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November 16, 2024

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Retail Anti-competition Bill Hits Snag in Arizona

A bill that would close the door to electric retail competition in Arizona has hit a snag in the state legislature.

House Bill 2101 sponsored by Rep. Gail Griffin (R) cleared two committees but failed 26-29 on the House floor on Feb. 14. Lawmakers approved a motion from Rep. Andres Cano (D) to reconsider the bill within 14 days. As of Tuesday, the bill hadn’t been voted on again.

HB 2101 would repeal a 1998 law that was intended to give customers a choice of electricity service providers in the service territories of both investor-owned utilities and consumer-owned “public power entities” (PPEs).

But the competition envisioned by the law never materialized. Although the Arizona Corporation Commission (ACC) adopted rules to allow competition, the rules were shot down by a 2004 appellate court ruling.

Now, proponents of HB 2101 say competition should be rejected to maintain reliable electric service.

During a committee hearing last month, many bill supporters cited the February 2021 winter storm in Texas that left millions of residents without power for days in subfreezing temperatures and contributed to the deaths of more than 200 people. Customers have retail electric choice in much of Texas.

“I’m not ready to gamble on a company that may not have a smart group of implementers,” said Rep. Teresa Martinez (R), a member of the House Committee on Natural Resources, Energy and Water. “We’re literally playing with people’s lives when it comes to water and energy.”

Others expressed concerns that allowing competition would lead to “cherry picking” of lucrative accounts.

With competition, Arizona’s existing utilities would serve as providers of last resort, being left to serve the costliest customers, said Molly Greene, senior director of state and local government relations for Salt River Project. The Tempe-based PPE with more than 1 million customers supports HB 2101, Greene said.

“The bill protects customers by eliminating the antiquated, defunct provisions that were contemplated a quarter century ago and never materialized,” Greene said.

Clean Energy Offerings

But Travis Kavulla, vice president of regulatory affairs for NRG Energy Inc., said there would be safeguards to protect customers in the event of electric competition in Arizona. NRG is an energy producer and retailer, as well as the parent company of Green Mountain Energy, which wants to do business in the state. HB 2101 would cut off that opportunity, Kavulla said.

NRG customers continue to pay utilities’ rates for upkeep of the grid, Kavulla said. In addition, Arizona customers would pay a “standby fee” for utilities’ prior investments in generation.

“Monopolies don’t like to be competed against, and in my experience they will do or say anything to deprive their customers of a choice in provider,” Kavulla said in written testimony to the committee.

Green Mountain Energy provides customers with 100% renewable energy. In contrast, Kavulla said, Arizona’s monopoly utilities have lagged in providing renewable energy.

The House NREW committee passed HB 2101 on a 10-2 vote on Jan. 18. The House Rules Committee then voted 8-0 in favor of the bill on Feb. 7.

Meanwhile, a companion bill in the Senate, SB 1631, was passed Feb. 16 by the Senate Committee on Natural Resources, Energy and Water on a 5-4 vote.

Green Mountain Application

Green Mountain Energy submitted an application to ACC in August to provide competitive electric generation services within the territories of the state’s largest investor-owned electric utilities, Arizona Public Service Co. and Tucson Electric Power Co.

Green Mountain Energy is licensed to provide electric service in 11 states, according to the application.

In its application, Green Mountain said it would offer annual fixed-price contracts to residential customers. Commercial and industrial customers would have a choice of fixed-price or indexed-price contracts. Green Mountain is asking the commission to approve a maximum price for the company’s electric generation services.

The application is on hold while the commission waits for an attorney general opinion on how to proceed.

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SoCalGas Proposes Hydrogen Pipelines

Southern California Gas proposed plans Thursday for what could be the largest green hydrogen infrastructure in the nation, with pipelines moving hydrogen from solar farms in the Mojave Desert and other inland areas to customers in the Los Angeles Basin.

The preliminary plan submitted to the California Public Utilities Commission proposes “one or more trunk transmission pipelines that would run from green hydrogen generation sources,” where renewable resources would be used to manufacture hydrogen, an energy-intensive process.

“The project would benefit ratepayers and the state by advancing California’s net zero goals, increasing use of clean fuels” and help to “facilitate the ultimate closure of [SoCalGas’] Aliso Canyon underground gas storage facility,” site of a massive natural gas leak in 2015, the utility’s application to the CPUC said.

SoCalGas asked the commission only for a memorandum account to keep track of expenses, for possible cost recovery later, as it pursues early-stage research and development. It requested that the CPUC approve the account by July. But it said the proposal was significant enough, “given the innovation and broad environmental benefits … [that] SoCalGas believes it important to provide the commission and the public with information about the project and its context in this first filing.”

“In one or more subsequent filings, SoCalGas expects to seek commission approval of the project and recovery of just and reasonable costs incurred,” it said.

SoCalGas is the largest gas utility in the U.S., with 5.8 million customer accounts and more than $3.6 billion in sales in 2020, according to the American Gas Association.

Hydrogen Hub

The application added to the focus on Los Angeles as a center of green hydrogen development.

The Los Angeles Department of Water and Power (LADWP) is converting its coal-fired Intermountain Power Plant in Utah to an 840-MW combined cycle natural gas-fired facility. The plant will be capable of burning a fuel mixture consisting of 30% hydrogen when it opens in 2025, transitioning to 100% by 2045, the utility has said.

