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November 20, 2024

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Monitor Seeks Access to PJM Liaison Committee Meetings

The PJM Independent Market Monitor on Monday filed a complaint to FERC alleging that the RTO is in violation of its tariff by not permitting the Monitor to attend Liaison Committee meetings (EL23-50).

“It is inconsistent with the independence of PJM, the PJM board and the independence of the Market Monitor to exclude the Market Monitor from any stakeholder process,” the IMM argued. “PJM should be directed to permit the Market Monitor to register for and participate in meetings of the Liaison Committee.”

The next LC meeting is scheduled for April 3.

The Monitor was able to attend the committee’s meetings until 2018, when the Members Committee voted to enforce the LC’s charter and restrict participation to RTO members and the Board of Managers, also preventing state regulators and FERC staff from attending. The Monitor quoted the PJM tariff in arguing that it is allowed to participate in stakeholder meetings when it determines its participation to be “appropriate or necessary to perform its functions,” and that charter provisions in violation of the tariff cannot be enforced. (See “Liaison Committee Meeting to be Closed to Nonmembers,” PJM MRC/MC Briefs: Sept. 27, 2018.)

The West Virginia Public Service Commission has also filed a complaint against PJM over its exclusion from LC meetings, arguing that the tariff requires that ex officio, nonvoting members be allowed to observe and that preventing them from doing so is also a violation of nondiscrimination provisions in the Federal Power Act Sections 205 and 206 (EL23-45). (See W. Va. PSC Files Complaint over PJM Meeting Policy.)

After also being excluded from LC meetings in 2018 alongside the Monitor, West Virginia PSC staff attended two MC meetings in September and November 2021 to push for stakeholders to vote on a rule change to permit their attendance. A motion was made during the Nov. 17 meeting to open the LC, but stakeholders narrowly voted to indefinitely table discussion.

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Texas PUC Appeals Court’s Decision on Uri Transactions

Texas regulators last week asked the state’s Supreme Court to overturn a recent appeals court ruling that could force ERCOT to unwind market transactions during the deadly February 2021 winter storm.

Attorneys for the Public Utility Commission said in a filing Thursday that the appeals court’s ruling should be overturned because the orders it issued expired years ago and therefore cannot be voided. They defended the commission’s actions during the storm, saying it made “split-second decisions” necessary to help correct a market failure (23-0231).

The PUC urged the Supreme Court to review the decision, reverse the judgement, and either dismiss the case or rule in the commission’s favor.

The 3rd Court of Appeals on March 17 reversed two PUC orders to keep the market’s wholesale prices at the $9,000/MWh cap during the storm. The court found the commission’s actions “entirely” eliminated competition and were contrary to state law. It remanded the case for “further proceedings consistent” with its ruling. (See Texas Court Reverses PUC’s Uri Market Orders.)

The PUC said the high court should grant its petition because the orders in question expired shortly after the storm, rendering them moot.

“They no longer exist, so the Court of Appeals could neither affirm nor reverse them,” its attorneys argued.

The commission said the appeals court created “harmful precedent” by allowing a statute’s general policy statements to “trump both specific grants of authority and the statute’s overall policy objective.” The court focused solely on market competition, it said, ignoring the PUC’s responsibility to balance the law’s policy objectives.

It said the court’s reasoning calls into question any commission rule that “arguably limits competition” and that its “invented” constraints could hamstring future efforts by the PUC and ERCOT to “ensure ‘the reliability of the regional electrical network.’”

The PUC’s attorneys also argued that the appeals court’s decision has “surprised the electricity world” and introduced “mass uncertainty” into Texas’s electricity markets.

“The markets are already reacting to that uncertainty in ways that are hard to predict,” they wrote.

3 Mitigation Plans Amended

During the PUC’s open meeting last week, it also approved amended voluntary mitigation plans (VMP) for Luminant, NRG Energy (NYSE:NRG) and Calpine that add “clear” guidelines for their non-spin reserve service (NSRS) offering practices in ERCOT’s day-ahead ancillary services market (54739, 54740 and 54741).

Staff earlier this month determined that language in the mitigation plans provided the generators with an “absolute defense” against market abuse allegations related to the service’s submitted offers at prices up to the high systemwide offer cap (HCAP). They estimated non-spin capacity awarded to large suppliers for noncompetitive offers submitted between August 2021 and July 2022 to be between $285 million to $380 million.

The revisions eliminate language that allows offers and/or bids for day-ahead market energy and ancillary services at prices up to and including the HCAP.

Non-spin ancillary service market outcomes are affected by offers from all suppliers, and Luminant, NRG and Calpine are the largest suppliers. ERCOT’s conservative operations posture, instituted in the latter part of 2021, expanded the service’s procurement from an hourly range of 1,175 MW-1,838 MW to 3,654 MW-4,303 MW. That affected the amount of excess supply and increased the likelihood that the grid operator must rely on certain suppliers to meet procurement requirements.

Staff said that when a supplier is frequently pivotal to non-spin’s procurement, it does not forego profit if it submits offers higher than a competitive level. Instead, they said, the supplier would be incented to increase its offers to obtain excess rent and would effectively be able to control the price at which ERCOT must procure ancillary services.

Independent Market Monitor Director Carrie Bivens, who signed off on all three mitigation plans, said they were not effectively mitigating anticompetitive conduct in the non-spin market “given that there is currently no planned end date to ERCOT’s increased non-spin procurement.”

She said the amended mitigation plans will continue to provide the generators with “reasonable safeguards against the potential exercise of market power in the ERCOT markets that may constitute an abuse of market power.”

