Page 973 – RTO Insider

February 28, 2021November 2, 2023

Hawaii Bill to Fund Small Landowner Carbon Efforts

A bill to make carbon offset projects affordable for small landowners is making its way through the Hawaii legislature.

Senate Bill 493 would establish an “agriculture and forest carbon-positive incentive program” to encourage small agricultural producers to reduce emissions by helping them pay for carbon sequestration efforts and clean energy use. Part of the state’s effort to reach carbon neutrality by 2045, the program is intended to create jobs and stabilize the food and water supply for a state almost entirely dependent on shipped goods.

The text of SB493 notes that “while carbon offset credits pay for carbon-positive actions, certification is cost prohibitive to small landowners. Incentivizing carbon-positive actions through a payment of services program would allow small farmers, ranchers and landowners to be compensated for taking actions to help Hawaii reach its climate-positive goal.”

The incentive program would be broken into two phases. Phase I activities would help farmers, ranchers and landowners implement a regenerative annual cropping system; improve pastureland, including growing trees and shrubs around pastures (agroforestry); engage in reforestation; protect land from disturbance; institute rotational grazing; and improve foraging.

Phase II activities would focus on energy creation and consumption. The program would cover, “but is not limited to,” biofuel production, methane capture, improved forest management, grazing intensity, mixed production systems, and efficient nutrient and waste management.

Details of SB493 are being debated, including how the incentives would be funded. The current bill proposes to create a special fund to be financed, in part, by revenue from the state’s Environmental Response, Energy and Food Security Tax. That tax was established in 2010 to discourage fossil fuel use and fund energy and food-security initiatives by adding $1.05/barrel tax to all petroleum products except aviation fuel. The bill also calls for unspecified funding from the state’s general revenue.

Various state agencies would have a hand in the program. Hawaii’s Department of Agriculture and Department of Land and Natural Resources (LNR) would establish compensation rates and contract terms for the program, with terms ranging from one to 30 years. The Hawaii Green Infrastructure Authority (HGIA) would establish and chair a committee to review applications, with participation from Agriculture and LNR. Eligibility would be determined at the point of application.

General administration of the program would fall to the HGIA and the state’s Greenhouse Gas Sequestration Task Force (GHGSTF), which was established in 2018 under the auspices of the Office of Planning (OP) to harmonize the state’s climate initiative goals with its clean energy and carbon sequestration efforts. The GHGSTF would be required to identify a number of program co-benefits, such as job creation; food security and agriculture for local consumption; water security; increased biodiversity; soil health; and invasive species reduction and removal.

Who’s in Charge?

The GHGSTF addressed SB493 during a Feb. 16 meeting, in which members also discussed various reports and plans pertaining to Hawaii’s broader 2045 carbon-neutral goal. During the meeting, OP Director and GHGSTF Chair Mary Alice Evans expressed concern that the task force does not have enough funding to meet its goal of providing state lawmakers with key reports.

“We weren’t able to get additional funding due to the pandemic, so we will have to make do with the vast expertise of our members to be able to meet at least the interim report and hope that by the time we get to the interim report that there are funds available to finish up the final report to the legislature,” Evans said.

In its Feb. 5 testimony on the bill, the GHGSTF explained that its role of identifying and prioritizing carbon-positive activities is jeopardized by a chronic lack of funding. Evans said, “The OP has struggled providing administrative support to the Greenhouse Gas Sequestration Task Force. Since 2018, the OP has noted this need for additional staffing and funding to support the task force’s work.” The GHGSTF’s Feb. 16 meeting was being held after “a yearlong hiatus because of these significant funding and staffing challenges,” Evans said.

Other testimony submitted Feb. 5 showed strong support for the bill, including from the LNR Department, the HGIA, the Sierra Club and the Environmental Caucus of the Democratic Party of Hawaii, along with smaller groups and individuals.

The Tax Foundation of Hawaii acknowledged the potential benefits of carbon sequestration but questioned whether they “justify grabbing a pot of barrel tax money without going through the normal budgeting process that also considers sweltering primary schools, underfunded state pensions, or disaster relief for rain-flooded or lava-burnt counties, as well as the economic decimation wrought by COVID-19.”