A report published last March by the National Renewable Energy Laboratory — titled “LA100: The Los Angeles 100% Renewable Energy Study” — showed that LADWP will require a large amount of dispatchable generation closer to home to reach a 100% clean-energy goal and replace four outmoded natural gas plants that need to be rebuilt or retired.

The Los Angeles City Council voted in September to require that 100% of the electricity used in the city be carbon-free by 2035, establishing a 2030 deadline for replacing the gas-fired plants.

And the Green Hydrogen Coalition has been leading development of a green hydrogen hub in Southern California. The goal of the HyDeal Los Angeles initiative is to deliver green hydrogen for the Los Angeles Basin at $1.50/kg by 2030.

In a probable boost to that effort, the $1.2 trillion infrastructure bill passed by Congress in November provides $8 billion for development of four green hydrogen hubs in the U.S. and $1 billion toward domestic production of the electrolyzers needed to produce hydrogen, part of the Department of Energy’s Hydrogen Energy Earthshot initiative. (See ‘Ecosystems’ Needed to Drive Green Hydrogen Growth.)

SoCalGas said its new plan, called “Angeles Link,” could provide the green hydrogen needed to convert the four outdated gas plants to cleaner generation and displace up to 3 million gallons of diesel fuel per day, if heavy-duty diesel trucks are replaced by hydrogen fuel-cell trucks.

“As contemplated, the Angeles Link would deliver green hydrogen in an amount equivalent to almost 25 percent of the natural gas SoCalGas delivers today,” the utility said in a news release.

LADWP praised the effort.

“We are encouraged that SoCalGas is embarking on a major project that will help make green hydrogen a reality here in Los Angeles,” LADWP General Manager Marty Adams said in the SoCalGas statement. “Developing a source of safe, affordable green hydrogen is key to achieving our clean energy future by 2035, while ensuring the reliability we all need and depend on.”

Spotty Record

California is legally mandated to replace all fossil-fuel generation serving retail customers with clean-energy resources by 2045 and to reduce greenhouse gas emissions 40% below 1990 levels by 2030. How a partial replacement of natural gas with green hydrogen might play out under the mandates is untested and could prove problematic.

SoCalGas said in its application that green hydrogen could help decarbonize “‘hard-to-electrify industries,’ electric generation and the heavy-duty transportation sector” while advancing “progress toward net zero goals.”

The CPUC has yet to take any action regarding SoCalGas’ application.

The utility has wrangled with its regulator in recent years, being punished for misdeeds — including a nearly $10 million fine earlier this month — that the pipeline announcement appears geared to partly offset in the public eye.

SoCalGas’ past run-ins with the CPUC include the long-running Aliso Canyon controversy, which resulted in a CPUC investigation and continued oversight. It also generated last year’s $1.8 billion legal settlement between plaintiffs, SoCal Gas and parent company Sempra Energy.

In April 2019, the CPUC fined SoCalGas $8 million for failing to send out prorated customer bills in a timely manner, resulting in higher bills and extending the billing period for many customers.

On Feb. 3, the CPUC fined SoCalGas $9.8 million for misspending ratepayer funds for advocacy work on building codes. The commission had prohibited such activities in 2018 after its Public Advocates Office determined SoCalGas inappropriately used ratepayer money to fight energy-efficient building standards.

In its proposed decision, the CPUC said SoCalGas had shown “profound, brazen disrespect for the commission’s authority” during the investigation and deserved to be penalized.

The company said in a brief statement it was reviewing the decision and looked forward to “further engagement.” It has 30 days from the issuance date to challenge the ruling, after which the proposed decision becomes final.

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PPL Announces Losses, Dividend Cut in Q4 Call

PPL’s (NYSE:PPL) stock price took a sharp hit Friday as the company announced during its fourth-quarter earnings call that it was cutting dividends in half and missed earnings and revenue targets.

The company announced it will reduce its quarterly common stock dividend to 20 cents/share from $41.5 cents last quarter. PPL’s stock price dropped 7.25% in trading, finishing the day at $26.10.

CEO Vincent Sorgi said PPL’s year was marked by a “strategic repositioning” of the company, including the sale of its U.K. utility business Western Power Distribution for 7.8 billion pounds ($10.7 billion) to National Grid and the purchase of the London-based company’s Rhode Island utility, Narragansett Electric, for $3.8 billion. (See PPL to Sell UK Business, Acquire Narragansett Electric.)

“2021 was very much a transition year for PPL,” Sorgi said. “It was about reimagining PPL and laying a firm foundation for the company’s future growth and success, and I believe we achieved just that.”

Narragansett Purchase

Sorgi said PPL anticipates receiving a final order from the Rhode Island Division of Public Utilities and Carriers regarding the Narragansett acquisition by March. PPL received FERC approval for the purchase in September, but the utility needs final approval from the PUC for the deal to go through. (See FERC Approves PPL Acquisition of Narragansett.)

Sorgi highlighted PPL’s utility experience, customer satisfaction and innovation as reasons the company is confident it will ultimately win regulatory approval for Narragansett’s acquisition. He said PPL has been a “clear leader” in the development and deployment of the kind of smart grid technology Rhode Island will need in achieving its decarbonization goals.

“We think we’ve met the standard for approval in the state, and we are looking forward to the decision coming out from the division,” Sorgi said. “We are all very focused on getting this deal over the goal line and bringing real value to our line.”