One of nine bills offered by the Texas Senate earlier this month addresses VMPs. SB2011 would require plans be updated at least once every two years and raises violations from $25,000/day per violation to up to $1 million/day per violation. (See Texas Senate Lays out Changes to ERCOT Market.)

Luminant’s mitigation plan dates back to 2019, NRG’s to 2012 (it was first amended in 2014), and Calpine’s to 2013.

The PUC did not assess any financial penalties.

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New Governor Seeks Shift in Nevada Energy Policy

Nevada Gov. Joe Lombardo on Monday announced an executive order outlining energy policies for his administration, including the state’s “advancement of energy independence.”

Nevada should develop a diverse energy supply portfolio, the order states, with a focus on affordability, reliability and sustainability. In addition to solar, wind, geothermal, hydropower, hydrogen and energy storage, Lombardo envisions a role for natural gas for electric generation and use in homes and businesses.

“The state’s energy policies shall ensure all consumers and businesses continue to have diverse energy options available to them in their homes and businesses, including electric and natural gas service, energy efficiency and renewable energy resources,” the executive order states.

Lombardo, a Republican who last year narrowly defeated incumbent Democratic Gov. Steve Sisolak, who championed clean energy policies, wants enough electric generation developed in the state “to mitigate the risk of energy markets not having sufficient electric energy supplies during peak usage periods.”

At the same time, Nevada should develop transmission and energy infrastructure to make the state a regional leader in exporting its solar, wind and geothermal energy — and to import resources as needed.

Lombardo said the state should keep exploring participation in an organized Western energy market “when such a market furthers Nevada’s objectives of reliability, affordability and sustainability.”

Lombardo wants to promote energy innovation through partnership with universities, industries and others in the state. Job creation and economic development are goals of the policies.

The order calls for streamlining the permitting process for energy projects. State agencies should review applications concurrently rather than tackling them sequentially. The governor will advocate for a similar approach at the federal level.

The order also calls for an overhaul of the Nevada Climate Strategy, adopted in 2020, to reflect the new energy policies.

“Governor Lombardo’s energy policy objectives provide a critical framework for the future of energy in Nevada,” Dwayne McClinton, director of the Governor’s Office of Energy, said in a statement.

Lombardo announced McClinton’s appointment last month. Before starting work as the new GOE director on Feb. 20, McClinton was senior legislative policy adviser at Southwest Gas. He also has experience in the renewable energy industry and worked on Lombardo’s transition team.

The Nevada Conservation League said Monday that the executive order’s support for natural gas was “the wrong direction for Nevada.”

Most of the state’s energy now comes from gas, and high gas prices are causing Nevadan’s utility bills to soar, the League said in calling for a focus on clean energy.

“Nevada has steadily made progress in reducing climate pollution and developing a local clean energy economy,” Christi Cabrera-Georgeson, the League’s deputy director, said in a statement. “Gov. Lombardo should lean in on these efforts and not hold Nevada back by relying on expensive out-of-state fossil fuels.”

Lombardo touched on the topic of energy independence during his state-of-the-state address in January.

“California does not have enough electric generation within its own state to meet its electricity needs — and is now relying on the broader Western electric market to import energy,” the governor said in his address.

“With California retiring its units and changing its transmission rules, we have no choice but to reduce our reliance on the market and seek energy independence for all Nevadans,” he added.

In his new executive order, Lombardo sets as a strategic goal “having our utilities secure sufficient energy supply through dedicated in-state energy resources, including both utility-owned and third-party-owned solar, that ensure reliability for Nevadans.”

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FERC Urged to Close ‘Regulatory Gap’ on Tx Costs

State regulators, environmental groups and ratepayers urged FERC last week to control growing transmission costs by increasing oversight of “local” projects, limiting the use of formula rates and other measures. Transmission owners defended their spending and said FERC’s existing oversight processes under Order 890 are sufficient.

FERC solicited the stakeholders’ comments after it held a technical conference on containing transmission costs last October (AD22-8, AD21-15). (See Transmission Owners, RTOs Defend Planning, Cost Control Practices.)

The Illinois Commerce Commission and New Jersey Board of Public Utilities filed joint comments noting that both states have aggressive policies to decarbonize their power systems that will require significant transmission expansion. But that does not mean transmission should be built with little to no scrutiny, which the regulators said has been happening with “supplemental projects” in PJM.

Supplemental projects (called “asset management” projects under Order 890) represented 55% of the cost of transmission entering service from 2017 to 2021, ICC and BPU said. Spending on supplemental projects totaled $13.7 billion in that five-year period, compared to just $7.1 billion in the 19 years between 1998 and 2016.

“The need for new and stronger transmission, weighed against transmission’s rising costs, potential novel technological alternative solutions, and an inability to access underlying data, puts stakeholders — state commissions in particular — in a difficult situation with respect to assessing the efficiency and cost-effectiveness of proposed transmission plans,” the BPU and ICC said. “The majority of regional transmission owner stakeholders lack the resources and information necessary to make such determinations.”

An independent transmission monitor, as initially suggested in FERC’s advanced Notice of Proposed Rulemaking on transmission, could determine how well planning processes are working and determine whether local projects’ needs might be addressed more efficiently through a regionally planned project, the states said.

“We believe a regulatory gap exists,” the Ohio Public Utility Commission’s Federal Energy Advocate told FERC. “Too many transmission projects are not receiving sufficient regulatory scrutiny to ensure regulators and the public that, at least with regard to local (i.e., supplemental) projects, the regional transmission systems are being built in a cost-effective manner.”

States are hampered in overseeing such projects in PJM because even though they are limited to a specific zone, such zones often cross state lines — as do three of the four that make up Ohio. Even if the PUC stepped up its oversight, Ohio ratepayers would still be faced with costs allocated from projects that fall outside its jurisdiction, the advocate said.

