Search
`
November 19, 2024

Posted on

AEP, Liberty Utilities Try Again on Kentucky Territory Deal

American Electric Power and Algonquin Power & Utilities subsidiary Liberty Utilities have filed a fresh application with FERC seeking approval of AEP’s Kentucky operations’ sale to Liberty.

This time, the two utilities have added new commitments so the sale won’t raise customer rates (EC23-56).

FERC shot down the sale in December, indicating more consumer protections were needed before the commission could give its blessing.  

The utilities have since added more safeguards, including a five-year freeze on the current return on equity and 55% equity capital structure; a commitment from Liberty to maintain the same credit profile for five years; and a five-year cap on operations and maintenance and administrative costs at the 2022 rate.

AEP and Liberty also pledge to hold wholesale power and transmission customers harmless from any transaction costs for five years following the sale. The proposed transaction’s other aspects remain unchanged.

The utilities are requesting an expedited review of the application and hope to the close the transaction by April 26. If they fail again to gain commission approval by then, termination rights kick in for the parties.

“When taken in total, these commitments will ensure that the transaction has no adverse effect on both Kentucky Power or Kentucky TransCo’s individual rates and the rate for the AEP East zone,” AEP and Liberty said in the filing.

The new sale application continues AEP’s two-year effort to offload its Kentucky operations to Liberty. Late last year, the parties agreed to shave $200 million off the purchase price down to $2.646 billion. (See AEP Accepts Lower Price for Kentucky Operations Sale.)

AEP said the transaction’s approval should bring an economic boost to retail customers in an “economically disadvantaged part of eastern Kentucky.” It cited previously agreed-upon compromises at the Kentucky Public Service that include a $40 million fund to help offset volatile fuel rates for the remainder of the year; a $55 million, three-year rate holiday on collecting a Big Sandy nuclear plant decommissioning rider; a $43.6 million cut in regulatory charges collected from customers for storm costs; and a new Kentucky call center in the Kentucky territory.

“AEP and Liberty are committed to the sale and are requesting FERC’s accelerated review of the application so customers in eastern Kentucky can begin benefiting from the transaction,” AEP CEO Julie Sloat said in a statement.

Sloat said the sale is just one component of AEP’s strategic plan. She said utility leadership remains dedicated to selling AEP’s competitive renewables portfolio and conducting a review of its retail business as part of its equity financing plan and goal for a 6 to 7% long-term growth rate.

Posted on

NARUC Panel Tackles Gas-Electric Coordination

WASHINGTON — Despite making progress after repeated high-profile winter reliability events, the gas and electric industries still have more work to do to coordinate their operations enough to avoid such incidents in the future, experts said at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit Monday.

Winter Storm Uri in February 2021 and Winter Storm Elliot in December 2022 each presented the power and gas sectors with a different set of problems, according to MISO President and COO Clair Moeller.

But Moeller said the events shared a common thread: Those problems were rooted in a continued disconnect between the industries — one stemming from difference in how they operate.

“Electricity is ‘N minus one’ forever,” he said, referring to the power industry’s “N-1” reliability criterion, which holds that the grid must be equipped in a way that it can lose a major resource or transmission line without threatening electricity supply. “Gas is like, ‘You know, pipes don’t fail very often, so maybe it’s not worth those investments.’”

The gas industry has been more focused on the commodity itself rather than ensuring resilient operations because nobody has paid it to provide the latter, he said.

“Just to make it more fun in the planning horizon, we’re asking them to become intermittent resources, the reciprocal of renewables, to fill all those holes, and at the same time, we’re electrifying, taking their base load,” Moeller said. “So, the planning problem here is enormous.”

The differing business models makes it difficult to figure out whom to talk to in order to bridge the differences between the two industries, Moeller said. And even within the gas industry, the pipelines have their own issues, which are different from the local delivery companies and natural gas suppliers.

“There really isn’t a very good place to talk about it except here, which is why I bring it up,” Moeller said. “It’s time; the penetration of renewables is accelerating. We’re relying on gas to be that reciprocal intermittency. But we haven’t told them what that looks like, and we haven’t shown up with a checkbook to make sure that they can do it.”

After experiencing the polar vortex of 2014 and helping its neighbors get through Uri, PJM Senior Vice President of Operations Michael Bryson said he thought his RTO had achieved good coordination with the gas industry.

“I think we found out during Elliot that there were certainly gaps in what we were able to see in terms of availability,” Bryson said.

PJM’s load forecast was off by about 10% as it was not ready for the rapid temperature drop over the Christmas holiday weekend, but it also ran into plenty of outages of gas-fired plants that its operators were unaware of until they tried to dispatch the units, he added.