The group suggested that “a direct appropriation of general funds would be preferable” and that “earmarking revenues from any tax type for a particular purpose decreases transparency and accountability.” It also contended that Hawaii State Energy Office or Department of Agriculture would be better suited to administer the program than the HGIA.

The Agriculture Department testified that “the measure assigns extensive and unfamiliar responsibilities to the Department of Agriculture and the Department of Land and Natural Resources. … The department will need substantial assistance to acquire the appropriate expertise to develop compensation rates and carbon incentives contract terms, estimate sequestration rates for priority sequestration activities, develop the technical underpinning of compensation rates for sequestration activities, and conduct landowner outreach.” The agency also wondered what program beneficiaries would consider to be “fair compensation.”

Questioned about the probability of the bill passing, Evans told NetZero Insider that “the 2021 legislative session ends on April 29, and we often don’t know the fate of specific bills until the session adjourns.”

February 28, 2021

Mass. EV Subsidy ‘Isn’t Enough,’ Energy Office Says

If Massachusetts is going to achieve its plan to have entirely electric new car sales in 2035, it needs to take a “hard look” at what low- and moderate-income households can afford in the electric vehicle transition, Daniel Gatti, director of clean transportation policy for the Massachusetts Executive Office of Energy and Environmental Affairs, said Thursday.

The state offers a $2,500 subsidy for an EV purchase, but that is not enough to make the transition financially feasible for people with an annual income of less than $75,000, Gatti said during an EV webinar presented by Green Energy Consumers Alliance.

EVs currently make up less than 5% of new vehicle sales in Massachusetts, according to Gatti. A disproportionately large number of EV sale rebates under the state’s MOR-EV subsidy program are going to Tesla buyers, according to the Center for Sustainable Energy. The program data show that from March 2020 to February 2021, 47% of MOR-EV rebates were for Teslas, which MotorTrend estimates range in price from $39,000 to $81,000.

Massachusetts EV Subsidy — Expansion of publicly available charging infrastructure, as seen here, could make it easier for renters in Massachusetts to switch to EVs. | *Shutterstock*

Janelle London, co-executive director of the West Coast nonprofit Coltura, said that state EV subsidies focus on the purchase of new vehicles and do not “change the fundamentals of car ownership.”

Typically in the U.S., Coltura said, wealthier people buy new vehicles and everyone else buys used vehicles. Policies that call for all new car sales to be EVs do not change that model and instead encourage automakers to compete for business in the EV market, she said.

Last December, Massachusetts joined Connecticut, Rhode Island and Washington, D.C., in the Transportation and Climate Initiative Program, a regional cap and invest program to cut emissions from gasoline and diesel fuel by 26% before 2032. A minimum of 35% of program funds is set aside to benefit overburdened and underserved environmental justice communities. In addition, Gatti estimated that the program will provide up to $300 million for transportation infrastructure upgrades to support EVs.

Last month, the Massachusetts Department of Environmental Protection announced a new initiative to help install publicly available direct current fast charging stations, along with a program to encourage apartment buildings to install charging stations for residents.

“These investments will make it easier for tenants and Massachusetts residents who do not have access to off-street parking to make the jump to an electric vehicle,” Gatti said.

The EV transition, however, has the state energy office thinking carefully about what changes will be necessary for the power grid.

“It is going to require a really modern grid that is capable of doing more complex things than our grid is doing right now,” he said.

February 26, 2021

Avangrid CEO Touts Renewable Energy Future

Avangrid CEO Dennis Arriola this week touted the company’s installation of nearly 620 MW of new wind projects last year and said it is poised to solidify its clean energy position in 2021.

Speaking during an earnings call Wednesday, Arriola pointed to offshore wind projects and the construction of the New England Clean Energy Connect (NECEC) transmission line in Maine as critical drivers for Avangrid’s future.