The American Public Power Association also called for FERC to address locally planned projects.

“Among other potential problems, the magnitude of investment in locally planned projects suggests that transmission owners in some regions may be directing investment to such projects, with the result that potentially more efficient or cost-effective facilities are not considered,” APPA said.

But the problems vary by region and even between neighboring transmission owners so FERC should be flexible if it moves forward with any rule changes, the public power trade group said.

Advanced Energy United said local projects lead to fewer benefits than the major regional lines that are needed to help decarbonize the power system.

FERC “should aim to ensure more effective oversight of local transmission projects and more efficient regional and interregional transmission planning such that regional projects and/or non-wires alternatives and grid-enhancing technologies are selected over local projects when doing so would increase the benefits of transmission buildout while reducing total transmission costs,” said AEU.

More information sharing about such projects would help ensure that the money is being spent prudently and aid states in assessing such projects, AEU added. Setting up independent transmission monitors could help deal with the information asymmetry by providing independent analysis for all stakeholders, it said.

A joint filing of groups calling themselves the “Electricity Customer Alliance,” included several state consumer advocates from PJM, the Citizens Utility Board of Illinois, Electricity Consumers Resource Counsel, Public Citizen and the R Street Institute.

“Transmission developers have ample access to capital and spend over $20 billion per year on transmission in the United States,” the groups said. “Unfortunately, billions of dollars are misallocated annually, eroding net benefits to consumers and suppressing development of cleaner and lower-cost generation.”

FERC’s regional planning NOPR proposed pulling back on transmission competition by giving utilities the right of first refusal over transmission projects if they team up with another firm. But the groups said that would not bring their dollars out of the local process and into the regional planning process.

The Environmental Defense Fund, Natural Resources Defense Council, Sustainable FERC Project, Sierra Club and other environmental groups filed joint comments saying the current lack of oversight means FERC cannot ensure that transmission rates are just and reasonable.

“The current Order No. 890 requirements are insufficient to ensure a transparent process where stakeholders have a meaningful opportunity to examine system needs, evaluate public utility transmission providers’ proposed solutions, or propose potential solutions that can more effectively address these needs,” the groups said. “In practice, these requirements are treated like suggestions that are neither binding nor sufficiently detailed to elicit proper behavior from public utility transmission providers.”

Independent power producers NRG Energy (NYSE: NRG) and LS Power argued that while spending on transmission has been on the rise, it has not been for the major projects needed to transform the grid. In addition to developing generation, LS is active in competitive transmission development. NRG said the 5.5 million customers of its retail power business have seen their delivery charges rising in recent years.

“By removing the pass-through regulation that has come to characterize formula ratemaking in this field from its application to certain transmission rate base, the commission can return to the basic principles of sound utility regulation while achieving the public policy goals that animate much of its recent transmission rulemaking activities,” NRG and LS said.

They said FERC should put all projects at 100 kV and above into regional planning processes, a position LS Power has had for years.

Formula rates allow transmission owners to put new transmission investment into their ratebase with a presumption that it is just and reasonable. FERC could limit the type of lines that are put into formula rates to those that face competition, or additional regulatory oversight, or could even eliminate the practice altogether, NRG and LS said.

Utilities Say Local Spending is Justified

Formula rates are transparent and offer oversight, along with the benefits of administrative efficiency and allow for timely recovery of costs, said the Edison Electric Institute.

If any regulatory gaps exist, EEI said, the planning processes vary so much by region that FERC should not force universal fixes. Order 890’s rules for supplemental projects already offer sufficient transparency, it said.

The issue of smaller lines taking precedent has often come up in PJM, but Exelon told FERC there is good reason for the recent increase in spending in supplemental projects there.

“During the 2010s, PJM faced historically low load growth and had just experienced a build cycle of natural gas units, which had the effect of moving significant new, low-cost generation closer to load centers, reducing congestion,” Exelon said. “While these factors moderated the need for regional projects, during this period PJM identified, and PJM transmission owners developed, more than $20 billion in regional projects.”

Local projects needed investment in the same period as many lines reached the end of their useful lives and others needed maintenance, said Exelon (NASDAQ:EXC).

FERC should focus on the other changes it has considered — including the shift to forward-looking, scenario-based planning and first-ready/first-served queue processing — because the regulatory changes implied by its request for comments would amount to “experimentation” and might only delay needed investment in transmission, the company said.

American Electric Power (NASDAQ:AEP) agreed with Exelon that age is a major factor in rising transmission spending, saying 27% of its transformers and 10% of its circuit breakers are expected to exceed their life expectancy in the next 10 years.

“This reveals the simple fact that assets, some of which exceed 100 years old, have now reached the end of their useful life and need to be replaced to ensure the continuing reliability and resilience of the system,” AEP said.

AEP joined other transmission owners in questioning whether independent transmission monitors are needed, warning they could delay the transmission buildout without producing any real benefits.

The New York Transmission Owners do not want FERC to impose any national fixes because they could put a wrench in their efforts working with the state and others to implement the Climate Leadership and Community Protection Act that requires the state to have net zero emissions by mid-century. Because NYISO is in a single state, the local projects that have generated controversy in PJM are highly transparent there and regularly updated publicly with NYISO, the transmission owners said.

RTOs Weigh In

ISO-NE told FERC that its states have already asked for some reforms on “asset condition projects,” and its stakeholders should be allowed to work on that process.

Such projects are like PJM’s supplemental lines and generally fall under transmission owners’ responsibilities, but in New England projects above $5 million have to go the ISO’s Planning Advisory Committee.

PJM filed comments saying that FERC has found its supplemental transmission process provides enough transparency to stakeholders and reaffirmed that when the same rules were extended to end-of-life projects.