Infrastructure and Storm Damage

Sorgi also highlighted PPL’s response to significant storm damage in its service area, including a major December tornado outbreak in Kentucky and the remnants of Hurricane Ida in Pennsylvania in September.

Vince-Sorgi-(PPL)-FI.jpgVince Sorgi, PPL CEO | PPL

More than 500 transmission and distribution poles were destroyed from the storms in Kentucky, Sorgi said, but PPL restored power to most of its customers within 48 hours. Crews were also able to restore power in Pennsylvania despite historic flooding from the hurricane, Sorgi said, and PPL was recognized with an Edison Electric Institute Emergency Response Award for its restoration performance.

“When severe weather struck either in Pennsylvania or Kentucky, we responded quickly and effectively,” Sorgi said. “This performance is the result of the investments we have made in our grid and our dedicated employees who pride themselves on delivering the superior level of service each day.”

CFO Joe Bergstein said the capital investments made in the states last year aided in the support of grid modernization, resilience and reliability. In Pennsylvania, the company focused on distribution reliability and advancing IT systems, while transmission investments included smart relays, equipment monitoring and automation. Kentucky investments were primarily related to replacing aging transmission infrastructure, resulting in a total rate-base growth of about 6% in the state even as rates related to coal-fired generation facilities fell.

Operating Results

Friday’s lowered dividend payment was based on projected earnings per share from PPL’s existing business operations in Pennsylvania and Kentucky and the company’s targeted payout ratio of 60 to 65%. Because earnings from the former U.K. operation are now excluded, using the targeted payout ratio, the dividend was reduced.

The fourth-quarter earnings included special expenses of $29 million linked to the Narragansett acquisition and the sale of its U.K. utility.

The company reported a 2021 net loss of $1.48 billion (‑$1.93/share), compared with $1.47 billion ($1.91/share) in 2020. The earnings losses included special-item after-tax expenses of $2.29 billion ($2.98 per share) attributed to the discontinued U.K. operations, a U.K. tax rate change and a loss on the “early extinguishment” of debt.

However, earnings from ongoing operations in 2021, which excludes special items, was $806 million ($1.05/share), compared to $774 million ($1/share) in 2020. The company reported quarterly earnings of $134 million ($0.18/share), compared with $290 million ($0.38/share) in the fourth quarter of 2020.

PPL reduced its debt position by $3.5 billion, and it completed $1 billion in stock repurchases. Bergstein said the debt reduction was “one of the key financial highlights for 2021,” with a significant amount of the sale of WPD proceeds going to “strengthen PPL’s balance sheet.”

“We had a unique opportunity to establish one of the leading credit profiles in the sector, an attribute we see is increasingly important with the growing capital needs to fund the clean energy transition and now amid the backdrop of rising interest rates,” Bergstein said.

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Con Edison 2021 Earnings Jump 22%

Consolidated Edison’s (NYSE: ED) earnings rose 22.3% to $1.35 billion ($3.86/share) last year on higher electric, gas and steam revenues, the company reported last week.

The company earned $224 million ($0.63/share) in the fourth quarter, compared with $43 million ($0.13/share) in the same period a year earlier, after winding down a loss related to its investment in the Mountain Valley Pipeline.

“Once again in 2021, our employees continued to provide safe, reliable service to our customers throughout the unprecedented challenges of the pandemic, and our focus on delivering investor value remains strong,” CEO Timothy Cawley said in a statement. “Our expanded clean energy commitment reflects our dedication to lead the transition to renewables, gives our customers greater control over their energy use, and builds a more resilient grid.”

Con Edison said it aims to invest in, build and operate innovative energy infrastructure, advance electrification of heating and transportation, and transition away from fossil fuels to a net-zero economy by 2050.

The company last month released an investment plan targeting capital investments this year of about $4.6 billion, and $11 billion in aggregate capital investments over 2023-24.

Con Edison also last month submitted to the New York Public Service Commission a rate case for an 11.8% increase in electric rates and higher gas rates to become effective next January (22-E-0064).

The timing of the rate hike request proved awkward, as within two weeks many city customers were shocked to see sharp increases in their monthly Con Ed bills.

Gov. Kathy Hochul asked Con Edison to review its billing practices; she also announced increased relief efforts to reach low-income New Yorkers, making millions of dollars in aid available.  

“Even though the spikes we are seeing in electricity, natural gas and fuel prices were predicted and are due to severe winter weather, I am calling on Con Ed to review their billing practices because we must take unified action to provide relief for New Yorkers, especially our most vulnerable residents,” Hochul said.

Con Edison also must resolve several regulatory concerns before being authorized to build a new $4 billion substation complex in New York City dedicated to interconnecting offshore wind projects. (See Con Ed to Refine $4B Offshore Tx Plan for NYC.)

In October, Con Edison subsidiary Orange and Rockland Utilities (O&R) entered a joint proposal for new electric and gas rate plans for the three-year period through 2024, subject to regulatory approval.

Con Edison is one of the country’s largest investor-owned utilities, with approximately $12 billion in annual revenues and $63 billion in assets. CECONY is its regulated utility providing electric, gas and steam service in New York City and Westchester County, New York, while O&R serves customers in a 1,300-square-mile-area in southeastern New York and northern New Jersey.