“We actually had, in fact, during Elliot, what I would consider the golden ticket of capacity performance gas: firm transportation, firm supply, no notice scheduling,” Bryson said. “We had units with that, that were curtailed.”

PJM does not have visibility into the operational issues natural gas suppliers might be running into during extreme weather, and that could be fixed by requiring similar information sharing between the gas and electric industries as the RTO does with its neighboring grid operators, he said.

Post-Uri Reforms in ERCOT

Texas has been working on reforms to its power market since Uri knocked out about 50,000 MW of its generation, plunging the state into blackouts that lasted for five days and causing hundreds of deaths and billions of dollars in damages. They include mandatory winterization standards that can be enforced with fines of $1 million per violation per day, said Public Utility Commission of Texas Commissioner Lori Cobos.

“We’ve also developed a first-in-class, first-in-the-country new firm fuel product to help ensure winter resiliency when fuel availability issues arise,” Cobos added.

The PUC authorized ERCOT to procure up to 3,000 MW for the new firm fuel product, and it signed up 19 power plants, 18 of which can burn fuel oil with storage onsite, while the other has a direct pipeline connection to its own natural gas storage facility. All the generators can provide power for up to 48 hours.

ERCOT used the firm fuel product for the first time during Winter Storm Elliot just before Christmas, calling up eight generators that supplied 950 MW, Cobos said.

While the product provided some guaranteed generation, the PUC still is looking into the 13,000 MW of generation that went offline during Elliot, specifically whether any had weatherization issues, she said.

Gas-fired generation has grown at the expense of coal because it is cleaner, but it cannot be stored. And now the electric industry is relying on the gas industry to meet needs the gas system was never designed for, said Chris Moser, head of competitive markets and policy at NRG Energy (NYSE:NRG).

“The gas system itself is well-built; the electric system itself is well-built. The combination of those two systems, frankly, is brittle,” Moser said. “And it’s the touchpoints in between the two of them, some of them just on a daily basis, where things start to break down.”

The issues are exacerbated during winter storms, when spot prices for natural gas spike to above $100/MMBtu, which leads to generator bids above the price cap in many markets. Uri saw prices reach $1,200/MMBtu on the border of Texas and Oklahoma despite the region’s vast supplies of natural gas, said Moser.

When gas is just $4 or even $10/MMBtu, generators can deal with it, but once prices get into the hundreds that can “sink an entire company,” Moser said.

Posted on

Eversource Still Eyeing Offshore Wind Sale

Eversource’s 2022 earnings were hit by continued uncertainty over its offshore wind portfolio despite record profits, the company said in a call with analysts on Tuesday.

The New England utility is performing a “strategic review” of its 50% stake in the South Fork Wind Farm, Revolution Wind and Sunrise Wind projects, which could lead to a sale of the assets, all of which are still under development.

“While our longer-term total shareholder return compares favorably with our peers, our 2022 return was disappointing,” CEO Joe Nolan said. “We understand that much of that is related to the uncertainty over our offshore wind investments. We expect to resolve that uncertainty in the coming months as our strategic review progresses.”

The company had originally planned to finish the review by the end of 2022 but now says it will be done by the second quarter of the year.

“I’d like to move at a good pace, but this is very complex and … folks need to understand that any buyer of these assets is going to want to do significant due diligence,” Nolan said.

But there is “significant interest in the lease here as well as the projects,” he said.

“We are going to get a fair price for these assets,” he added. In the meantime, work on the projects is moving ahead.

Despite earning a record $1.4 billion last year, an increase of 15% from 2021, the company missed Wall Street estimates, reporting adjusted earnings of $4.05/share for the full year and 92 cents/share for the fourth quarter.

Nolan said that Eversource’s customers should see reductions to their bills soon as mild winter weather has reduced consumption and eased gas prices.

“For most of our electric customers, lower power supply costs will start to be reflected in bills in July,” he said.

Unitil

Unitil, which serves customers in Massachusetts, Maine and New Hampshire, had a strong 2022, beating estimates and earning $41.4 million, up $5.3 million (24 cents/share) from the previous year.

“The earnings growth reflects higher distribution rates, including recoupment associated with the New Hampshire rate cases, partially offset by higher operating expenses,” CFO Robert Hevert said.

Unitil’s adjusted gross margin increased by more than $12 million thanks to higher rates, colder winter weather and customer growth; the company added 425 new customers on the electric side and 855 for gas.