All stakeholders, including state regulators, can ask questions during its “Attachment M3” process for local planning.

“PJM currently has processes in place pursuant to which a PJM TO or incumbent developer constructing either a [regional] baseline project approved by the PJM Board of Managers or an Attachment M-3 Project provides reports to PJM, which allows PJM to track the project’s scope, schedule and any cost increases,” the RTO said.

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NERC Balks at Expansion of Cyber Rules

WASHINGTON — NERC will not support expanding physical security standards to all bulk power system transmission assets when it files comments with FERC next month, a senior official told the Electric Power Supply Association (EPSA) last week.

FERC’s existing physical security reliability standard (CIP-014-3) requires transmission owners to perform periodic assessments to identify transmission stations and substations whose loss or damage could cause cascading outages.

In December, FERC ordered NERC to report on the effectiveness of the existing standards and determine whether a minimum level of protections should be required for all BPS transmission stations, substations and primary control centers (RD23-2). The commission acted following the Dec. 3 gunfire attack on two Duke Energy (NYSE:DUK) substations in North Carolina, which left 45,000 customers without power for as long as four days. NERC’s response is due in mid-April. (See FERC Orders NERC Review on Physical Security.)

“The easy answer will be apply everything [to] every station … Just protect them,” NERC Senior Vice President Manny Cancel said during a panel discussion at EPSA’s Competitive Power Summit March 21. “That really is not very prudent. It doesn’t make any sense at the end of the day to drive up costs without really buying down risk. So [NERC will propose] a much more risk-based approach [with a] discussion about the sort of no-regrets moves to make. And it’s not just physical protection, right? It could be everything from designing the grid differently. It could be the introduction of renewables and battery storage. It could be a bunch of those.”

Advance Planning Crucial

Cancel’s fellow panelists agreed on the need to balance costs against risks. They said the most cost-effective protections are those planned in advance.

“Bolting it on [afterward] is not the way that we want to do security,” said Mara Winn, deputy director for preparedness, policy and risk analysis for the Department of Energy’s Office of Cybersecurity, Energy Security, and Emergency Response (CESER). “‘Secure by design’ is something that we take very seriously.”

That includes vetting of suppliers. “It is a lot better to know that you’ve done your due diligence, that you … are buying from suppliers that you can trust,” she said.

“You can’t bolt down every system, so you have to pick and choose,” said John J. Rovinski Jr., supervisory special agent in the FBI’s Cyber Division. “Just obstructing the view of things and knowing your architecture is key. … It doesn’t have to be a [large] investment. CISA [the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency] just put out a product on their website last month, specifically talking about hardening power substations, and listed out a number of different things that are not very expensive to do. Just maintaining a fence. Having signage. Making sure there’s no vegetation near those fences offers you better sight lines for your closed-circuit TVs. It’s not very expensive to hire someone to come and trim your bushes back.”

“It can’t be gold-plated. It’s got to be prudent,” said former New Jersey regulator Richard S. Mroz, an adviser to Protect Our Power, an organization that supports efforts to strengthen the grid. “But it is prudent to make these investments … whether it’s in cybersecurity or physical security, because the alternative — the cost of not doing it — is worse.”

‘Copycats’

Cancel is also CEO of the Electricity Information Sharing and Analysis Center (E-ISAC), which saw a spike in physical security incidents in the presidential election year of 2020 and in the mid-term election year of 2022. Most incidents involved petty thefts or vandalism, and only 3% of such incidents resulted in impacts to the grid, he said.

Although small groups of neo-Nazi and white supremacist sympathizers have been accused in planned attacks on grid assets, there is no evidence of central planning of such attacks, Cancel and Rovinski said. (See Feds Charge Two in Alleged Conspiracy to Attack BGE Grid.)

In most incidents, Cancel said, “we don’t know a lot about attribution, because, as you know, there hasn’t been many apprehensions.”

But, he added, “When you look at all these extremist groups, or groups that are driven by a particular ideology, it is a consistent arrow in their quiver: That is attacking critical infrastructure, whether it’s electricity or some other critical infrastructure sector. That’s part of their plan.”

As a result, Cancel said, the E-ISAC’s seventh GridEx exercise on Nov. 14-15 will “have a big focus on physical security.”

“The grid itself is a natural target,” said Rovinski, “just because it’s visible, a kind of community service that is locally available — you don’t have to travel far.

“The increase in attacks increases the chatter among the groups who look at the news coverage, because media coverage, obviously, invites copycats,” he added. “They’ve seen power being taken down for 60,000 people. [They think] ‘Oh, that creates an attack that gets our message out, that puts us to the forefront.’”

Transatlantic Cooperation

The panelists also agreed that the U.S. has improved cooperation with its European allies in response to fears that Russia might launch cyberattacks to dissuade them from coming to the aid of Ukraine.  

“As far back as probably October of 2021, before the invasion actually occurred, we were getting briefings from our government partners both at CISA and at DOE,” said Cancel.

“We had gotten the sector together to say, look … this threat is real, here are the potential things that could happen [and] made everybody revisit what happened with Ukraine in 2015 and 2016, where Russia actually did disrupt electricity infrastructure there.”

CISA and DOE warned of the need to monitor for malicious software called Pipedream with the ability to disrupt critical infrastructure.

“We came together in unity,” Winn said of the U.S. and its allies. “I think that’s a fantastic outcome of a challenging situation.”

Now, she said, the question is, “What do we need to do to sustain efforts to make sure that we don’t lose all of that engagement? To make sure that … the partnership on analyzing and understanding threats continue.”

Cancel said officials also are focused on the threat from China, which he said has “very sophisticated capabilities that are similar — and in some cases may exceed — [Russia].

