NYISO asked FERC last week to reject protests by state regulators and clean energy groups over the ISO’s proposal for integrating distributed energy resource aggregations into its markets, defending its call for a 10-kW minimum for participation (ER23-2040).
In June, NYISO proposed a 10-kW minimum capability for individual DER participation in aggregations, along with new metering and telemetry requirements for DERs. (See “DER Revisions,” NYISO CEO Delivers ‘State of the Grid’ to Management Committee.)
The ISO said the 10-kW minimum was needed to save staff time reviewing aggregations for interconnection and enabling it to integrate new software and procedures without significant hassle.
But the New York Public Service Commission, Advanced Energy Management Alliance and Advanced Energy United said the ISO’s proposals were unclear and ran afoul of FERC Order 2222 and that more time was needed to evaluate their impact.
In a joint protest, AEMA and AEU took exception to several of NYISO’s proposals, including limiting the ability to use a third-party meter service in homogeneous aggregations, eliminating bid-based and locational-based marginal price-based reference prices, and the transition mechanisms through which transmission operators will upgrade their system to allow DER aggregations.
The two organizations were most concerned about the proposed 10-kW minimum requirement, calling it “fundamentally at odds with FERC’s findings in Order No. 2222.”
“Other wholesale markets, such as ERCOT, have developed rules that allow residential scale participation,” they said. Despite pledging a “goal” to accommodate small DERs, NYISO’s “filing gives no commitment or timeframe to do so,” the groups said.
“Failing to allow such resources to provide wholesale services they are technically capable of providing absent an arbitrary and unjustified minimum capacity requirement is unjust and unreasonable and presents an undue barrier to market participation that will undermine competition and reliability to the detriment of customers,” they added.
The PSC was also concerned about the 10-kW proposal, saying in its protest that the requirement was “unduly restrictive and inconsistent with the directives of Order No. 2222.”
The ISO responded that it “has spent more than 15 months working with its stakeholders to develop the business practice manual provisions that detail how the DER and aggregation participation model will be implemented.”
While saying it was “sympathetic” to stakeholder concerns, the ISO said their proposed remedies would be administratively burdensome and could further delay the introduction of DER aggregations into its markets.
The ISO has requested FERC rule on its proposal by July 31, saying it hopes to implement DER aggregation as early as Aug. 1.
New Jersey Gov. Phil Murphy signed legislation Thursday that will allow the state’s first offshore wind project to benefit from federal tax credits.
Murphy signed the bill, A5651, in a press conference at a new factory built by German manufacturer EEW to build monopiles for use in the foundations of offshore wind turbines. The Senate and the General Assembly passed the bill 21-14 and 46-30, respectively, on June 30 in the last session before the legislature recessed for the summer. The legislature will not return until after the November elections.
Unlike other states, New Jersey doesn’t allow wind developers to receive the benefits of tax credits awarded under federal laws such as the Inflation Reduction Act. Instead, the state receives the benefits for use to help ratepayers.
The new law allows the state’s first OSW project, Ocean Wind 1, to receive the tax credit benefits, but it does not allow other wind projects in the state to get the same benefits. (See NJ Lawmakers Back Ørsted’s Tax Credit Plea.)
Murphy hailed the bill as “absolutely critical to moving our entire offshore wind industry forward and cementing our leadership in this new industry.”
“I cannot emphasize this enough: We have a once-in-a-generation opportunity right now to bring tens of thousands of overwhelmingly union jobs and billions of dollars of investment to our state with offshore wind,” he said at the conference at the Port of Paulsboro, flanked by massive monopiles under preparation for eventual use in the foundations of a wind turbine. He said they were the first ever monopiles built on U.S. soil.
“New Jersey is literally building the foundation for our nation’s entire wind industry, and this bill will allow these projects to expand and create even more jobs,” he said.
The New Jersey Board of Public Utilities approved Ocean Wind 1, from Danish developer Ørsted, in 2019. The BPU also has approved the 1,148-MW Ocean Wind 2 and 1,510-MW Atlantic Shores. The state’s third solicitation, launched by the BPU in March, could result in the award of capacity totaling 4 GW or more. (See NJ Opens Third OSW Solicitation Seeking 4 GW+.)
A think-tank report published June 5 on the state’s rapidly growing OSW sector said the construction of a second phase of the EEW factory was “more than a year behind schedule” because of funding issues, in large part because Ørsted could not access the federal tax credits. Speaking before the legislature’s votes last month, the developer said federal tax credits were intended to advance industry development. The company said it already has invested $160 million in the EEW factory and “is poised to increase this investment.” (See NJ OSW Projects Face Public Funding Scrutiny.)