“2022 certainly had its challenges. Ultimately, we were able to overcome these challenges and finish the year strong,” CEO Thomas Meissner said.

Posted on

How to Quicken Transmission Development Discussed at NARUC

The U.S. used to be able to build massive infrastructure projects such as the Empire State Building and the Pentagon in just a year, but nearly a century later that is far from the case with electric transmission, Maryland Public Service Commission Chairman Jason Stanek said at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit on Monday.

With billions in dollars in new federal incentives aimed at expanding clean energy, the pace of transmission development needs to speed up in order to take full advantage of those.

“As a state commissioner, I’m disappointed,” Stanek said. “I’m disappointed that over my five years at the commission, I haven’t been able to site and build 1 inch of interstate transmission.”

The Inflation Reduction Act and the Infrastructure Investment and Jobs Act (IIJA) are setting the country on course for the largest investment in infrastructure installation in 100 years, said Jeff Dennis, deputy director of the U.S. Department of Energy’s Grid Deployment Office.

“But we know that a significant portion of those benefits — as much as 80%, according to a Princeton study — of the emission reduction benefits that Congress expected from the IRA won’t happen if we don’t increase the pace at which we build transmission,” Dennis said.

The past decade has seen the grid expand at a clip of about 1% per year, but that needs to exceed 2% to meet those goals, he added.

Much of the funding DOE received for transmission in those recent laws is for “commercial support” rather than the loans it has used most often in the past, said Dennis. The money will help finance and speed up the development of transmission.

The IIJA included $2.5 billion the department can use to facilitate transmission by doing things like becoming the anchor-customer on a line to help it get financed and then sell off that space as the project is developed. The IRA has another $2 billion that DOE can use to help support transmission projects deemed in the national interest, Dennis said.

DOE also has new loan authorities, including some aimed at repowering existing corridors so that they can transmit more energy than they do now, Dennis said.

The IRA offers $100 million for addition regional and interregional transmission lines.

New England is expecting major changes to its grid, as it will have to greatly expand clean energy to meet future demand, which is on pace itself to grow from 25 GW today to 43 GW in the future because of electrification, said Digaunto Chatterjee, vice president of system planning for Eversource Energy.

“The best way to deploy IIJA funds is to surgically address specific transmission upgrades on your system and create new landing sites for offshore wind,” Chatterjee said.

While the industry has a daunting task of expanding its transmission grid and turning over to new sources of generation, it is a job that it has successfully performed in the past, said National Grid Clean Energy Development Director Terron Hill.

“When you think about the 1970s, we had a huge buildout of the transmission network in order to pick up electrification needs and new industries,” said Hill. “We saw the same type of buildout of the transmission network as we transitioned away from oil and coal to natural gas.”

New England has added about 300 MW of renewable energy per year, but to meet its carbon-mitigation goals, the pace of infrastructure development will need to be closer to 3,000 MW, Hill said.

“That is a huge challenge, but it’s a challenge that we can meet,” Hill said. “I was told very early in my career, that if you give engineers and planners a problem to solve, they will come up with the best solutions.”

Part of the solution is getting more efficiency out of the existing transmission grid through the adoption of dynamic line ratings, topology optimization and advanced power flow controls, said Hilary Pearson, vice president of policy for LineVision. The firm’s technology has helped New York wring more transfer capability out of its grid, which has historically been congested in power flowing from west to east and north to south, limiting the amount of load served by clean energy.

“By using dynamic line rating sensors in the western part of the state — very renewable-rich but has constraints and congestion on the system — we’re going to be able to eliminate 320 MW of existing wind energy curtailments, while creating another 190 MW in headroom for new renewable energy projects to be able to come onto the grid,” she said.

Posted on

DC Circuit Upholds FERC on Montana PURPA Project

The D.C. Circuit Court of Appeals on Tuesday upheld a FERC decision that allowed a solar-and-storage project in Montana to be certified as a qualifying facility under the Public Utility Regulatory Policies Act even though its total power production capacity exceeded the law’s 80-MW limit (21-1126).

FERC had justified its March 2021 decision under its longstanding “send-out” analysis, which determines a facility’s capacity based on the electricity it can actually deliver to an interconnecting electric utility.

Broad Reach Power’s Broadview Solar project included solar panels with a gross capacity of 160 MW DC and a 50-MW battery, but the project’s inverters allowed it to produce and deliver only 80 MW to its interconnection with NorthWestern Energy’s (NASDAQ:NWE) transmission system.d.