“We continue to see attempts to survey networks here in the United States. And what the Chinese are very good at doing is looking for vulnerabilities; looking for holes in networks, so they can get in and introduce malware or just, you know, poke around and see what they can steal. It’s very focused on espionage surveillance.”

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Regulators Boost Incentive for NJ Floating Solar Project

New Jersey’s Board of Public Utilities (BPU) has increased its incentive to an 8.9 MW floating solar project in Millburn, which the agency says is the largest in the nation.

But the regulator also said the award does not set a precedent for future projects developed on water, which some analysts see as a growth sector for the solar industry.

The BPU agreed to award an incentive of $115.52/MWh to the project in the agency’s now-closed Transition Incentive program, which floats 16,510 solar panels in a reservoir at the American Water Canoe Brook Water Treatment Plant about 10 miles from Newark. The agency agreed to increase the incentive from the original rate of $91.2/MWh, the program’s general rate for net-metered residential and grid-supply ground-mounted projects.

The award concluded a more than two-year negotiation with the reservoir owner, New Jersey American Water, which argued the project should be eligible for an incentive at the top end of the program’s incentive scale — $152/MWh — because the floating array met the program’s “preferred siting” criteria for projects that harness new and innovative technology.

At its Feb. 17 meeting, the BPU approved an order that acknowledged that water-based solar arrays are a “potentially positive development in renewable energy technology” and use “novel technology.”

However, the order added, the award would not apply to future floating solar projects, in large part because the Transition Incentive program was shut down in July 2021 and replaced with the Successor Solar Incentive (SuSI) Program.

Robert Pohlman, vice president of NJR Clean Energy Ventures (CEV), which now owns the Millburn project and partnered with the developer early on, said the BPU’s decision to increase the incentive above other types of solar initiatives shows the agency’s support for the project and the merits of siting solar panels on water.

The panels typically sit on a floating platform kept in place by cables connected to the bottom of a reservoir, lake or other body of water.

“It’s a beneficial use of property and locations and space that would otherwise not be used to generate renewable energy,” he said. “Any time we can leverage sites like this, we are interested in it.”

Completed in December, the project is fully operational and provides most of the electricity needed to run the treatment plant, he said.

Global Potential 

The award comes as the concept of floating solar panels on bodies of water — sometimes called floatovoltaics — got a boost from a new study published in March that concluded that floating solar projects on reservoirs present a “huge potential” for generating clean energy worldwide.

Researchers from Sweden, China, Switzerland, Thailand and the U.S. studied databases of reservoirs worldwide and concluded that more than 114,000 of them could be used, potentially generating 9,434 TWh a year. That could help 6,256 communities become self-sufficient, according to the study, which said the number of floating solar projects is accelerating and could reach 4.8 GW worldwide by 2026. In addition, the presence of the panels reduces evaporation, conserving water, the study said.

“Floating photovoltaic (FPV) systems on reservoirs are advantageous over traditional ground-mounted solar systems in terms of land conservation, efficiency improvement and water loss reduction,” the study concluded.

A 2019 National Renewable Energy Laboratory (NREL) report, which described itself as the first assessment of floating solar potential in the U.S., said that with 24,419 man-made water bodies in the country, floating solar could “produce almost 10% of current national generation.” A side benefit, the report concluded, is that many of the water bodies are in areas where electricity prices are high and land is expensive, making land-based solar development difficult.

New Jersey has four floating solar projects, including the newly approved Canoe Brook project, totaling about 18 MW, according to the BPU. A small, 112 kw project was developed at another reservoir at the American Water Canoe Brook Water Treatment Plant and a 3.3 MW project sits on a sand and gravel pit in Jackson.

The 8.9 MW project in Millburn will be the largest floating solar project in the country, and the state now has “more floating solar capacity than the rest of North America combined,” said BPU spokesperson Peter Peretzman.

“Installing this expanding technology on bodies of water avoids use of agricultural and open land and can be an important component in meeting the state’s clean energy goals,” he said.

Higher Cost, Smaller Footprint

Solar Renewable Energy LLC (SRE), of Mechanicsburg, Pa., the developer of the Millburn floating solar project, also assembled a 4.4 MW array on a retention pond in Sayreville, New Jersey in 2020. The two projects are now owned by CEV, the renewable energy subsidiary of New Jersey Resources (NYSE: NJR).

With more than 12,700 solar panels, the Sayreville project covers about 12 acres of the 71-acre pond, and sells the electricity to the Borough of Sayreville, providing all the energy needed to run the borough water treatment plant, according to a release by CEV.

A letter submitted to the BPU by Douglas Berry, CEO of Solar Renewable Partners, and two other companies involved in the Millburn project, said the Sayreville project showed the “technology and siting advantages [that] floating solar provides versus traditional ground mount system,” and so the similarly designed Millburn project deserved the top incentive of $152/MWh.

The Sayreville project cost 48% more to develop than “traditional” ground-mount systems, the letter said, arguing that floating solar projects in general should be granted the “preferred siting” incentive rate. Other project supporters say the project footprint is “approximately 25% smaller than that of a comparable ground mount array,” representing a more productive use of land, according to the BPU order that set the initial incentive level of the Millburn project at $91.20/MWh and allowed the developer to petition for an increase.

CEV claims that the Millburn project will be the largest floating solar project in the U.S., a description it previously used for the Sayreville project. Whether that is true is difficult to tell; the Solar Energy Industries Association (SEIA) said it doesn’t track floating solar development.

The Millburn project will provide about 95% of the power needed to run the treatment facility. In arguing for the top-end incentive, New Jersey American Water said that putting solar on water preserves open space and farmland “while simultaneously improving the health of the water body by providing shade that reduces evaporation and algae growth,” according to the order.