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Report: Challenges Ahead in Maine Power-to-Fuel Pilot Search

Maine has many options and challenges ahead in the search for a pilot project to demonstrate the benefits of renewable power-to-fuel (PTF) facilities for the electric grid, a recent Public Utilities Commission report said.

“PTF facilities and the technologies that are available are highly operational and location specific,” which leaves a lot of open questions before a pilot is identified, said Matthew Rolnick, PUC staff analyst.

While there are extensive PTF studies and pilots in the U.S., most are relatively new and do not have results available yet, Rolnick said during a Feb. 15 Energy, Utilities and Technology Committee (EUT) meeting.

“It’s hard to know when those results will be coming online … so it’s still very early days,” he said.

Rolnick presented findings to the committee from its initial study of PTF pilot program feasibility, as directed by a Maine energy storage law enacted in June. The committee could use that report to inform a pilot program bill in the current session. (See New Maine Law Sets 400-MW Energy Storage Target for 2030.)

As defined by the law, PTF is the conversion of renewable energy to hydrogen, methane or “other fuel.” Possible benefits of PTF to the grid, Rolnick said, include avoiding renewable curtailment by redirecting excess generation to a hydrogen production facility and avoiding investment in transmission and distribution expansion and upgrades.

Generating hydrogen from excess renewable energy generation could support the electric grid while also reducing emissions associated with the thermal sector, the PUC said.

“There may be ways to use PTF to produce gases that could be injected into the existing natural gas infrastructure to provide carbon-free space heating to the roughly 50,000 Maine customers that currently use natural gas,” the report said.

In its review of PTF projects, the PUC identified a small pilot project in New Jersey that is demonstrating the production of hydrogen from solar and its subsequent blending into the gas distribution system. Developer New Jersey Resources (NJR) commissioned the project in October.

The New Jersey Board of Public Utilities approved cost recovery for that project, which NJR estimated will cost $6 million. Initially, the project will offset 180 tons of CO2 per year, the company said in its rate case filing.

Last year, the EUT committee considered but did not pass a PTF pilot bill (LD 9) introduced by committee chair Sen. Mark Lawrence (D). Maine-based Summit Natural Gas testified in support of the bill, saying PTF has the potential to make hydrogen from otherwise-curtailed wind energy in the state for injection into the gas system.

Increasing renewable energy in Maine is causing costly curtailments and the need for transmission investment, Summit said in its Aug. 27 comments to the PUC for the report. Building hydrogen facilities in constrained locations can reduce the impact of grid constraints and delay grid upgrades, the company said in response to a PUC request for information.

The Conservation Law Foundation (CLF) also supported the possible role of PTF in facilitating growth in the clean power sector, but it said in comments to the commission that it is “skeptical” of short-term investment in the technology. Among the nonprofit’s concerns is the risk of “inadvertently encouraging” reliance on fossil fuels.

CLF asked the commission not to recommend the legislature move ahead with a pilot, saying in Sept. 2 comments that the technology is “inarguably expensive.”

The Office of the Public Advocate agreed with the CLF’s assessment, saying that putting a high initial cost for emerging technologies on ratepayers is inconsistent with state law, according to Oct. 20 comments.

With respect to a PTF program, the OPA said, it’s not clear that Maine has “any unique attributes” that make it an “ideal” pilot host.

The PUC supported a pilot program in its report and suggested that the legislature could direct the commission to request proposals that can identify technology costs and benefits.

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FERC Approves Pause of PJM Transmission Constraint Penalty Factor in Virginia

FERC on Friday accepted revisions to PJM’s tariff and Operating Agreement that temporarily remove transmission constraint penalty factor (TCPF) rules in Virginia’s Northern Neck peninsula (EL22-26, ER22-957).

The peninsula, which encompasses Lancaster, Northumberland, Richmond and Westmoreland counties, is normally served by three transmission lines: a 230-kV line from Fredericksburg, a 230-kV from Lanexa-Dunnsville and a 115-kV line Harmony Village. But as part of a transmission upgrade project approved in 2020, PJM placed the Lanexa-Dunnsville line on outage at the beginning of the year.

That immediately created price fluctuations of the TCPF to its default rate of $2,000/MWh in the real-time energy market. PJM on Jan. 31 told FERC that the TCPF rules were creating “unjust and unreasonable energy market rates” for consumers on the peninsula.

The RTO also said the price fluctuations contributed to the default in January of Hill Energy Resource & Services, which had portfolio positions in the financial transmission rights market in the congested Dominion zone. (See PJM Weighs Options on Hill Energy FTR Default.)

TCPFs provide price signals to incent more supply or demand response. But the Northern Neck has a “few relatively small” combustion turbines, PJM told FERC, and load has not “responded significantly enough.” The line outage has resulted in “repeated instances” when no actions can relieve the transmission constraint on the other two lines, causing real-time energy market prices to oscillate between the offers of the CT plants and the TCPF of $2,000/MWh, even in the early morning hours, when behind-the-meter solar resources located on the peninsula are usually enough.

“PJM has shown that under the specific circumstances in the record, the transmission constraint penalty factor is not achieving its intended purpose in the Northern Neck peninsula and is resulting in an inappropriate price signal that establishes high prices without a commensurate benefit,” the commission said. “We therefore agree that it is just and reasonable to stop applying the transmission constraint penalty factor in the Northern Neck peninsula for a limited time.”

The RTO said the situation is expected to continue throughout the life of the project until its completion in December 2023, resulting in “significant increases in costs to load,” without an “amendment to the existing transmission constraint penalty factor rules.”