“The commission’s determination that Broadview is a qualifying facility with a ‘power production capacity … not greater than 80 MW’ because its component parts, working together, produce no more than 80 MW of grid-usable AC power was reasonable and well-supported by the statute’s text, structure, purpose and legislative history,” the D.C. Circuit said in its decision.

In upholding FERC’s order, the court rejected challenges by NorthWestern and the Edison Electric Institute, which argued that FERC exceeded its authority because the “power production capacity” of Broadview’s facility should be the total amount of DC power generated by the solar array and not the grid-usable AC power produced by the inverters working in conjunction with the solar array and battery.

PURPA was enacted in 1978 to encourage alternative energy generation by “qualifying small power production facilities” (QFs). It requires utilities such as NorthWestern to purchase a QF’s generation output, “providing those facilities with a guaranteed market,” the court noted.

Montana has been an especially contentious front for PURPA disputes in the West, where utilities contend the law requires them to integrate large volumes of QF renewable resources at contracted rates far above market rates.

Circuit Judge Justin Walker dissented in part from his colleagues on the three-judge panel, Circuit Judge Cornelia Pillard and Senior Circuit Judge David Sentelle, who drafted the majority opinion.  

PURPA “gives lucrative benefits to small facilities that produce solar power,” Walker wrote. “It defines them as facilities with a ‘power production capacity’ of no more than 80 MW. … Because Broadview can produce 80 MW for its inverters while it simultaneously produces 50 MW for its battery, Broadview’s facility is capable of producing more than 80 MW of power. So it is too large to be a ‘small facility.’ For that reason, I would grant the petitions, vacate the rehearing orders and remand to FERC for reconsideration.”

The case took an unusual twist at FERC before reaching the appeals court.   

In September 2020, FERC broke with its own precedent by deciding the Broadview project could not be certified as a QF because it exceeded the 80-MW cap despite its limited interconnection. Its decision aligned with the arguments of NorthWestern and EEI.

The commission’s lone Democrat at the time, Richard Glick, dissented. The commission’s decision, Glick wrote, “will make QF status turn on the capacity of any one component of the facility, rather than the actual power production capacity of the facility itself. That conclusion finds no support in the statute, our precedent or common sense.” (See Montana Hybrid Ruling Departs from PURPA Precedent.)

In March 2021, with Glick now chairman, FERC set aside its prior ruling, reinstated its send-out analysis, and determined Broadview could be a QF. (See FERC Reverses Ruling on Montana QF.)

“It is not fathomable to conclude that Congress would be more concerned about the electricity a project could theoretically generate on its own but not deliver to any customer,” Glick said at the time. “Instead, since the statute is all about the sale of a project’s output, the appropriate way to look at a facility is to assess how much can actually be sold to the purchasing utility.”

Posted on

NARUC Panelists: Rate Design Key for the Clean Energy Transition

Getting rate design right is important to the clean energy transition because it will help determine the best resource mix and ensure customers have opportunities to cut their bills with demand response and distributed resources, experts said at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit this week.

“The reason that I think there’s no more exciting topic than rate design is because it truly sits at that intersection of every other aspect of the energy system: affordability, reliability; all of the conversations we’re having around grid modernization, integration of different resources, customer choice,” said former Virginia State Corporation Commissioner Angela Navarro, now head of state regulatory affairs for Richmond-based climate technology company Arcadia. “All of those things are central to determinations on rates.”

Smart meters are on most homes in the country now, while rooftop solar and electric vehicles are becoming increasingly common; how those resources impact rates is very important, Navarro said. Storage has huge potential, but that can only be harnessed with the right rate design that informs its owners when to charge and discharge.

On the other side, the right rate design can help avoid negative impacts on the grid, such as by encouraging customers to charge their EVs during off-peak hours, she added.

Supply is going to be more variable in the future because of the growth of intermittent renewables and more common extreme weather, said Lon Huber, Duke Energy vice president of pricing and customer solutions.

“But fortunately, with technology, we have an increasing number of tools to use to start shaping load to match the more variable supply out there,” Huber said.

Sending those price signals far and wide requires approval from regulators and the right technology; it cannot happen overnight, he added. On top of smart meters, utilities need field area networks, data management systems and updated billing systems that can take years to put in place.

Smart meters have been rolled out to 75% of the nation’s customers and despite being in place for years in many jurisdictions, their use rarely matches their potential, said Travis Kavulla, NRG Energy vice president of regulatory affairs.

“We’re still talking about single-digit percentages of those smart meters that are used to do anything to actually interact with customers in terms of sending a price signal or any other incentive to flex demand,” Kavulla said.

