization and the buildout of domestic supply chains and jobs.

Individual grants will range from $1.5 million to $3 million, and applicants will be required to supply matching funds equal to 29% of project costs, except for the demonstration projects, where the funding split will be 50% each for DOE and the applicants.

Commercialization plans must include “U.S. manufacturing commitments as well as plans for technology maturation and technology licensing,” the FOA says. “Invention and copyright licensing to commercialize technology” developed under the FOA is also required.

DOE will be looking for “interoperable, scalable, readily manageable advanced tools and technologies [that] are compatible with common methods and best practices,” the FOA says.

Applicants will also have to develop diversity, equity, inclusion and accessibility plans aimed at ensuring benefits and jobs for “underrepresented groups in STEM [science, technology, engineering and math]” and their communities.

Concept papers are due by Sept. 12, with a full application due Dec. 5. Winners will be notified in February and funding awards made in June 2023.

Wednesday’s funding opportunity follows on the DOE’s April announcement of $12 million in awards to six university-led teams researching the use of “anomaly detection, artificial intelligence and machine learning, and physics-based analytics to strengthen the security of next-generation energy systems.” According to the announcement, these next-gen systems “include components placed in substations to detect cyber intrusions more quickly and automatically block access to control functions.”

August 18, 2022November 15, 2023

Andersen to Manufacture Energy-generating Windows

Minnesota-based Andersen Corp. and California startup Ubiquitous Energy have signed an agreement to develop and manufacture windows that double as solar power modules.

The companies pledged windows “without aesthetic compromises”; in other words, visible light will pass through the windows, which, judging by early versions developed entirely by Ubiquitous, will not visibly reveal their photovoltaic abilities.

The two companies announced their agreement the day after President Biden signed the Inflation Reduction Act, which will provide more funding to technologies aimed at fighting climate change with electrification replacing fossil-based technologies.

The breakthrough Ubiquitous claims to have made is based on patented technology pioneered by researchers at Michigan State University and the Massachusetts Institute of Technology. MSU has already installed glass produced by Ubiquitous.

In January, Ubiquitous revealed that Andersen was a leading investor in a $30 million funding round it concluded at the end of 2021, taking the total of investor research and development funding to $70 million.

The company’s technology produces power from ultraviolet and infrared light, allowing visible light to pass through the window. The two companies intend to manufacture the solar glass in the U.S.

“With our patented technology, Ubiquitous Energy has expanded what’s possible in photovoltaic technology. We’ve engineered our solar cells to selectively transmit visible light, what we see, while absorbing and converting invisible ultraviolet and infrared light into electricity,” the company announced on its website. “This makes our technology the first truly transparent solar technology, allowing windows to convert ambient light into useful electricity without impacting aesthetics or performance.”

Ubiquitous in April announced it had demonstrated the technical ability to uniformly coat glass as wide as 1.5 meters, the first step toward its production line target to manufacture high volumes of 1.5-by-3-meter floor-to-ceiling solar windows.

The company also said its technology does not use hazardous materials, but “earth-abundant materials” instead. Its coating technology follows “standard industry coating practices, and its windows will meet ‘Low E thermal performance’ standards,” it said.

Brandon Berg, senior vice president of research and development at Andersen, described the agreement with Ubiquitous as “a powerful opportunity to leverage our industry leadership, product development expertise and manufacturing capabilities.”

Newly elected Ubiquitous CEO Susan Stone said the two companies “have a shared goal of changing the way the world uses solar power and positively impacting the environment in a big way without compromising aesthetics or function.”

August 18, 2022January 31, 2024

Entergy CEO Denault Stepping Down in 2023

Entergy CEO Leo Denault | Entergy

Entergy on Wednesday announced that chairman and CEO Leo Denault will step down early next year after a decade at the utility’s helm.

The Entergy Board of Directors has elected current CFO Drew Marsh to succeed Denault as CEO, effective Nov. 1, in an overlapping transfer of power. Denault will continue to lead the board as chairman until his retirement.

Entergy said the move is part of an “orderly and planned leadership succession process.”

Denault, 62, has spent 23 years with Entergy, becoming an executive vice president and CFO in short order a few years after his arrival. He has served as chairman and CEO since 2013, when he took over for J. Wayne Leonard as Entergy transitioned into MISO membership. Denault and Leonard are Entergy’s only two CEOs in the last 24 years; Leonard, who died in 2018, became CEO in 1998.

In a press release, Entergy’s lead independent director Stuart Levenick said Denault has “strengthened the business and positioned Entergy well for the future.” Levenick also said he’s “confident that Drew will carry the torch and continue serving all of Entergy’s stakeholders well by creating sustainable value today and for future generations.”

Marsh, 50, joined Entergy in 1998, serving in several financial planning and strategy roles before becoming CFO in 2013. Kimberly Fontan will become Entergy’s CFO; she has served as a senior vice president and chief accounting officer since 2019.

“I am both grateful and honored by the confidence the board has placed in me, and I’m honored to follow in my colleague and friend Leo Denault’s footsteps,” Marsh said. “I will uphold Entergy’s values and the strategy that he has instilled in our leadership team.”

Denault said his transition comes at a “logical time,” pointing out that Entergy recently successfully pulled off its “planned, multi-year strategy” to exit the merchant nuclear power business.

Entergy owned six merchant nuclear power plants when Denault began managing the company: FitzPatrick and two Indian Point units in New York; Vermont Yankee in Vermont; Pilgrim in Massachusetts; and Palisades in Michigan. All are now closed except for FitzPatrick, which Exelon now owns.