To solve the pricing issue, PJM proposed setting the transmission line limit “at a level that ensures the offers of the resources being used to control the constraint are reflected in the congestion price in lieu of applying a transmission constraint penalty factor.”

The RTO also proposed providing “regular informational filings” to the commission regarding congestion on the peninsula and to work with stakeholders on reforms to the TCPF rules if a similar situation happens in the future.

PJM requested an effective date of Feb. 1, 2022, one day after the date of its filings, because “recalculating energy market settlements is labor intensive, especially over an extended period of time.”

Protests

Several stakeholders protested PJM’s proposed changes.

Chicago-based hedge fund Citadel argued that PJM failed to demonstrate the existing TCPF rules were unjust and unreasonable. The company said PJM recorded recent scarcity pricing on the same path in August and December of 2020 and August 2021 and did not demonstrate how customers were harmed during those events and did not raise concerns at the time of those events. Citadel said there were 784 real-time intervals of prices reaching $2,000/MWh during the previous outages on the line, which “did not prompt PJM to make an emergency filing.”

DC Energy also said the outages in 2020 and 2021 created “substantially similar conditions on the remaining facilities serving Virginia’s Northern Neck” and argued that “emergency measures to eliminate the scarcity pricing signal were not justified in those circumstances and they are not justified now.”

Citadel also argued that “PJM should focus on ways to accelerate new generation development in this location as opposed to creating uncertainty around existing, market-based price signals.” The company said more than 700 MW of new solar, battery, and solar-battery facilities are planned to come online in the peninsula during or shortly after the period of the transmission outage.

Appian Way said that, because this case involves the Hill Energy default, PJM “may have responded with an excessive and unwarranted level of political sensitivity due to the historical context of the GreenHat” Energy default of 2018.

The commission said that while PJM has an existing process to temporarily relax the TCPF, the existing provisions “do not contemplate the unique scenario presented here.”

“Based on the evidence in the record, we find that PJM’s continued application of the transmission constraint penalty factor to congestion in the Northern Neck region resulting from the Lanexa-Dunnsville-Northern Neck line outage will not produce the intended short-term or long-term responses and, instead, will only result in higher costs to ratepayers without a commensurate benefit,” FERC said.

The commission said it agreed with PJM that new generation resources sufficient to relieve the constraint “could not reasonably be expected to be sited, constructed and complete the PJM interconnection process before December 2023.”

FERC also disagreed with Citadel’s argument that PJM failed to provide enough evidence for its proposal. The commission said PJM provided LMP data for the Northern Neck on Jan. 14, as well as for the period Feb. 1-14. The data were “sufficient to demonstrate the link between high prices and the transmission constraint penalty factor.”

The commission also disagreed with DC Energy’s and Citadel’s assertions that past incidences of high prices in the same area of the Dominion zone “demonstrate that PJM’s current tariff is not unjust and unreasonable.” It said the findings were “grounded in the unique circumstances” in the proceeding.

It directed PJM to submit an informational filing updating the commission on congestion patterns within 90 days of the date of the order and every 90 days after until the Lanexa-Dunnsville line upgrade is complete. The RTO was also encouraged to “consider modifications to its analyses of and planning for transmission outages to prevent such occurrences in the future.”

Danly Dissent

FERC Commissioner James Danly provided the lone dissent on the order, saying he disagreed that PJM met its Section 206 burden to demonstrate the existing transmission constraint penalty factor tariff rate is unjust and unreasonable

“As best I can make out, the high prices required by the tariff in the face of an unresolvable constraint are both too high for PJM’s liking but are simultaneously an insufficient incentive for anyone to do anything about it,” Danly said. “I am suspicious that this is a case of scarcity pricing being allowed in a market tariff only until it actually occurs, and then it must be eradicated. Markets cannot work when high prices that occur by design are disallowed in practice.”

Danly said it “does appear” that there may not be a short-term solution to the pricing issue, but he said he was “skeptical” that three weeks was a sufficient amount of time to make the determination. He said he was also concerned by the “regulatory uncertainty” making the change could cause.

“I cannot imagine how an existing generation resource in PJM can remain in business given the frequency of changes the commission repeatedly imposes on these markets, all tending to reduce prices for existing generation,” Danly said. “Today, we reduce price again, demonstrating to everyone that the mechanisms we put in place to harness market forces will be abandoned when they work as planned.”

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Vt. Maps Fast-charger Buildout for Federal NEVI Funds

With some National Electric Vehicle Infrastructure (NEVI) program guidance in hand, Vermont is already mapping out where it expects to begin building electric vehicle fast-charger stations in the coming year.

The state will receive a $3.1 million NEVI apportionment for federal FY2022, followed by four additional $4.5 million annual installments, said Patrick Murphy, sustainability and innovations project manager at the Vermont Agency of Transportation. The total $21.1 million in funding is Vermont’s part of the $5 billion allocated for NEVI over five years under the Infrastructure Investment and Jobs Act.

After reviewing the federal government’s NEVI guidelines released Feb. 10, VTrans has a preliminary plan to install or upgrade 15 fast-charger stations along federally approved alternative fuel highway corridors.

“Priority must be given to [alternative fuel corridors] … until they are deemed by the Federal Highway Administration (FHWA) to be fully built out,” Murphy said Friday in testimony to the Vermont Senate Transportation Committee.