Kavulla recently wrote a paper for an Energy Systems Integration Group effort looking into how retail pricing could be used to get customers to respond to grid needs, called “Why is the Smart Grid So Dumb? Missing Incentives in Regulatory Policy for an Active Demand Side in the Electricity Sector.” It has been a more than a decade since federal stimulus dollars gave most states the push to install advanced metering, and despite soaring rhetoric from that time, the investment has done little to make demand an active part of the electric industry, he argues.

“My basic proposition is this: that someone somewhere has to face the clear price incentives to accurately manage demand in order for it to happen,” Kavulla said. “And all too often in our regulatory schema that we set up for ourselves, regulated utilities themselves lack clear incentives to do so. And even for competitive retailers like NRG, we face an incomplete set of incentives to make these kinds of investments in demand flexibility.”

Getting the rate signals right could mean huge savings, with New York state estimating it could cut the cost of compliance with its climate mandates by a third, while PJM identified retail rate design as one of five key focus areas for successfully decarbonizing the grid, he added.

Kavulla would like to see more jurisdictions set up opt-out time-of-use pricing to tap the demand resources that advanced metering has made available. Customer adoption of complex rates under opt-in constructs are too low.

“As much as my inner libertarian would like to avoid this, regulators really cannot escape making solid decisions on behalf of customers in highly regulated industries like these,” Kavulla said.

Opt-in regimes usually produce better responses from customers who affirmatively decide to participate, said Huber. The system works too, with Huber noting Arizona has seen up to 60% participation in time-of-use rate programs.

“I think opt-in in the long run is better, but it takes time,” Huber said. “And it takes a lot of marketing [and] a lot of education to get it done.”

The Future of Solar

Getting rate design right is important for the solar industry as rooftop panels become increasingly common in many jurisdictions, leading to often thorny debates about how to pay for their excess output going forward, experts said an earlier panel on Sunday.

“Increasingly some of the issues that we’re beginning to tackle are how do we sort of evolve the industry from what has been a traditional approach to behind the meter resources,” Solar Energy Industries Association Senior Director of Utility Regulation and Policy Kevin Lucas said. “And how do we evolve that in a way that’s going to make sure that regulators, policymakers, customers and utilities are getting the most bang for the buck out of the resources that they’re putting onto the grid?”

SEIA is working in Arizona now to get a system in place that encourages more growth of solar-plus-storage than its current “net billing” structure, which does favor storage but incentivizes its use to shave the customer’s own peak rather than the system peak. Customers get paid less for exporting power to the grid than they do shaving their own demand.

SEIA would like to see batteries controlled by utilities in a program where they can be called on up to 30 times a year for up to three hours at a time and they get paid based on response to those signals.

“So, if a customer chooses to participate in a given event, they will export energy, that energy is going to be measured, and at the end of the year, they will get a credit based on how well they perform during these specific calls,” Lucas said.

Some 760,000 customers have solar installations on their homes, but just 47,000 customers around the country have adopted storage, said Sunrun Senior Manager for Public Policy Thad Culley. Most of the customers with storage have bought systems to improve their resilience because they live in areas that experience outages more often.

Expanding that market to a bigger number of customers and getting them to work with the grid is going to take some new rates, Culley said.

“You’re going to need to have some kind of predictable value stream going forward to motivate the customer to want to play nice with the grid and do the types of grid support services that are valuable,” Culley said.

With the right incentives, those customers could even provide more specific services that benefit the local grid, he added.

Posted on

FERC OKs WEIM Changes for Washington Cap-and-trade Costs

FERC on Friday approved Western Energy Imbalance Market (WEIM) tariff revisions to allow generators to include costs associated with the Washington cap-and-trade program in their default energy bids and commitment costs.

The commission approved the revisions over the objection of the Utah Division of Public Utilities (UDPU), which argued the rule changes run afoul of the U.S. Constitution because they impose an unlawful “border tax” on electricity imported into Washington (ER23-474).

WEIM operator CAISO filed the tariff changes late last year in anticipation of the Jan. 1 roll-out of Washington’s cap-and-trade regulations, which require any in-state emitters of more than 25,000 metric tons of carbon a year — including electricity generators — to acquire allowances to cover their emissions. The rules also apply to any electricity imported to serve Washington demand.

CAISO’s rule changes have to do with the reference levels the ISO uses to calculate a resource’s default energy bids and commitment costs for the WEIM. In its filing with FERC, the ISO proposed to alter the reference levels to allow generators selling into Washington to reflect GHG compliance costs in their market bids to ensure that those resources don’t appear be less expensive than their actual costs.