After the bill was passed, Atlantic Shores CEO Joris Veldhoven said in a statement that the approval “reaffirms the state’s commitment to offshore wind” and called on it to enact an “industry-wide solution, one that stabilizes all current projects including Atlantic Shores … the largest offshore wind project in the state of New Jersey.”
“We need immediate action that also supports the Atlantic Shores project,” he said.
Budget Signed, but Other Bills Remain
The OSW tax credit bill was one of several clean energy-related bills advanced by the legislature on June 30.
Murphy also last week signed a bill, S2024, that enacts a $54.3 billion state budget that includes a $40 million Green Fund that the governor said would “leverage both private capital and federal funds.” The governor announced the fund in February but since has said little about it; nor has the New Jersey Economic Development Authority (EDA), which will administer it. Murphy’s budget book at that time said the fund was designed to “attract up to $280 million in private capital to advance projects to advance the state’s new and bold environmental goals.” (See NJ Launches $80M Clean Energy Loan Fund for Small Business.)
The signed budget also contains an additional $10 million “to support the continued installation of EV charging infrastructure throughout the state,” according to a statement put out by Murphy’s office.
The legislature also sent to Murphy a bill, S3044, that would put in place the funding for the first year of a three-year, $45-million pilot program enacted in 2022 that will be the state’s most aggressive move into replacing diesel buses with electric-powered buses. The bill passed the Assembly with a 49-27 vote and the Senate by 26-9.
The 2022 bill, A1282, required the New Jersey Department of Environmental Protection (DEP) to create a program under which six districts or contractors each year would take students to school with electric buses to assess the reliability and effectiveness of using them in place of diesel-powered vehicles. The performance of the buses would be evaluated on factors such as costs, maintenance, fuel use and speed, and data would be collected and submitted to the DEP. (See Electric School Bus Pilot Awaits NJ Governor’s Signature.)
In a less divisive vote, the Senate on June 30 passed 37-0 a bill, S427, that would provide corporate business tax credits to incentivize building owners to retrofit their warehouses to be solar ready. The bill now is before the Assembly Environment and Solid Waste Committee.
Buildings must be at least 100,000 square feet in size and create a “solar-ready zone” that accounts for at least 40% of the space. The credit, which would be available once solar panels are installed on the roof, would be at maximum the lesser of two options: 50% of the cost incurred in retrofitting the building for solar or $250,000.
The Senate also voted 27-13 to pass a bill, S2185, that would require the BPU to develop a pilot program to provide incentives to developers and others that install energy storage systems, and then create regulations for a permanent program. The program would seek to help develop a range of storage, from customer-sited energy storage systems to larger systems connected to the grid. (See Clean Energy Bills Stack up in NJ Legislature.) The bill now will be heard by the Assembly Appropriations Committee.
The Assembly advanced a bill, A5442, that would direct the BPU to study how best to market and promote large-scale geothermal heat pump systems and look at the feasibility and benefits of mounting such a campaign. After the 76-1 vote, the bill now is before the Senate Environment and Energy Committee.
Ohio lawmakers are raising concerns about how Illinois’ Climate and Equitable Jobs Act (CEJA) will impact their state’s ratepayers after PJM last year found that power plant retirements stemming from the law could require $2 billion in new transmission to maintain reliability.
Ohio House Public Utilities Committee Chair Dick Stein (R) and Senate Energy and Utility Committee Chair Bill Reineke (R), along with 10 other colleagues, sent a letter to PJM’s Board of Managers last month saying that while the RTO’s markets have done well for the state in the past, they were worried that could be changing.
“We are becoming increasingly concerned that the actions of PJM, FERC and other PJM states may jeopardize the successful, competitive market model that Ohio has nurtured,” the letter said. “We appreciate that PJM has brought concerns related to generation retirements and looming reliability challenges to our attention. Needless to say, we are quite concerned about reports that the PJM region is on the precipice of power shortages that could lead to blackouts for our consumers that need electricity.” (See PJM Chief: Retirements Need to Slow down.)
The legislators said those looming reliability issues are exacerbated by CEJA provisions that mandate closure of fossil fuel plants, which requires the phaseout of coal and natural gas units by specified dates starting in 2030, with the last plants to shut down in 2045. The law requires the Illinois government to collaborate with PJM and MISO starting in 2025 to analyze the impact of its provisions on reliability.
PJM has released a “very initial snapshot” of what the retirements could mean, including increased east-to-west power flows and up to $2 billion in transmission upgrades. That analysis did not include any of the new generation that CEJA incentives are expected to bring online. (See Illinois Climate Bill Could Force $2B in Tx Upgrades, PJM Says.)