Each station must have at least four, 150-kW ports and cannot be located more than 50 miles from another qualifying fast-charger station on a corridor. In addition, stations cannot be located more than one mile from a highway exit.

By pairing first-year NEVI funding with American Rescue Plan Act funding, Murphy said, Vermont could “come close within the next fiscal year to building out what’s required under the federal guidelines,” before it can use remaining funding for the state’s existing EV infrastructure goals. The installation cost for four 150-kW ports would be an estimated $413,000.

Vermont has an existing plan to put fast chargers along highways based on prior federal guidance for placement every 50 miles and within five miles of highway exits or interchanges and allowing for lower charging output.

Given Vermont’s rural nature, many highway exits do not have the electric infrastructure to support high output fast chargers within one mile.

“The move from the five- to one-mile distance may result in a number of requests for exceptions,” Murphy said, adding that it might also require other solutions, such as renewable energy and battery storage at some locations.

Fast-charger stations that the state has funded and built already along FHWA-approved corridors mostly have two 50-kW plugs.

“No locations on any of the corridors that we’ve had designated meet the new higher standard,” Murphy said.

NEVI guidelines call for states to complete station installations within six months of securing equipment and installation providers. That timeline, Murphy said, is “faster than any of the projects that we’ve completed to date” and could present certain challenges.

Demand for charging equipment will increase with the amount of NEVI funding that states will receive, he said. And there may be ongoing supply chain issues from the pandemic that could be compounded by Buy America requirements that the federal government has yet to clarify.

Current equipment costs also could increase as demand grows across states, Murphy said.

VTrans foresees additional difficulties arising from requirements of President Biden’s Justice40 initiative, which calls for 40% of investments to benefit disadvantaged areas. The initial guidance for locating fast-charger stations along highway corridors is “pretty prescribed,” Murphy said.

“The one-mile guidance from a highway intersection or exit clearly serves the traveling public for longer trip making, but it won’t always be compatible with a dual concern about making sure that these investments support local communities,” he said.

Murphy expects VTrans will have a draft plan for NEVI funds ready by March for stakeholder feedback, and final state plans are due for submission to FHWA by Aug. 1.

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Study Casts Doubts on Corporate Green Goals

Of five studied, large U.S.-based companies, only Apple has a fair chance of hitting its carbon reduction goals, a recent report said.

The study by the Next Climate Institute and Carbon Market Watch gives Seattle-based Amazon, California-based Google and Arkansas-based Walmart a low chance of meeting their goals, while suggesting Rhode Island-based CVS Health Corp. has only a faint chance.

Of the 25 companies examined in the report, all of which have pledged to reduce carbon emissions, Danish shipping giant Maersk stands the greatest chance of meeting its carbon goals.

The study authors admit many gaps in its structure. Each nation was limited to five companies among the 25 samples, which defined their goals differently and exhibited varying levels of transparency about their current carbon emissions and reductions plans.

The study gives only Maersk a good chance of reaching its goals. It concludes that Apple, Sony and Vodaphone have fair chances. Amazon, Google and Wal-Mart are among 10 companies with poor chances.  Eleven corporations, including CVS, have faint chances, the study said.

A breakdown of the study’s five U.S.-based companies finds that:

      • Apple’s (NASDAQ:APPL) claims to be currently carbon neutral are misleading, addressing only its administration office, business travel and employee commuting, which represents just 1.5% of its carbon footprint, the study said. The overwhelming majority of its carbon footprint comes from buying, manufacturing and transporting components. Apple’s 2030 targets call for reducing massive amounts of carbon from manufacturing. The company does not have any published interim carbon reduction targets, but it has shown steady year-by-year carbon reductions.
      • The study dinged Amazon (NASDAQ:AMZN) for a lack of details in its data, and the absence of interim reduction targets on emissions plus haziness on how emissions are defined leaves the study’s authors leery about Amazon becoming a net-zero emitter by 2040, which is the company’s goal. However, the study noted more detailed targets are expected to be published this year. Also, the study voiced concern about Amazon achieving part of its goals by investing in carbon credits related to forestry improvements.
      • Google (NASDAQ:GOOG) currently claims to be carbon neutral and plans to be carbon-free by 2030, but the study says carbon neutrality is achieved with carbon credits and that only some specific emissions are tracked. Google has a great number of anti-carbon measures in motion. The study also contends more detailed data are needed to gauge their effectiveness.
      • Walmart (NYSE:WMT) has credible interim targets and a strategy to eliminate its operational emissions by 2040, but that accounts for only 9% of its carbon footprint. Meanwhile, the retailer relies on its suppliers voluntarily reducing their emissions with no interim targets. The report recommends that Walmart make suppliers’ participation mandatory or create better incentives to participate. The company should also set specific emissions targets for its suppliers.
      • The study criticized CVS (NYSE:CVS) for “insufficient identification of emission reduction measures” to achieve a 2050 net-zero target: “We could not identify measures that CVS Health wants to implement to realize deep emissions reductions.”

Meanwhile, Maersk is decarbonizing its ship fuel, which accounts for 63% of its total emissions. However, the study contends the shipper does not have clear plans to decarbonize emissions from its supply chains and electricity use, which will likely grow as the ships switch to alternative fuels. Maersk is aiming for net-zero emissions by 2040.