CAISO modeled the changes on tariff provisions already in place to accommodate California’s cap-and-trade program, which is administered by the state’s Air Resources Board (CARB). Under those provisions, the reference levels used in the default energy bid and commitment costs are based on a GHG allowance price derived from the average of two index prices published by separate vendors.

Washington’s cap-and-trade program is not tied to CARB’s, and the Washington-specific provisions approved by FERC on Friday differ in their details because the state’s Department of Ecology will not be holding an allowance auction until later this month, meaning there is not yet a published allowance price available to set the reference level. CAISO instead proposed a three-phase rate that will change in response to certain “triggers,” FERC noted.

In the first phase, before the first auction, CAISO will rely on a reference rate of $41/metric ton (MT), the halfway point between the Ecology Department’s floor and ceiling prices of $19.70/MT and $72.29/MT, respectively. For the second phase, CAISO will use the clearing price from the most recent quarterly auction until index prices become available. In the third phase, the ISO will rely on the average of two index prices from separate vendors, similar to its treatment of the CARB program.

The ISO contended that an index price would eventually provide a more accurate reflection of the price for Washington allowances.

“CAISO indicates that while the auction price is a starting point, as Washington’s cap-and-invest program evolves, CAISO expects market participants will engage in bilateral trading, which will cause deviations from the auction price.  According to CAISO, an index price, updated daily on weekdays, provides a timelier estimate of the allowance price,” FERC wrote.

Constitutional Questions

In approving the WEIM tariff provisions, FERC rebuffed the sole protest by the UDPU, a Utah agency charged with investigating consumer utility complaints and monitoring utility operations to ensure compliance with state Public Service Commission rules.

The UDPU contended that the tariff changes violate the Constitution’s Supremacy Clause because they subject out-of-state generators to Washington’s state-levied allowances, contravening FERC’s “exclusive authority to regulate the sale of electric energy at wholesale in interstate commerce.”

“UDPU states that the CAISO adders for compliance with state-specific cap-and-invest programs will affect the set of resources selected for generation in the WEIM, causing commission-jurisdictional markets to clear in significantly different ways than they would in the absence of those directly-imposed bid costs,” FERC noted.

The agency had also argued that Washington’s cap-and-trade program is unconstitutional under the dormant Commerce Clause because it imposes a “border tax” on energy imported into Washington. And it additionally contended that the program provides preferential treatment to in-state interests because Washington utilities are provided a free allocation of GHG allowances, buffering the state’s ratepayers from the burden of some compliance costs.

The commission said it was “not persuaded” by the UDPU’s arguments, noting that it could only consider whether the tariff provisions were just and reasonable under the Federal Power Act, and not the legality of the underlying law motivating the provisions.

FERC wrote that the revisions “simply allow generators to incorporate compliance costs associated with Washington’s cap-and-invest program in their default energy bids and commitment costs, which account for the variable costs of generation and provide generators a reasonable opportunity to recover their costs.” Those revisions are consistent with other commission-accepted tariff provisions that accommodate the compliance costs associated with state environmental requirements — including in the WEIM, the commission said.

The commission similarly found the UDPU’s “border tax” argument to be aimed at the constitutionality of the cap-and-trade program, saying a FERC proceeding was not the proper venue for addressing such a question.

“In any case, if the commission were to reject CAISO’s filing based on constitutional grounds, and if Washington’s cap-and-invest program were not ultimately enjoined by a federal court, generators would be deprived of the opportunity to recover costs that they are legally obligated to incur,” the commission said. “As long as the tariff revisions at issue apply to the mandatory compliance costs incurred by generators within the borders of Washington and which are subject to Washington’s jurisdiction, we are required to allow the opportunity for their recovery.”

Posted on

PJM OC Briefs: Feb. 9, 2023

No Consensus on IROL-CIP Cost Recovery

VALLEY FORGE, Pa. — PJM and its Independent Market Monitor gave first reads of their proposals exploring whether generators should be permitted to recover upgrade costs for facilities determined critical for interconnection reliability operating limits (IROLs) under NERC Critical Infrastructure Protection (CIP) standards.

PJM’s proposal would create a cost recovery mechanism similar to black start service, where expenses can be submitted to both the RTO and Monitor for review and monthly payments would be made from revenue socialized across the RTO. PJM argued that the investments needed to comply with the standards are above what is typically required of generators and there is not a sufficient look-ahead in the analysis its staff does to identify critical facilities for a generator to include its expenses in future Base Residual Auction (BRA) offers. (See “Revisions to IROL CIP Issue Charge Rejected,” PJM Operating Committee Briefs: Dec. 8, 2022.)