Entergy said Denault played a critical role during and after Hurricane Katrina’s 2005 destruction, making sure the company’s headquarters remained in New Orleans — where it is the city’s only Fortune 500 company — and guiding Entergy New Orleans through bankruptcy proceedings after it lost nearly all of its customers in the storm’s aftermath.

The utility also praised Denault for spearheading an accelerated goal to reach net-zero emissions by 2050 and “advancing climate resilience initiatives throughout communities in the Entergy region.”

For years, Entergy has had a goal to invest about $1 billion annually in transmission capital projects for economic and system resilience reasons. In June, Entergy committed to a $25 billion, five-year capital plan to ramp up decarbonization efforts and to accelerate reinforcements to its Gulf Coast infrastructure to better protect it against future hurricane strikes. The plan includes adding more renewable energy and burying some distribution lines.

After Hurricane Ida darkened the coastal Louisiana grid for weeks last year, Entergy faced calls from climate change activists to harden its transmission and distribution system and make more investments in renewable energy. (See Entergy Fends Off Calls for Tx, Solar, Microgrid Investment.)

Entergy announced other leadership changes Wednesday.

Chris Bakken, currently executive vice president and chief nuclear officer, was named executive vice president of Entergy infrastructure. Entergy said Bakken will have oversight responsibility for both utility operations and nuclear operations.

Senior Vice President of Nuclear Corporate Services Kimberly Cook-Nelson was appointed executive vice president of nuclear operations and chief nuclear officer. The company said Cook-Nelson will be responsible for operations at Entergy’s four remaining nuclear plants in in Arkansas, Louisiana and Mississippi. She will report to Bakken.

August 18, 2022December 13, 2023

NERC Board of Trustees/MRC Briefs: Aug. 17-18, 2022

Vancouver Hosts Return to In-person Meetings

VANCOUVER, Canada — At the first in-person meetings of NERC’s Board of Trustees and Member Representatives Committee (MRC) since the start of the COVID-19 pandemic, attendees reflected on the changes that the organization has experienced in the years since they last saw each other.

“I think the last time we met in person, Jennifer Sterling was the chair, and then Paul [Choudhury] took over as chair … and now I’ve taken over,” MRC Chair Roy Jones said on Wednesday. “So Paul now has the honor of being the only MRC chair to never hold a meeting in person.”

The meetings, held Wednesday and Thursday, were NERC’s second attempt at returning to in-person gatherings after the second-quarter meetings, intended to be held in D.C., were converted to virtual sessions after an attendee tested positive for COVID-19 at the meeting site. (See “Positive COVID-19 Test Prompts Return to Virtual Sessions,” NERC Board of Trustees/MRC Briefs: May 11-12, 2022.)

Ahead of the third-quarter meetings, NERC put new policies in place to prevent a repeat of the incident and its disruptions to attendees’ travel plans. These rules, requiring isolation and virtual attendance after a positive test, were put into practice when NERC CEO Jim Robb tested positive on-site the day before the MRC meeting. While Robb remained in Vancouver and listened to the events via webcast, Manny Cancel, president of the Electricity Information Sharing and Analysis Center, delivered the President’s Report in his place.

The final meeting of the board and MRC in 2022 is scheduled for Nov. 15-16 in New Orleans. According to the 2023 schedule shared this week, NERC plans to hold its first- and third-quarter meetings in person in California and Canada, respectively. Gatherings for the second and fourth quarter will be held in D.C. and Atlanta, following a hybrid model in which trustees and members meet in person while all other attendees join virtually.

Board Approves ERO Budgets

The board approved relatively few actions at its meeting Thursday. Only the Finance and Audit Committee (FAC) submitted any items for approval, primarily the final business plans and budgets for NERC and the regional entities, approved at its meeting the day before. (See related story, NERC FAC Approves Final 2023 ERO Budgets.) With the board’s approval, the ERO will file the budgets with FERC by Aug. 25.

The FAC also asked trustees to approve an extension of NERC’s $4 million line of credit, which the organization maintains for emergency working capital needs and unforeseen contingencies. NERC has renewed the line annually since 2007; last year the board authorized management to execute the renewal without its approval.

However, the board must still give its assent “if the terms and conditions [of the line of credit] materially change.” In the next renewal period, the interest rate index for the line will change from the London Interbank Offered Rate to the Secure Overnight Financing Rate, which qualifies as a material change. As a result, management decided to take the question of approval back to the FAC and board. The trustees agreed to the change and renewal without objection.

Updates on Standards Projects

Howard Gugel, NERC’s vice president of engineering and standards, updated the board on the progress of some ongoing standards projects. First was Project 2021-07 (Extreme cold weather grid operations, preparedness and coordination), which NERC started last year in response to the mass outages caused by the February 2021 winter storm.

The project has produced two draft standards, EOP-011-3 (Emergency operations) and EOP-012-1 (Extreme cold weather preparedness and operations). Both standards were posted for comment in May; EOP-011-3 passed on the first ballot, but EOP-012-1 failed and was returned to the standard drafting team for revision along with industry comment. Gugel said EOP-011-3 is currently “in a holding pattern until we get EOP-012 across the board.”

Gugel also discussed the ongoing efforts to revise NERC’s Critical Infrastructure Protection (CIP) standards, including the proposed changes to CIP-003-8 (Cybersecurity — security management controls) that are currently out for a formal comment and ballot period that will close on Friday. If the standard passes this ballot — for which Gugel said NERC has “good expectations” — additional revisions are likely to follow based on the work of Project 2016-02 (Modifications to CIP standards), which on Wednesday entered a ballot period that is expected to wrap up by Sept. 21.