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SPP Briefs: Week of Feb. 14, 2022

SPP Reaches out to Public Interest Organizations

Faced with a rapidly evolving grid’s continued focus on decarbonization and a resource mix to match, SPP is working to strengthen its relationship with public interest organizations (PIOs) and the interests they represent.

Staff told the Corporate Governance Committee (CGC) on Thursday that they have held two meetings this year with PIOs and stakeholders to discussion the grid operator’s governance structure and their straw proposals.

The subjects have included expanding qualifications to sit on the Board of Directors and the Nominating Committee’s search criteria; eliminating membership withdrawal deposits for PIOs; adding even more transparency to SPP meetings; and providing a role for Western regulators before their utilities become RTO members.

“I’m encouraged by the nature of the conversations that are taking place,” board Chair Larry Altenbaumer said.

Staff said they find PIOs offer value to SPP because they have “an unbiased perspective” in reviewing policy and market design proposals that serve the larger interests and because they tend to be actively engaged in state, regional and interconnection-wide generation, and regional market and transmission planning forums, particularly in the Western Interconnection.

Their participation is motivated by the end state of evolving market design and rules to support future technology. SPP says a decarbonized grid is essential and the evolving grid’s economics warrant change, including regional coordination of energy needs.

“We’re very, very encouraged with the past few months and very, very encouraged by the items under consideration,” said Kylah McNabb, an energy consultant representing the Sustainable FERC Project. “We do understand it’s a process. Taking a look at these items is the start of a larger conversation that will take place in coming weeks.”

McNabb indicated to the CGC that her organization is all but certain to soon submit its membership application to SPP. The organization, based in Oklahoma City, is a partnership of state, regional and national environmental and other PIOs working to expand clean energy’s deployment and to reduce and eventually eliminate carbon pollution from the power sector.

SPP currently has only one PIO member in the Lignite Energy Council. However, that sector could grow should the RTO reclassify alternative power members Advanced Power Alliance (APA) and American Clean Power Association, the grid operator’s newest and 110th member, as PIOs.

Western Resource Advocates, which spoke for consumers during SPP’s failed bid to integrate the Mountain West Transmission Group, is also considering membership in the RTO. (See Xcel Leaving Mountain West; SPP Integration at Risk.)

APA’s Steve Gaw, who helped facilitate the discussions with the PIOs, said, “There’s still more conversation ahead on this. When I look at the issues that are there, I feel like the attempts to find paths forward have been very positive and help educate and understanding on both sides has been worthwhile.”

SPP said it is pursuing “something more appropriate” for PIOs related to their membership withdrawal deposits. Staff have proposed three categories: $150,000 for load-serving entities, $50,000 for non-LSEs, and $12,000 for PIOs, consumer advocates and other similar groups.

CGC OKs Future Grid Group

The CGC approved the 17-person roster for the Future Grid Strategy Advisory Group, which will be responsible for providing periodic assessments of the RTO grid’s future state.

“We’re very pleased. … We really hit a home run with what we’ve got here,” COO Lanny Nickell said in presenting the group’s nominations, a reference to the group’s wide range of expertise. Its members represent investor-owned utilities, public power and governmental agencies, and independent transmission companies, while bringing expertise in transmission and generation planning and regulatory backgrounds.

Noting 11 of the members are in upper management, Nickell said, “I think we hit the mark there, as well.”

The group was approved in December and will identify gaps between future state projections and current trajectories, and increase organizational awareness of opportunities to shape the grid.

The team is chaired by Mark Ahlstrom, vice president of renewable energy policy for NextEra Energy Resources, with SPP’s chief information security officer, Sam Ellis, serving as staff secretary. The advisory group’s full roster can be found here.

The CGC also recommended:

      • that Google’s Will Conkling replace Jeff Riles, who recently left the company to be director of energy markets at Microsoft, as the large retail sector’s representative on the Members Committee; and
      • EDF Renewables’ Arash Ghodsian to be chair of the Generation Interconnection User Forum.

Committee members met in executive session to discuss the board vacancy created by Graham Edwards’ departure at the end of last year. The search process for his replacement didn’t begin in time to be included with the selection of SPP’s two newest board members, cyber expert Ben Trowbridge and utility veteran John Cupparo. (See “Members Elect 2 New Directors,” SPP Board of Directors/Members Committee Briefs: Jan. 25, 2022.)

M2M Settlements Reach $243M

SPP accrued $29.39 million in market-to-market (M2M) settlements from MISO during November in what staff termed “a very exciting month” during Friday’s Seams Advisory Group meeting.

The total was the second highest since the RTOs began the M2M process in March 2015, exceeded only by the massive $51.49 million settlement in MISO’s favor last February, in large part because of that month’s severe winter storm.

Staff said the M2M process also settled in SPP’s favor in December at $10.25 million. It was the 10th straight month the process settlements have been in the green for SPP and the 25th time in the last 27 months. Settlements in SPP’s favor now total $243.31 million.

Permanent and temporary flowgates were binding for more than 5,700 hours in November and December, compared to 1,875 hours in October. The grid operators exchange settlements for redispatch based on the non-monitoring RTO’s market flow in relation to firm-flow entitlements.

Staff’s Neil Robertson told SAG members that SPP and MISO are planning a series of stakeholder meetings through midyear to discuss cost allocation for their joint targeted interconnection queue (JTIQ) study, which last month identified a $1.755 billion portfolio of suggested projects. (See MISO, SPP Roll out $1.755B Joint Tx Portfolio.)