Steve McElwee 2022-07-13 (RTO Insider LLC) FI.jpgPJM Chief Information Security Officer Steve McElwee | © RTO Insider LLC

IMM Joseph Bowring said the concept of “cost recovery” is part of the old-fashioned cost-of-service regulatory model that is not relevant to markets. Bowring said it’s already possible for generators to represent their IROL-CIP costs in market offers and it would be inappropriate to create out-of-market cost recovery for the expenses. His proposal would memorialize that there is no cost recovery structure in PJM’s governing documents.

“PJM runs markets,” he said. “PJM is not a regulator.”

Rather than this being an issue for PJM to resolve, Bowring said generators should bear the costs. He compared the situation to investments facilities must make to comply with environmental regulations. No separate cost recovery mechanism was created for those costs, even though they were much larger than the IROL-CIP costs. Bowring also noted that there is no profitability test and that PJM plan proponents have no idea whether the identified generators are already more than covering all costs.

Greg Poulos, of the Consumer Advocates of the PJM States (CAPS), said state advocates are interested in seeing the most reasonable and best costs realized through markets. Creating cost-of-service structures creates a pathway for market participants to argue that each of their unique characteristics is a service that should be compensated.

Jim Davis of Dominion Energy said the comparison to black start is flawed because it is a voluntary service, while IROL-CIP critical status is determined by PJM. He said since that status is reevaluated annually, a facility may undergo significant upgrades only to have its critical marker removed after 12 months.

“The risk those resources have is [that] the rug could be pulled out from under them at the very last minute and have their status reverted back to low,” he said.

Security Update

PJM’s Steve McElwee urged stakeholders to be on the lookout for hackers impersonating known figures and report any suspicious activity to the RTO. He said members recently reported a “phishing” attempt impersonating PJM staff and contacting members saying their accounts are being suspended.

“It really is that partnership for us to be working together,” he said.

Dynamic Line Rating Task Force Update

Stakeholders endorsed the conclusion of the Dynamic Line Rating (DLR) Task Force following the wrap-up of the group’s work providing education as stakeholders and PJM drafted and implemented a new framework to incorporate the technology into its operations.

PJM’s Natalie Tacka Furtaw told the OC that if future issues related to DLR arise, they can be addressed with a new problem statement and issue charge.

Stakeholders approved a problem statement and issue charge alongside a proposed solution under PJM’s “quick fix” process at the April 2022 OC, and PPL went live with the technology in October. The task force continued to monitor the implementation of DLR and its impact to auction revenue rights and financial transmission rights trading; however, there have not been any new requests for information since its December meeting. (See “Dynamic Rating Issue Endorsed,” PJM Operating Committee Briefs: April 14, 2022)

Fuel Supply Overview

Fuel inventories are moving in the right direction, despite natural gas well freeze-offs and the derailment of a train in Ohio disrupting a major cog in the rail system for the eastern PJM region, Brian Fitzpatrick, PJM’s principal fuel supply strategist, told the OC. With stockpiles improving and major transportation risks averted, namely the potential for a railroad strike, PJM is shifting to collecting inventory data biweekly rather than weekly.

“Generally speaking, we’re starting to see an increase back in onsite inventories,” he said.

A cold snap over Feb. 2-4 resulted in freeze-offs amounting to around 2 bcf/d in Appalachian supply, but mild weather has helped build a nearly 7% inventory surplus relative to the five-year average. Fitzpatrick said the impact to supply was minor compared to Winter Storm Elliott, which caused the loss of 10-11 bcf/d. Aside from the Dec. 23-24 storm, he said it has been an otherwise smooth winter for natural gas thus far.

The derailment of a Norfolk Southern train in East Palestine, Ohio, has not caused major issues transporting coal, and Appalachian production remains around 5% above last year’s outputs.

The mild winter has also helped East Coast inventories of diesel and residual fuel oil recover from being notably below the five-year average throughout 2022.

Posted on

Environmentalists Applaud Whitmer Budget on Climate Change Issues

Gov. Gretchen Whitmer’s (D) 2023-24 budget proposal calling for about $500 million to fund efforts to reach Michigan’s net-zero goals won praise last week from environmentalists.

Whitmer’s budget, the first of her second term in office, proposes slightly more than $79 billion in total spending, meaning the climate change mitigation spending makes up less than 1%.

But Derrell Slaughter, with the Michigan office of the Natural Resources Defense Council, said Whitmer’s “budget proposal points to the clean energy transition moving forward in Michigan.” While the investments are small overall compared to the entire budget, Slaughter said they would boost jobs, cut consumer electricity bills and lower overall pollution.