Pohlman said floating solar projects also improve the efficiency of solar panels.

“The function of the water being close to the panels does have a cooling effect and allows the projects to operate more efficiently,” he said. “The water being there cools the panels down, and they work more efficiently when they’re cooler. If the panels get too hot, they’re not operating at their highest efficiency.”

Asked if the company is looking to acquire any other floating solar projects, Pohlman said he did not want to discuss the company’s pipeline but said their ownership of the two existing projects has been positive and a learning experience.

“We are seeing more opportunities of this type, and you’re starting to see them pop up around the country,” he said. “You are definitely starting to see the industry look at it and take a much harder look than they have in the past. These projects are testaments to that.”

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FERC Approves Greenlink Nevada Incentives

FERC last week approved a package of transmission rate incentives for NV Energy’s $2.5 billion Greenlink Nevada project (EL22-73).

The approved package includes the abandoned plant incentive, the regulatory asset incentive and the construction work in progress (CWIP) incentive, all of which are intended to encourage investment in transmission infrastructure.

Greenlink Nevada will consist of two cross-state transmission lines that, together with the existing One Nevada line, will form a transmission triangle around the state. Greenlink West, along the west side of the state, will be a 525-kV line from Las Vegas to Yerington. In Northern Nevada, Greenlink North will connect Ely to Yerington via a 525-kV line.

The expected in-service dates are December 2026 for Greenlink West and December 2028 for Greenlink North.

NV Energy said Greenlink will improve reliability and provide access to renewable energy zones in the state. It will also encourage regional transmission expansion and facilitate Western energy market development, the company said in its petition seeking the incentives, filed in June.

But as NV Energy’s largest-ever transmission investment, “Greenlink Nevada presents significant financial and regulatory risks and challenges,” the petition said.

Under the abandoned plant incentive, NV Energy can apply to recover costs if it abandons the Greenlink project because of factors outside of its control. The Public Utilities Commission of Nevada has approved the project, but it still needs additional approvals at the federal, state and local levels, the company noted.

“NV Energy has demonstrated that Greenlink Nevada faces certain regulatory, environmental and siting risks that are beyond NV Energy’s control and that could lead to the project’s abandonment,” the commission said in granting the incentive. “Approval of the abandoned plant incentive will address those risks.”

The regulatory asset incentive will allow NV Energy to recover costs that it incurs before Greenlink Nevada goes into operation. The commission also granted the utility’s request to include 100% of the CWIP for the Greenlink project in its rate base.

NV Energy said the incentives will help ease strain on the company’s cash flow and potentially reduce project costs. The CWIP incentive will also reduce the “rate shock” that could occur if the entire project cost was added to rates when Greenlink Nevada goes into service, the company said.

Several parties objected to NV Energy’s incentive request. The Nevada Bureau of Consumer Protection said construction of Greenlink was mandated by Senate Bill 448 of the state’s 2021 legislative session, and therefore incentives aren’t needed to encourage NV Energy to build it.

MGM/Caesars said the incentives are duplicative and would increase costs and risks to customers.

But the commission said the package of incentives had been tailored to address NV Energy’s risks and challenges for Greenlink Nevada. And SB 448 doesn’t require NV Energy to build Greenlink — only to submit a plan for its development, the commission said.

Commissioner Mark Christie supported the incentive package but wrote a concurrence reiterating concerns he has expressed previously about the incentives. (See FERC Approves Transmission Incentives for Dayton Power.)

Under the CWIP incentive, consumers serve as a utility’s de facto lender, Christie said, and with the abandoned plant incentive, consumers become the insurer of last resort.

Christie has called for the commission to revisit the incentives offered to transmission developers.

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Mich. PSC OKs Higher Outage Credits, Stricter Requirements for Restoring Power

Michigan utility customers who suffer lengthy power outages will automatically receive credits of $35 daily instead of having to apply to for a one-time credit of $25 under new rules unanimously approved by the Michigan Public Service Commission Friday (U-20629).

The credits will be effective after 96 hours (four days) during “catastrophic” conditions, defined as a utility having 10% or more of its customers without power; after 48 hours during “gray sky” conditions affecting between 1% and 10% of customers, and after 16 hours during normal conditions.

The order, approved at the March 24 PSC meeting, also reduces the required times for restoring long-duration outages; reduces the amount of time first responders must guard downed wires until they’re relieved by a utility line worker; updates reliability standards to ensure Michigan’s performance indicators match industry guidelines; and establishes annual reporting requirements for rural electric cooperatives and investor-owned utilities.

Also approved Friday was an order directing utilities and cooperatives to improve outage reporting and setting requirements for reporting on their cybersecurity programs (U-20630).

Spokespersons for both of Michigan’s largest utilities, CMS Energy (NYSE: CMS) and DTE Energy (NYSE: DTE), said the companies would comply with the new orders.

DTE’s Peter Ternes said the utility had been anticipating the rules and on its own had instituted a credit for customers following the first major ice storm that hit state residents in February.

CMS Energy’s Brian Wheeler said the company supported the changes. “We remain committed to strengthening our grid in order to reduce the length and number of outages,” Wheeler said.

Three major ice and snow storms that hit Michigan over several weeks in February and early March left almost 1 million customers without power, most of them in DTE and CMS territory. Some customers were without power for more than one week.

Another major wind storm hit the state on March 25, knocking out power to several thousand customers.

The new rules will not affect customers who lost power in the three previous storms.

Under the previous outage rules, a customer had to be without power for at least five days before they could apply for a one-time $25 credit. The new $35 credits will be indexed to the rate of inflation.