A table from PJM showing the RTO’s initial estimates of what transmission upgrades might be required to reliably retire the power plants in Illinois impacted by CEJA. | PJM
Stein met with PJM after sending the letter, to which the RTO said in a statement it would formally respond soon.
“The loss of affordable and reliable coal and oil energy generation and the implementation of 100% renewables could potentially put a strain on the energy grid,” Stein said in a statement after the meeting. “Ohioans should not be burdened by cost increases that are caused by the policy choices of other states.”
The $2 billion is very preliminary, and now is the time for PJM, and the experts on the grid that it employs, to look into the issue more formally, former Illinois Commerce Commissioner Erin O’Connell Diaz said in an interview.
“It’s appropriate that the legislators of Ohio are concerned about it because there are a lot of costs that can flow out of different types of legislation,” said O’Connell-Diaz, who now runs consulting company FutureFWD.
While plant retirements generally create some new transmission costs, she said, ratepayers in Illinois and other states with similar clean energy policies are going to be paying to bring on clean energy, which will produce cheap power for the grid that Ohio will benefit from in the form of lower prices. The RTOs can quantify those kinds of benefits going forward as well, she said.
‘Shark-infested Waters’
The Natural Resources Defense Council supported CEJA, as it has similar laws in other states. Tom Rutigliano, of NRDC’s Sustainable FERC Project, argued that the Ohio legislators were mostly concerned about attacking renewables, but he also called for more coordination from the RTO.
“This letter is more focused on partisan, anti-renewable jabs than meaningful transmission or reliability solutions,” Rutigliano said in a statement. “Ohio officials’ efforts would be better directed toward following Illinois’s lead and working on collaborative, forward-looking reliability solutions, rather than attempting to close off their borders to clean, affordable energy. The request for further studies from PJM would be a distraction from what is needed to support a successful energy transition. Ultimately, this letter is a reminder that states need clear leadership, proactive planning and coordination from PJM.”
Former FERC Commissioner Tony Clark, a senior adviser at Wilkinson Barker Knauer, said such disputes among states have regularly come up and are likely to continue, especially in regions like PJM with varying energy policies. It is not ultimately feasible to isolate the impact of one state’s policies in regional markets, whether it is generation or (outside of the State Agreement Approach) transmission, he said.
“FERC has to allocate those costs based on court precedent with cost-causers and cost-payers being ‘roughly commensurate,’” Clark said. He said PJM’s strong minimum offer price rule (MOPR) represented “an attempt to try to isolate some of those costs, but the commission has backed off from that in recent years. It is, I think, taking a path where effectively the capacity markets are likely to wither a bit in terms of their revenue streams, and they seem to be more focused on trying to get more and more out of the energy and ancillary service markets. But even in those, you’re going to have spillover effects from any sort of market [or] public policy intervention in one state; it’s very hard to isolate it from others in an integrated market.”
If FERC had tried to keep the MOPR in place, states with strong clean energy policies would have pulled out of PJM and other markets, which put the federal regulator in a no-win situation in terms of market integrity, he added.
PJM states have been at odds over other issues in the past. A dispute over cost allocation more than a decade ago led to the “roughly commensurate” court precedent Clark cited. O’Connell-Diaz said she hoped for compromise on the dispute because any litigation would take years to resolve, and the industry needs to be focused on the reliable transition to a cleaner grid.
“But again, you put the overlay of the politics on it, and it’s shark-infested waters, isn’t it?” O’Connell-Diaz said. “And so, again, I go back to we really need to kind of wipe that away. You know, utility regulatory bodies should really have to be above all that that pressure. They need to be able to think clearly without any kind of political connotations.”
However, that is not an easy thing to do today, she added.
Former BOEM Director Amanda Lefton will lead RWE’s offshore wind development effort on the East Coast.
RWE announced the appointment Monday. The move will place her in charge of one of the largest projects of its kind in the United States: Community Offshore Wind, a collaboration with National Grid Ventures that has a potential output of over 3 GW.
Lefton was appointed director of the U.S. Bureau of Ocean Energy Management in early 2021, shortly after President Biden’s inauguration. She previously was first assistant secretary for energy and the environment for New York, a role that placed her at the center of that state’s climate protection efforts.
In January 2023, Lefton resigned as BOEM chief to become senior policy director of energy and climate at law firm Foley Hoag. Elizabeth Klein was named BOEM director upon Lefton’s departure.
As measured by installed capacity, RWE is the world’s second-largest offshore wind developer, behind Ørsted. All 19 of the facilities RWE now operates are outside U.S. waters, but it is working to develop wind farms off the east and west coasts of the United States.