And when paired with other spending proposals on issues improving home weatherization, the budget will help many Michiganders, especially those in lower-income households, save money, said Lisa Wozniak, executive director of the Michigan League of Conservation Voters. Whitmer’s proposed budget “puts money back in Michiganders’ pockets while investing in our communities, expanding clean energy and protecting our health,” Wozniak said.

Included in the spending plan is:

  • $150 million in grants for school districts to run electric school buses;
  • $45 million, mostly in federal funds, for the Michigan Clean Fleet Initiative to encourage counties, airports and regional transit systems to upgrade to electric vehicles;
  • $40 million in one-time state general fund monies to help local governments get ready to develop renewal resources;
  • $43 million to help harden the state’s electric grid against natural disasters and severe weather incidents; and
  • $100 million for environmental justices projects.

Whitmer also called for the state to temporarily suspend the sales and use taxes on the first $40,000 of the cost of an electric vehicle.

Charles Griffith with the Ecology Center said the organization would continue lobbying for even more funds to meet the goals of the MI Healthy Environment Plan, but he called Whitmer’s proposal “a great step forward.”

Michigan’s fiscal year runs from Oct. 1 to Sept. 30, and typically the Legislature completes work on the budget by early summer.

The budget has been criticized by Republicans for proposing to spend almost all the nearly $9 billion surplus Michigan received from the federal government, leaving just $250 million that would be allocated to the state’s Budget Stabilization Fund, used during economic recessions to minimize budget cuts.

Republicans also worried the plan is designed to forestall a required income tax cut if the state finds itself with a large budget surplus. Top state officials have not been shy about saying an alternative tax proposal pushed by Whitmer is designed in part to keep the required income tax rate cut from taking place, and thus preventing the political anguish of trying to raise the rate in the event of a recession.

Democrats narrowly hold the majority in both houses of the Legislature: by just one vote in the Senate, and two votes in the House of Representatives.

Posted on

FERC OKs Changes to MISO Retirement Studies

FERC on Friday ruled that MISO generation owners must now give a year’s advance notice to the grid operator before they can retire or suspend resources.

The commission approved MISO’s request to double  the amount of time it has historically required GOs to submit the notices under Attachment Y of the tariff, effective Monday (ER23-630). 

The RTO’s requirement that notices be submitted four full quarterly study periods in advance is just one piece of a more rigorous generation-retirement proposal. The grid operator will now conduct retirement reliability studies in batches on a quarterly basis and include extra analysis of thermal, voltage, stability and import limitations. Staff will also halve the time, from 75 to 150 calendar days, that they’ve allotted themselves to notify GOs whether their resources are needed for reliability purposes. (See MISO to File More Stringent Generator Retirement Study Process.)

MISO said it needs the additional notice to better analyze an anticipated slew of retirement requests. FERC agreed.

“As MISO explains, it expects to continue receiving a substantial amount of Attachment Y notices for generator suspensions and retirements,” the commission wrote. “We find that the revisions will enhance the study process by allowing MISO more time to conduct the Attachment Y study that is needed to assess whether the reliability of the MISO transmission system is impacted by specific unit suspensions and retirements.”

FERC’s order also stimulated debate over whether the RTO should share some details of the confidential retirement notices it receives.

The footprint’s industrial customers asked FERC to require more transparency from MISO about its members’ retirement plans, saying the grid operator is “falling short of promoting full and robust transparency that enables forward market signals regarding generation suspensions and retirements for resource adequacy and transmission planning.”

The RTO should immediately and publicly disclose Attachment Y notices it receives so utilities can make timely plans for new generation or demand management, the customers said. FERC said the request was beyond the scope of the proceeding.

Commissioner Allison Clements said though she ultimately agreed with the decision, the secrecy surrounding MISO generation retirements might need some loosening. She said the extended-notice requirement could lead to GOs keeping their suspension and retirement plans under wraps longer.

“Transparency in this context requires a balance between generation owners’ desire for confidentiality and the consumer benefits of earlier notice to allow market forces and planning processes to efficiently respond to generation supply changes,” she wrote. “However, I am not convinced that MISO’s current confidentiality provisions strike that balance appropriately.”

Clements encouraged MISO and its stakeholders to discuss whether “more timely public notice of forthcoming suspensions and retirements is feasible.”

“The primary basis for MISO’s proposal in this proceeding is that the number of generator suspension and retirement requests has substantially increased in recent years, and MISO expects that trend to continue. This means that potential negative effects of insufficient transparency will only grow as the fleet transition continues,” she said.