PSC Chair Dan Scripps said the increased credit was an improvement but acknowledged it may not wholly restore a customer for the cost of lost food, medicine or other inconveniences. (See PSC Chair Says Michigan Grid ‘Nowhere it Needs to Be’.)

Commissioner Katherine Peretick said the commissioners were grateful Michigan residents came forward at recent public hearings to describe what they had to endure. “We know we have a lot more work to do,” she said.

The PSC also announced it had created two new webpages, one dealing with distribution system reliability metrics (featuring information on state utility outages) and a website helping customers prepare for possible outages.

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PJM Chief: Retirements Need to Slow down

WASHINGTON — PJM needs to slow the pace of generation retirements to avoid reliability problems by the end of the decade, CEO Manu Asthana told the Electric Power Supply Association last week.

In a keynote address to EPSA’s Competitive Power Summit on March 21, Asthana said PJM faces increasing loads from electrification and data center growth and that new supply resources have not kept pace with retirements because of clogged interconnection queues, siting obstacles and supply chain constraints.

“I think the math is pretty straightforward,” Asthana said. “I think we need to add [supply resources] faster … but I also think we need to subtract slower and subtract generation only when the replacement generation is here at scale. I really think that’s critical.”

In February, PJM’s Board of Managers invoked an accelerated stakeholder process to address the potential generation shortfall, which the RTO outlined in a staff white paper.

PJM currently has 190 GW of installed capacity to serve its 150-GW peak load, “a very healthy reserve margin,” Asthana said.

But by 2030, PJM expects its data center load could rise to 10 to 15 GW in addition to increasing loads from electrification of heating and transportation.

The RTO forecasts at least 40 GW of generation is at risk of retirement by 2030. “So … suddenly, that 150-GW/190-GW reserve margin starts to look really not enough by 2030,” Asthana said.

Most of the retirements are expected because of state and federal environmental and climate policies.

“Policy reasons are harder to reverse. It’s not that you can send a market price signal that will necessarily override policy signals,” Asthana said. “It is worth noting, though, that several of our states have worked with us to put reliability offramps in place for their policies.”

New Jersey will allow generators to seek an extension of CO2 compliance deadlines if a unit shutdown would impact grid reliability. Illinois officials will allow generators to seek limited, temporary exceptions to the emissions ceiling in the Climate & Equitable Jobs Act “if they are deemed necessary to maintain the reliability of the Bulk Electric System.”

Asthana said PJM is attempting to solve the challenge by streamlining its interconnection process, fine-tuning capacity accreditations of resources and considering changes to the capacity market.

Having won FERC approval for its revised queue procedures, Asthana said PJM is working “feverishly” to hire additional staff and consultants and automating processes to increase its interconnection throughput. “I’m not sure that’s going to be enough,” he said, citing “supply chain pressure” and siting issues.

Although the RTO has 260 GW of proposed resources in its queue, last year less than 2 GW was added to the system. “When you do the math — when you look at the rate of retirements, you look at the rate of growth, and you add in the current rate of throughput for our queue — we are headed for some trouble. And that trouble is likely to find us later in this decade,” Asthana said.

Increasing Winter Risks

Asthana said the stakeholder process is focused on the capacity market, including modeling the RTO’s increasing reliability risks in winter and whether changes are needed to the Capacity Performance (CP) construct.

The week before, PJM had presented the Resource Adequacy Senior Task Force a preliminary proposal to overhaul its capacity market. The RTO said its proposal would improve modeling, resource accreditation, testing and market power mitigation rules. (See PJM, Stakeholders Present Initial Capacity Market Proposals to RASTF.)

CP, which increased performance bonuses and nonperformance penalties, was initiated in response to widespread outages during the 2014 polar vortex. Yet during the bitter cold over the Christmas weekend last year, one-third of gas-fired generation in the RTO’s Northeast was unable to operate because of inadequate winterization, Asthana said.

“We had actually asked this question of the gas industry after Winter Storm Uri in Texas around our vulnerability in our region to that sort of freeze-off. And I think we and the gas industry believed that actually we were adequately weatherized up in the Northeast. And it turns out, we encountered a condition for which we were not ready,” he said.

PJM expects to issue at least $1 billion in CP penalties over the generation outages. (See PJM Weighs Options for Winter Storm Elliott Follow-up.)

“I think it’s appropriate for us to ask ourselves is that [CP] penalty structure correct [for] the future? Did it achieve what it needed to achieve? Do we need to make modifications to it? And also, I think it’s appropriate to ask, is the risk that capacity suppliers are taking on as a result of their capacity commitment and that capacity penalty structure — are they able to pass that through in their offers?”

Asthana dismissed suggestions that PJM’s challenges require abandoning competitive markets. “I know there are voices out there that are using this opportunity to say, ‘Hey, are markets actually the right tool to do this? And I think that drumbeat is going to just continue, because there are a lot of people that have entrenched positions against markets,” he said.

“I would submit to you [that] every grid operator in the world is struggling with these questions, whether they are markets-based, whether they are not markets-based. And in fact, within PJM, we have vertically integrated utilities; we’ve got restructured utilities; we’ve got a whole mix of participants, who have all benefited from our market structure that we have collectively put in place and nurtured over the last 25 years. And the evidence is strong that there are billions of dollars of efficiency [obtained] through the power of competitive markets. And so, I encourage everyone to remember that as we think about the future and think about designing the changes to our markets. They’re complex, but very, very necessary, and very, very worth it.”

EPSA CEO Todd Snitchler, who led a question-and-answer session after Asthana’s speech, said PJM’s challenges are “a five-day-a-year problem. It’s not a 365-day-a-year problem. But it’s mission-critical when it happens.”