In early 2022, RWE and National Grid Ventures successfully bid $1.1 billion for lease area OCS-A 0539, which is south of New York and east of New Jersey in the New York Bight. Expected operation date is 2030 for what the partners now call Community Offshore Wind.
In late 2022, RWE won a BOEM lease 28 miles off the coast of California with a $158 million bid that will allow it to develop up to 1.6 GW of floating wind. It projects completion sometime in the mid-2030s.
Community Offshore Wind is now awaiting word on whether it will be awarded a contract in New York’s 2022 offshore wind solicitation. The partners submitted multiple versions of their plan with a variety of price tags and power output ratings. As specified in the solicitation, they outlined ways they would help New York build an offshore wind industry.
RWE has previously developed onshore wind projects in New York state.
Lefton led BOEM at a critical time for the U.S. offshore wind sector, as President Biden set a 2030 goal of 30 GW of capacity and backed up the vision with policy. Installed capacity in U.S. waters was just 42 MW at that point, however, and there was little onshore infrastructure or domestic supply chain to support a radical expansion.
During her two years at BOEM’s helm, the agency greenlighted the nation’s first two utility-scale offshore wind projects, held three lease auctions, began review of 10 projects and advanced exploration of the Oregon and Central Atlantic coasts, the Gulf of Maine and the Gulf of Mexico for potential offshore wind development.
RWE in a news release Monday lauded Lefton’s stakeholder collaboration and all-of-government approach toward clearing the many obstacles to offshore development. Lefton in turn lauded RWE’s conception-to-completion track record in project development.
When she left BOEM for the private sector in January, the Department of Interior’s chief of staff said: “BOEM is at the epicenter of the Department’s work to create good-paying union jobs in the offshore energy sector, support a reliable domestic supply chain and meet the moment for a clean energy economy. Amanda has been a driving force of this effort, and we are grateful for her vision, commitment and service to this country.”
Sam Eaton, CEO of RWE Offshore Wind Holdings, made a similar point Monday: “Amanda has successfully created significant momentum for the offshore wind industry in the U.S. Her know-how navigating all levels of government has resulted in the approval and now construction of the nation’s first two offshore wind projects.”
The Department of Energy on Thursday announced the latest recipients of federal grant money intended to modernize the U.S. power grid against natural disasters caused by climate change, awarding $207.6 million to nine states and three tribal nations.
The grants are part of the $5 billion allocated to grid-hardening projects under the bipartisan Infrastructure Investment and Jobs Act (IIJA), which passed in 2021. Half of the spending is earmarked for state, territory, and tribal governments, to be distributed over the next five years. (See Bipartisan Infrastructure Bill Offers Funding for Grid, EVs.)
The nine states and three tribes announced on Thursday comprise the third cohort of recipients to be unveiled since the grants began earlier this year. Applications for the 2022 and 2023 fiscal years closed May 31 for state and territory governments; tribal governments have until Aug. 31 to submit their applications for the year.
Among the states included in Thursday’s announcement were California and Texas, the largest beneficiaries under the program so far with $67.5 million and $60.6 million awarded respectively. According to their fact sheets, California’s goals for the funding include reducing the frequency and duration of power outages in the state, advancing California’s clean energy goals and creating clean-energy jobs. Texas plans to use the money to identify gaps in grid resilience and improve weather-related resilience in critical infrastructure facilities.
Other recipients include:
Kansas — $13.3 million;
Kentucky — $11.1 million;
Maine — $4.4 million;
Michigan — $14.9 million;
Minnesota — $11.9 million;
Oregon — $19.9 million; and
Rhode Island — $3.4 million.
In addition, three Native American tribes — the Metlakatla Indian Community and the Native Village of Eagle in Alaska, and the Standing Rock Sioux Tribe of North and South Dakota — will receive a total of $622,000.
In all, the program has chosen 20 states, eight tribes, and the District of Columbia to receive $324 million so far this year. Eligibility is decided based on five factors: population, area, probability of disruptive events, severity of events and expenditure on mitigation efforts.
State and tribal governments must provide a 15% match to the federal allocation; entities receiving sub-awards from the grant recipient generally must provide a 100% match, although smaller utilities may match as little as one-third.
“Renewable energy has helped many parts of the country withstand a crippling heat dome, and the [administration’s] agenda will increase the amount of clean power sources available on the nation’s grid,” said Energy Secretary Jennifer Granholm. “DOE is excited to announce a continued stream of funding aimed at strengthening America’s workforce and preparing the nation for a more resilient, clean energy future. These grants will help modernize the electric grid to reduce impacts of extreme weather and natural disasters while enhancing power sector reliability.”