The Connecticut-based subsidiary of Spanish energy giant Iberdrola reported fourth-quarter profits of $166 million ($0.54/share) and 2020 earnings of $581 million ($1.88/share).

Avangrid’s networks division serves more than 3.3 million customers in New York and New England through its eight electric and natural gas utilities, while its renewables business owns and operates renewable energy generation facilities across the U.S.

Arriola said Avangrid sees “strong prioritization of clean energy policy going forward” under the Biden administration, citing the president’s targets to decarbonize the power sector by 2035 and reach net-zero emissions economy-wide by 2050, first with several climate-focused executive orders and then through a proposed $2 trillion investment in clean energy over the next five years.

“For us, this translates into an acceleration of renewables deployment, grid enhancements and transmission projects to support growing demand for clean energy,” Arriola said.

He said NECEC is the largest clean energy project in New England and equivalent to removing more than 700,000 passenger vehicles from the road in terms of greenhouse gas emissions.

Construction of the $1 billion NECEC with Central Maine Power technically began in January, which followed a lengthy court battle over a referendum on the project that was ultimately deemed unconstitutional after tens of millions of dollars were spent by advocates for and against it.

NECEC spans 145 miles with the capacity to carry 1,200 MW of Canadian hydropower from the Maine-Québec border to Lewiston, Maine, where it will connect to the New England Control Area. The HVDC project includes upgrading 50 miles of existing AC transmission, a new converter station and substation and other upgrades. It has an in-service date of 2023.

“While we recognize there is a vocal minority in [Maine] that is basically against any infrastructure development anywhere, we remain confident that NECEC will be completed and will provide affordable clean energy and substantial economic benefits, including jobs, to the people of Maine,” Arriola said.

Avangrid currently owns 8.2 GW of renewable energy in 22 states and that portfolio is set to increase when its acquisition of PNM Resources officially closes, likely in the second half of 2021. The deal will create one of the biggest clean energy companies in the U.S., with 10 regulated utilities in six states and renewable energy operations in 24 states. (See Avangrid to Acquire PNM Resources for $4.3B.) Avangrid would become the third-biggest U.S. renewables operator, with most of its current portfolio being onshore wind, and a growing pipeline of offshore projects including Vineyard Wind and Park City Wind in New England. (Note: An earlier version of this article misstated Avangrid’s renewable capacity.)

Avangrid Renewable Energy — Vineyard Wind 1, a joint venture between Avangrid and Copenhagen Infrastructure Partners, is located 15 miles off the coast of Martha’s Vineyard and is slated to become the first large-scale offshore wind farm in the United States. | *Vineyard Wind*

Arriola said that the 800-MW Vineyard Wind, a joint venture between Avangrid and Copenhagen Infrastructure Partners (CIP) off the coast of Martha’s Vineyard in Massachusetts, now has an in-service date of 2024 as the U.S. Bureau of Ocean Energy Management resumed its oft-delayed work on the final environmental impact study and record of decision.

Avangrid also partnered with CIP to develop the 804-MW Park City project in Bridgeport, Connecticut, which has an expected in-service date of 2025. Arriola added that the recent addition of a 30% federal investment tax credit means that Vineyard Wind will “generate additional value.”

“We’re one step closer to placing turbines in the water at the nation’s first utility-scale offshore wind farm,” Arriola said.

The CEO added that Avangrid is poised to grow its renewable energy capacity “nearly 70% by 2025, with significant growth driven by offshore wind.”

Call transcript courtesy of Seeking Alpha.

February 26, 2021March 6, 2025

RTOs: Let Us Share Trading Info

FERC’s technical conference Thursday on RTO/ISO credit practices was prompted by the 2018 GreenHat Energy default in PJM. But many of the speakers found a more recent reason for concern: last week’s crisis in ERCOT, where widespread generation outages during subfreezing conditions pushed prices to the $9,000/MWh cap, prompting collateral calls and defaults among electricity retailers and municipal utilities.

RTO officials said the Texas crisis pointed to the need to consider loosening restrictions on information sharing among RTOs, while other witnesses said it highlighted the difficulty grid operators have preparing for “Black Swan” events.