Snitchler noted that PJM’s 13-state footprint includes states such as Maryland and New Jersey, which have adopted aggressive climate policies, and fossil fuel-producing states such as Ohio and Pennsylvania. Does PJM tailor its message based on the audience, he asked?

No, said Asthana, describing the RTO as “the interested truth teller.”

“We’re interested in reliability; we’re interested in helping our states achieve their decarbonization objectives as well, but doing it reliably,” he said. “So we try to say the same thing … regardless of who we’re talking to.

“We don’t have different messages for different audiences. That would not work, because they talk to each other.”

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WECC Report Reviews State of the Western Interconnection

Among the topics covered by WECC’s State of the Interconnection (SOTI) report released Friday, one subject stands out for its immediacy: the impact of extreme natural events on the Western grid.

WECC organizes the annual report to highlight its stakeholder-selected reliability risk priorities, which currently include cybersecurity, natural events, resource adequacy, and the impact of changing resources and customer loads on the bulk power system (BPS).

And while growing cybersecurity risks get play across the NERC-led ERO Enterprise, the SOTI makes clear that climate threats are still paramount in the Western Interconnection.

“Last year, the West experienced extreme weather ranging from heat waves and dry spells to extreme winter storms and atmospheric rivers. The frequency, duration and seasons of extreme events have increased over the last 40 years,” WECC said in the report.

The interconnection last year registered 40 reportable reliability events, according to the SOTI, up from 33 in 2021 and tying 2019. WECC said such events have increased in severity over the past four years, based on NERC’s severity risk index (SRI), which “measures the severity of daily conditions based on the combined impact of load loss, loss of generation and loss of transmission on the BPS,” according to NERC.

Among last year’s events were 10 Level 3 energy emergency alerts (EEA-3), nine of which occurred during a late summer heat wave over Aug. 30 to Sept. 10.

“The average duration of the EEA-3s in 2022 was more than 200 minutes, exceeding the average duration for EEA alerts in previous years by almost double,” the report noted.

Last summer’s heat wave also saw the Western Interconnection set a new electricity demand record of 167,530 MW on Sept. 6, exceeding WECC’s peak forecast of 164,650 MW and smashing the previous record of 162,017 MW set in August 2020. The report notes that 1,000 cities in the West saw temperature records fall during the heat wave, with afternoon highs reaching 15 to 30 degrees above historical averages.

Although not detailed in the SOTI, the West averted even higher demand — and rolling blackouts — last summer through California’s emergency measures, which included heavy use of industrial demand response and last-minute calls for residents to consume less electricity during periods of peak usage. (See California Runs on Fumes but Avoids Blackouts.)

The report notes that 22,581 wildfires burned 3.3 million acres across the West last year, with 31 of those affecting the BPS between January and July, down from 70 such fires in 2021.

“There is no strong correlation between wildfire number or severity and risk to the BPS. This is largely because fire location is the dominant driver of risk to BPS elements,” the report said.

The SOTI also highlighted the impact of drought and long-term aridification on the Western grid, with the latter having severely reduced water levels of the reservoirs behind hydroelectric dams on the Colorado River system, with Lake Powell, impounded by the 1,320-MW Glen Canyon Dam, at its lowest level since being filled in the 1960s.

While a series of atmospheric rivers this past winter have restored the reservoir levels supporting California’s extensive hydroelectric system, WECC offered a cautionary note.

“Despite record precipitation over the last few months, much of the West remains in a state of drought, although conditions have improved compared to a year ago,” the report said.

Dual Peaks

The SOTI addresses Western resource adequacy from the perspective of natural events and the changing resource mix. It notes that, over the last 50 years, the U.S. heat wave season has doubled from 34 to 73 days, and that grid planners are dealing with the dual challenges of higher loads in both summer and winter.

“While the Western Interconnection’s peak demand occurs in the summer, many entities are winter-peaking. As temperatures and extreme weather increase, some of these entities are becoming dual-peaking. This presents resource planning challenges for entities that have historically experienced one predominant peak,” the report said.

WECC pointed to a recent example: Just a year and a half after record-smashing heat in June 2021 produced record loads in the Pacific Northwest, a December 2022 cold front also caused record winter peak demand in the BC Hydro, Alberta Electric System Operator and Western Power Pool areas.

The SOTI pointed to a future Western resource mix that will be much less reliant on coal and nuclear generation by 2032 (with anticipated retirements of 13.4 GW and 1 GW, respectively), and more heavily dependent on solar (31.9 GW of new capacity), wind (9.2 GW) and natural gas (4.7 GW). WECC also projects the region will take on 18.3 GW of new battery storage over that period.

“Variability is a primary driver of resource adequacy challenges, and, based on data provided by entities for WECC’s Western Assessment, variability will increase,” WECC wrote. “Projections for maintaining resource adequacy depend on new resources coming online as planned, with little margin for delay. Factors such as supply chain disruption or siting delays can pose serious risks.”

The report pointed out that WECC and the ERO Enterprise have “focused heavily” on the emerging risks from inverter-based resources (IBRs) such as solar and wind.

“While solar-related IBR events decreased in 2022, battery storage — also inverter-based — is increasing, expanding the potential for increased IBR-related events,” the report stated.

The report also covers transmission-related developments over the past year, including final U.S. Department of the Interior approvals of the Gateway South transmission line across Wyoming, Colorado and Utah; the Ten West Link from Arizona to California; and two segments of the Gateway West project from Wyoming to Idaho.

WECC also points to other projects in the later phases of review or nearing approval, including Boardman-to-Hemingway in the Northwest, Greenlink in Nevada and SunZia in the Southwest.

“While these projects reflect progress, WECC studies show a growing risk associated with transmission availability, particularly regarding growing resource adequacy risks,” the report said.