DOE’s resilience investments form just part of the expenditures planned for the U.S. grid under the IIJA. The Biden administration plans to invest more than $15 billion under its Building a Better Grid initiative launched last year, including the grid resilience program, a $2.5 billion program to upgrade transmission lines, the $10.5 billion Grid Resilience and Innovation Partnerships program to support national resilience projects and the $760 million Transmission Siting and Economic Development Grants program. (See DOE Opens Applications for $6B in Grid Funding.)
FERC on Friday approved a new settlement with BP America over allegations that it manipulated interstate natural gas prices in 2008 after an appeals court found the regulator exceeded its authority in an earlier penalty order (IN13-15).
BP agreed to pay a $10.75 million civil penalty and will not seek the return of an additional $250,295 in disgorgement that it had already paid. Initially, FERC had assessed a civil penalty of $20.16 million, which the firm appealed to the 5th U.S. Circuit Court of Appeals.
The firm already paid that earlier fine, plus interest, under protest, so the deal effectively means FERC will not oppose BP seeking to reclaim $13.6 million through a suit in the U.S. Court of Federal Claims, or any other forum with jurisdiction.
The case involved natural gas prices in the Houston Ship Channel in the days following Hurricane Ike in 2008, when BP allegedly traded next-day, fixed-price natural gas to artificially depress them to benefit positions it held.
The 5th Circuit found in a decision in October that some of the transactions FERC was seeking fines for were intrastate trades, over which the court said it does not have jurisdiction. The new order limits the fines to the 18 transactions the court said were under FERC’s authority to regulate.
FERC affirmed its finding that BP engaged in market manipulation but limited that finding pursuant to the court’s order. The commission had argued that it was able to seek fines on any natural gas transaction, including intrastate gas deals, that affects the prices it regulates under the Natural Gas Act, but the court rejected that claim.
“The commission cannot exercise its jurisdiction merely because a manipulative scheme may affect the prices of interstate natural gas trades,” the court said.
BP stipulated to the facts set forth in the deal and acknowledged that the 5th Circuit upheld FERC’s findings of manipulation when it came to the 18 jurisdictional transactions.
FERC’s Office of Enforcement started investigating BP after Ike during the period of Sept. 18 to Nov. 30, 2008, when it sought to determine whether the firm’s trades were intentionally trying to depress Platts’ Gas Daily index prices at the Houston Ship Channel to benefit bigger, financial spread positions BP held that settled off index prices.
The index positions BP held paid off when Houston Ship Channel natural gas was lower than the Henry Hub prices in Louisiana, which was the case when Ike hit and caused prices to plunge. Then the firm “engaged in a glut of physical sales” at the ship channel to keep the index profits rolling in for weeks after the hurricane hit, the court said.
Hecate Energy lost a court appeal to have FERC review its petition that NYISO had charged it an unreasonable rate for upgrade costs to connect a solar power plant near the New York state capitol to the grid (21-1192).
A majority of a three-judge panel of the D.C. Circuit Court of Appeals on Friday ruled against the renewable energy developer and disagreed with its argument that NYISO’s filed tariff with FERC was not detailed enough.
Hecate said it was surprised when NYISO charged it $10 million to interconnect a proposed solar facility in New York and initially challenged the decision with FERC after it was unwilling to pay for these upgrades.
FERC rejected Hecate’s argument that it was not given enough notice that six non-jurisdictional projects could be included in NYISO’s final bill for interconnection. FERC later affirmed its decision, denying Hecate’s rehearing request.
In response, Hecate filed two petitions for review with the court. The first was filed after FERC did not act on Hecate’s petition for a rehearing and the second was filed after FERC did address the request.
The court sided with FERC, however, finding NYISO’s tariff detailed enough and that it gives fair notice that non-jurisdictional projects could be included in interconnection studies.
The court also noted that Hecate’s contention that “FERC’s reading of the tariff cannot be squared with other tariff provisions” is lost since the generator did not make the argument to FERC on rehearing.
Hecate can raise its argument on appeal if it has “reasonable ground[s],” the opinion added.
Circuit Judge Justin Walker’s opinion included a quirky footnote for curious readers noting that Hecate is pronounced as “HEK-a-tee” like the Greek goddess of magic, not “HEK-ut,” like the ruler of the witches in Shakespeare’s “Macbeth.”
Kentucky regulators last month rejected Kentucky Power’s request to recoup $11.5 million in fuel costs incurred during the December 2022 winter storm, while also raising the prospect of penalizing the utility for its performance during the event.