The grid operators will also raise the subject during Tuesday’s meeting of their state commissions’ staffs as they look to involve the regulatory community.

“We’re better off trying to get onto the front end versus waiting for a baby to be dropped on the doorstep,” said Adam McKinnie, an economist with the Missouri Public Service Commission.

Robertson also said the Joint Planning Committee, comprising single representatives from MISO and SPP, will soon meet to consider suggested projects submitted during the grid operators’ Feb. 15 Interregional Planning Stakeholder Advisory Committee meeting. The grid operators plan to conduct a targeted market efficiency project (TMEP) study this year, focusing on smaller projects Robertson referred to as “TMEP-like”. (See MISO, SPP Take on 2nd Interregional Planning Effort.)

The RTOs expect to complete the study’s report and recommendations in August.

In reviewing their 2022 SAG work plan, members added a placeholder for Western services expansion to account for SPP’s many initiatives in the Western Interconnection. The group’s work plan also includes support for the TMEP development and JTIQ cost allocation work, and supporting SPP with seams-related activities in executing the RTO’s strategic plan.

MOPC, Board Meetings Moved to Dallas

SPP has moved its April governance meetings, originally scheduled for Little Rock, Ark., and Kansas City, Mo., to Dallas because of “challenges and uncertainty” its stakeholders have faced in making travel arrangements.

The Markets and Operations Policy Committee will be held April 11-12 and the Strategic Planning Committee on April 13. The Regional State Committee and quarterly joint stakeholder update is scheduled for April 25, with the board and Members Committee meeting April 26.

SPP encouraged stakeholders who are sick or who have been in close contact with someone infected with COVID to participate online. Unvaccinated attendees are “encouraged” to wear masks, but social distancing will not be enforced because of space limitations.

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FERC Reverses Itself on NYISO BSM Exemptions

FERC on Thursday voted 4-1 to accept revisions to NYISO’s buyer-side market power mitigation (BSM) measures designed to prioritize evaluating New York state-subsidized resources, reversing its decision in September 2020 to reject the ISO’s proposal (ER20-1718-002).

The BSM measures are designed to prevent uneconomic resources from entering NYISO’s capacity market. Under Part A of the mitigation exemption test, the ISO exempts a new entrant from the offer floor if the forecast of capacity prices in the first year of a new entrant’s operation is higher than the default offer floor. Its proposed revisions, submitted to FERC in April 2020, would to place “public policy” resources (i.e., renewable resources, battery storage and other zero-emission resources) ahead of nonpublic policy resources in its evaluations.

NYISO argued that in light of New York state legislation, including enactment of the Climate Leadership and Community Protection Act (CLCPA), subsidized resources were more likely to be completed. Unlike in 2020, under a Republican majority, the commission this time agreed.

Capacity requirements overview (NYISO) Content.jpgNYISO

 

“We are persuaded by evidence in the record indicating that NYISO’s proposed resequencing of resources is just and reasonable because it will minimize artificial capacity surpluses, which, as NYISO’s Market Monitoring Unit [Potomac Economics] explains, would otherwise occur ‘because the current Part A test can provide inefficient incentives for investment in new resources that are not needed,’” the commission said.

In addition to the CLCPA’s binding targets, the commission said that the Accelerated Renewable Energy Growth and Community Benefit Act provides for fast-track environmental review and permitting for major renewable energy facilities, and a number of nonpublic policy resources are expected to exit the market as a result of the state’s new “peaker rule” limiting NOx emissions.

FERC directed the ISO to submit a compliance filing within 30 days proposing a new effective date for the revisions no later than Aug. 1, the start of the next class year.

Reversal

FERC had approved several other of NYISO’s proposed revisions to the BSM measures in September 2020, including a formula that limited the amount of renewables that could be exempted. But its rejection of the Part A changes prompted a dissent from then-Commissioner Richard Glick and rehearing requests by the ISO, Equinor, New York Transmission Owners, the New York State Energy Research and Development Authority and the New York Public Service Commission. (See FERC Rejects NYISO Bid to Aid Public Policy Resources.)

The Republican majority at the time said NYISO’s plan was “unduly discriminatory because it does not provide sufficient justification for prioritizing the evaluation of public policy resources before nonpublic policy resources, independent of cost.”

Commissioner James Danly, now in the minority, said in a dissent that “the justifications offered in this order are simply unconvincing.”

“Our duty is to ensure just and reasonable rates pursuant to the [Federal Power Act], and not to determine whether NYISO’s proposal is consistent with federal, state, or municipal renewable energy policies,” Danly said.

Fellow Republican Commissioner Mark Christie concurred in a separate statement, taking exception to the majority’s reasoning.

“New York’s state law is discriminatory in its expressed preference for certain types of resources,” Christie said, while noting that the FPA does not pre-empt the state from doing so. “Does this make the NYISO’s tariff revisions — through which NYISO is acting necessarily to accommodate the reality of New York’s laws — produce rates that are ‘unjust, unreasonable and/or unduly discriminatory’ under the FPA? Under an ‘as-applied’ analysis of this specific, single-state ISO filing by NYISO — and under a practical approach — I do not find it so.”

Christie also said that there is no evidence that NYISO’s proposal would harm consumers in other states, and “if the people and businesses of New York do not like the impacts of their new state laws, their recourse is to the ballot box,” Christie said.