Falling temperatures Dec. 23 caused a spike in demand among the utility’s 163,000 customers in eastern Kentucky, forcing the company to import high-priced power from PJM. By the time the storm passed on Dec. 25, the utility had exceeded what it could recover for fuel and power costs through the non-Fuel Adjustment Clause (FAC) in its tariff.
In its request to the state Public Service Commission, the utility sought to establish a regulatory asset for recovery under a law approved in March that permits utilities to seek PSC approval to “finance extraordinary or other deferred costs” through securitization.
In denying the request, the PSC said Kentucky Power had not taken steps to procure adequate capacity, had failed to demonstrate that outages at its two generators were reasonable and had not proved its costs were properly incurred.
On the capacity issue, the commission pointed out that the utility let a contract with American Electric Power’s (AEP) Rockport Power Plant expire in December without procuring replacement capacity, eliminating a key hedge against wholesale power price fluctuations and shifting risk to consumers.
“Kentucky Power took no action to address its capacity shortfall in regards to energy capabilities, including entering into agreements that could hedge against market power prices. The Commission concludes, as further explained below, that Kentucky Power has not met its burden in this matter, and therefore the request should be denied,” the order said.
Facing Penalties
Along with denying the requested recovery, the commission issued a second order requiring Kentucky Power to show cause as to why it should not be subject to penalties for violating a state law that requires a utility to provide “adequate, efficient and reasonable service” to customers. The second order said the utility could be assessed penalties up to $2,500 per occurrence and per party.
The commission also argued that the utility had not shown that outages at its 1,560-MW coal-fired Mitchell and 295-MW gas-fired Big Sandy generators were reasonable. In response to a data request from the commission, the company said the Big Sandy generator was offline due to repairs that took longer than anticipated to complete, while Mitchell was operating at reduced capacity for reasons largely unrelated to the storm.
The commission additionally questioned the use of the new securitization law.
“Kentucky Power’s request would alter the recovery mechanism for non-FAC eligible purchased power costs and is not an appropriate use of deferral accounting,” the order said. “The existence of securitization legislation does not preempt the commission’s broad authority related to regulatory assets and is not sufficient justification to defer expenses. In fact, securitization is only available for expenses for which deferral accounting has already been approved by the commission. Thus, it does not impact the commission’s decision on whether to grant deferrals.”
In a joint protest, the Kentucky Industrial Utility Customers and the Attorney General’s Office of Rate Intervention argued that Kentucky Power’s request was contrary to the FAC regulations and would preempt the six-month review of the clause — components of which both companies are protesting — and an administrative case investigating the FAC. The protest also posited that purchased power costs should be recovered through a base rate filing, rather than the FAC.
In an email to RTO Insider, Kentucky Power spokesperson Sarah Nusbaum said the company disagrees with the commission’s findings, arguing that purchasing power during Winter Storm Elliott was more affordable than a long-term contract and that the company’s decisions maintained reliability.
“Generation resources are selected based on least-cost principles, and it was less expensive to purchase energy when needed as compared to a long-term purchase power agreement,” Nusbaum said. “Regarding the penalty statute, we do respectfully disagree that the penalty statute is implicated here. We kept the lights on during a record storm and did not willfully violate any Kentucky law, regulation or KPSC order.”
Nusbaum said allowing the company to issue securitization bonds would have reduced carrying costs for the storm expenses and effectively reduced the interest rate compared with recovering those expenses through base rates. The company included securitization bonds in its June 29 base rate filing — along with other strategies for deferring the expenses — with the aim of reducing the immediate impact on ratepayers’ bills.
“Securitization was not the only method we used to reduce rate impact in this case,” Nusbaum said. “Kentucky Power is seeking a lower return-on-equity than was recommended by our expert witness, not proposing to increase depreciation rates, and extending the life of existing meters rather than replacing them with new meters. Additionally, several low-income benefits are proposed in this case, including an optional seasonal tariff to help reduce winter bills, an expansion of the company’s energy assistance program, and a solar garden program that directly benefits low-income customers.”
Utilities in Several States Petition Commissions for Cost Recovery
Several other utilities also are seeking approval to recover costs for expenses related to Winter Storm Elliott.
AEP spokesperson Scott Blake said the Public Service Company of Oklahoma and Appalachian Power in Virginia and West Virginia have filed to recover fuel costs, as well as costs for CCR and ELG work and other storm work.
In Kentucky, Kentucky Utilities and Louisville Gas and Electric received PSC approval for establishing a regulatory asset to recover costs related to a March 3 windstorm that caused nearly 400,000 customer outages. According to the utility’s filing, the storm resulted in around $83 million in operating, maintenance and capital costs. Total operating and maintenance costs are around $23.2 million, of which $7.8 million are included in base rates.
Though the filing sought to create a regulatory asset, it did not include securitization. The commission’s order found that the storm caused damage for which costs could not be reasonably anticipated.
“The commission finds that with regard to KU/LG&E’s request for authorization to establish deferral accounting for the repair and restoration of the Major Storm Event, the costs to repair the damaged assets are extraordinary and nonrecurring and could not have been reasonably anticipated or included in KU/LG&E’s planning,” the April 5 order said.
AUSTIN, Texas — Two of the world’s richest men, who are using their billions to help the clean energy transition, drew gawkers and rubberneckers in the halls of the JW Marriott Austin hotel’s event space during Edison Electric Institute’s annual conference last month.
Bill Gates and Elon Musk each filled the main ballroom with their respective keynotes. Gates, dapper in a business casual blazer, needed little prodding to share his thoughts on a clean energy future. Musk, wearing a fashionable outfit that included an open zipper across his chest and cowboy boots, was a man of fewer words, but big thoughts.
Gates showed up the day before his appearance. Trailed by a camera crew, he slipped into the conference’s networking center, which doubled as a trade show. It wasn’t long before Gates was surrounded by scores of observers as he made the first of several stops to the booths.
“Hey, Bill Gates is over there,” whispered one EEI staffer to another.
His first stop was at Antora Energy, a startup that uses thermal batteries to store renewable energy in carbon blocks that are then heated to 2,700 degrees Fahrenheit. The energy is discharged as zero-emission heat and/or power.
Antora is just one of more than 110 clean energy technologies that Gates’ Breakthrough Energy has invested in, about a dozen of which set up booths at the conference. The organization, founded by Gates in 2015, is working to accelerate innovation in sustainable energy and other technologies to reduce greenhouse gas emissions and reach a goal of net-zero emissions by 2050.
“Great ideas are just the beginning,” Gates explains on Breakthrough’s website. “We need a plan — and the willingness to do the hard work — so we can get on track over the next decade.”
“The key playbook of Breakthrough Energy has been to drive innovation and to drive policies for innovation,” Gates said from EEI’s main stage. “When we got this thing started in 2015, I didn’t know if we would find the innovative ideas. We raised several billion dollars, and amazingly, mostly here in the United States, we found phenomenal entrepreneurs and scientists together applying [for investment]. And so in any area of emissions, we now see the path to get there with execution, particularly on the green grid, which will be two and a half times the size of what we have today because of massive electrification.
“Massive electrification is daunting, but you can see that there is a path, a path that doesn’t involve saying to people, ‘OK, you now have to pay a lot more money for all your goods, including electricity,’” he said.
Asked by Ameren’s executive chairman, Warner Baxter, why he has such a rosy view that the 2050 net-zero goal will be reached, Gates pointed simply to civilization.
“The modern economy is about energy intensification. Crude oil and natural gas are magical things. The energy density there has allowed us to transform life in this very dramatic way,” Gates said. “The idea that now we have this goal, that by 2050 will basically replace all those cement plants, steel plants, coal plants — there’s no equivalent thing, even if you take the work that was done during World War II.”
He said the multidecade effort will have to be coordinated to make it work. That includes the “incredibly complex” task of designing a new electric grid.
“Many people, when they look at the climate problem, they’re like, ‘OK, what can we do to make a little bit of progress?’ But as you look at it, you’d say, “Oh, no, I need to get all the way to zero,’” he said. “You have to do the very hard things, and you have to do it not just in the rich countries but also in middle-income countries that now account for the bulk of the [world’s] nations. We have a lot of work to do to get to that in a very short period of time.
“We’re no longer able to say, ‘OK, in the near term, it’s business as usual,’ and then that payment comes later. We are now in the time period where the rate of renewable build and the rate of transmission permitting is completely inadequate to this goal. And yet, people have worked with us to lead on this.”
While obviously a fan of renewable energy, Gates said individual states’ incentives for generation and transmission projects will make it difficult to ensure reliability as more renewables are integrated onto the grid.
“If a huge part [of generation] is renewable energy — offshore wind, onshore wind, solar — then you’ll have parts of the United States where they will not be able to generate enough energy,” he said. “And so the idea that this has been done overwhelmingly at the state level — here’s a load; here’s [a] generator that’s fairly near that load — that paradigm does not work to get to zero emissions.”
Musk: Demand to Triple by 2045
Musk focuses much of his energy on electric vehicles, batteries and solar panels. That is, when he’s not exploring space, boring tunnels underground or attempting to manage his social media company.
He rose to fame and riches with Tesla, which dominates the EV market. Its massive Austin Gigafactory —driving past the 2,500-acre facility at the nearby state highway’s speed limit takes about 45 seconds — produces 5,000 Model Ys a week. Globally, more than 440,000 EVs rolled off Tesla production lines during the first quarter of this year.
Just before Musk’s appearance at EEI, Tesla announced it was partnering with Ford and General Motors and sharing charging infrastructure. Electrify America, the country’s largest fast-charging network for other EVs, has said it will incorporate Tesla’s charging standard into its stations as part of its commitment to “broaden charging solutions.”
“I think opening up the chargers is morally right, and it was something that will help power sustainability,” Musk told his audience. “We’re really trying to do everything here. We will support all electric vehicles on equal footing. We’re not advocating for special treatment of Tesla. We’re trying to clear a path for sustainability.”
However, Musk said, if the U.S. is to achieve a sustainable future, his back-of-the-envelope projections indicate electricity demand will triple by 2045.
“Everything is going to be electric,” he told his EEI audience. “I don’t know what your plans are for future electricity demand, but it’s going to be much higher than you think. You should start to plan now. We’re trying to work to a sustainable energy future, and it’s going to take many technology solutions to get there.
“I think this is good news for everyone who produces electricity, but it entails a tremendous amount of work ahead,” Musk added.
The key is the three pillars of a sustainable energy future, he said. They are sustainable power generation like solar, wind, hydro and nuclear; stationary batteries; and electric transportation.
“Once we have those three pillars in place, we’ll have a sustainable future for as long as the sun shines and the wind blows,” Musk said. “It will very much be a joint effort. The utilities have the wires; they’re the distributors of electricity. It’s hard work to actually put that generation in place and transport it to where it gets used, but we have to take advantage of the valleys of power production.”
Of course, he pushed Tesla Energy’s Powerwall as part of the equation. The sleek rechargeable lithium-ion residential battery stores solar energy for self-consumption, time-of-use load shifting and backup power. Aggregated together, they can be even more beneficial to the grid, Musk said.
“You’re operating collectively and helping to stabilize and preserve everything. The Powerwall battery pack is a helpful part of solving the energy problem because there’s a lot of neighborhoods where it’s hard to get incremental power to that neighborhood because you need more substations and you need more wires. Local storage helps alleviate some very boring situations where it’s just so frustratingly difficult to get more power to that neighborhood. It’s really a big deal and really helpful because obviously, it’s battery at scale, and it pumps electricity. We can do electricity better.”
The California Air Resources Board (CARB) is now taking applications for $150 million in state funding to help public school districts buy zero-emission buses and related infrastructure.
In announcing the funding round on Friday, the agency said recipients can get up to $395,000 to replace fossil fuel-powered buses with zero-emission models, as well as $100,000 per bus to acquire and install necessary charging equipment. Winners of the awards are required to scrap an old bus for every new vehicle purchased.
This marks the second year CARB is making money available under the state’s Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP) Public School Bus Set-Aside program, which last year helped 81 school districts buy 300 zero-emission buses, according to CARB.
“Zero-emission school buses play a key role in California’s efforts to achieve carbon neutrality [by] 2045 and help protect children who are particularly vulnerable to the health impacts from diesel exhaust,” the agency said in a statement.
CARB is partnering with the California Energy Commission’s Energy Infrastructure Incentives for Zero-Emission Commercial Vehicles Project (EnergIIZE) to help fund the charging infrastructure, which can include vehicle-to-grid (V2G) hook-ups that allow bus batteries to transmit energy back to the electricity grid to meet peak demand. California’s largest utility, Pacific Gas and Electric, last year received regulatory approval to establish the nation’s first V2G export rates for commercial electric vehicles, including school buses. (See PG&E to Offer Nation’s First V2G Export Rate.)
According to the U.S. Department of Energy, the average price of a large “Type D” electric school bus is $400,000, compared with $200,000-$250,000 for an equivalent diesel bus. Charger costs can range from $596 per port for a low-power dual-port Level 1 station to $140,000 for a 350-kW single-port DC fast charger. School districts expect to see significant savings from lower fuel and maintenance costs for electric buses.
This HVIP set-aside funding will be available to public school districts, public charter schools, joint power authorities, county offices of education and the California Department of Education’s Division of State Special Schools. Applicants must be in small- or medium-sized air districts — the state entities responsible for regional air quality planning and monitoring.
“The program prioritizes applicants located in low-income and disadvantaged communities in small and medium air districts that have historically had limited access to funding for investments in zero-emission transportation,” CARB said.
CARB will accept applications for the program until Sept. 29. Applicants must submit a letter of intent, a copy of the vehicle registrations for the buses they intend to replace and “preliminary information regarding existing and planned charging infrastructure.”