The conference, which will continue Friday morning, also elicited calls for lagging grid operators to adopt best practices such as mark-to-auction reviews and balance-of-period auctions in financial transmission rights (FTR) markets. FERC’s question on whether grid operators should outsource market clearing to a third party was received coolly.

Information Sharing

RTO credit risk officials said although they meet monthly with their counterparts to share best practices, confidentiality rules prevent them from sharing market participant-specific information, even if the participant may pose a credit risk in multiple markets.

“It would be helpful to be able to know, for example, who might be experiencing financial distress right now in MISO and SPP [and] ERCOT,” said Sheri Prevratil, NYISO’s manager of corporate credit. “Because that can certainly spread across all of the RTOs and ISOs.”

PJM Chief Risk Officer Nigeria Bloczynski, who was hired following the GreenHat default, said RTOs “should be able to share information on issues they are confronting, especially with regard to certain market participants. We need transparency, not only within the RTO/ISO community to help mitigate risk, but in the broader commodity space as well.”

She said market participants with whom she has spoken agree that “there should be some method of sharing information across RTOs.”

“The critical question in information sharing is how to share and aggregate it,” MISO CFO Melissa Brown said. “If information sharing does occur, it would make sense for there to be a single, central depository of that information, with limited access and distribution. [FERC] would be one such candidate for this sort of information sharing, echoing Order 760 data. Another alternative would be encouraging greater coordination and sharing among” independent market monitors.

Brown questioned the value of credit information alone from other RTOs. “Credit is inexorably linked to market activity. Knowing one without the other would give little actionable data,” she said.

She added that the costs of sharing must be justified by its ability to prevent defaults. “MISO has experienced only a few defaults since its market start, all with very little financial impact,” she said. MISO’s largest market default was less than $1,000 for the first 15 years of market operations. In February 2021, MISO incurred two additional potential defaults of $112,046 and $15,563, which are pending final resolution.

Third-party Clearing

Costs also were cited as a reason not to consider mandatory third-party clearing of FTRs.

R. Scott Everngam, a former FERC official now consulting for regulated electric utilities, said his position on third-party clearing of FTRs has evolved as RTOs have improved “the core credit office competencies that unfortunately were lacking in the not-too-distant past.”

“I am concerned that the costs [of third-party clearing] to market participants annually could approach the costs of a major default,” he said. “Third-party clearing houses are not likely to understand fully the market design risks of FTRs and other trading products as well as the RTOs/ISOs, who could keep costs lower by their better understanding of the risks of these products.”

It could also raise jurisdictional issues if the clearing house is regulated by the Commodity Futures Trading Commission, he said.

Abram Klein, managing partner of FTR trader Appian Way Energy Partners, said he is “extremely skeptical” of the viability of mandatory third-party clearing. “We have no concern with voluntary third-party clearing if certain market participants would gain efficiencies from novating their FTR portfolios over to an exchange; for instance, if their futures positions … would offset their FTR portfolios,” he said. “However, we believe mandatory third-party clearing may be too costly and raises significant legal hurdles.”

Klein said many current FTR market participants would be excluded from the market by exchanges’ requirements. “FTRs are not pork bellies or tiger shrimp. … Clearing members, we think, are too far removed from this complex product to be comfortable taking on the scale of business that third-party clearing of FTRs would entail.”

Scott Miller, who now serves as executive director of the Western Power Trading Forum, spoke of his experience working on a clearinghouse proposal as a PJM employee and of helping to draft Order 741 while at FERC in 2010.

“We thought that we had solved the problems of FTR margins and how collateral would be required” with Order 741, he said. The GreenHat default, he said, showed “that the RTOs and ISOs were not aware of what their discretion was.”

“I think it’s time for the commission to be very direct with regard to the jurisdictional RTOs and ISOs and say: ‘You have to collaboratively come together with a best practices solution,’” he added.

Unique, Unpredictable Risks

Miller said RTO markets are different from financial or commodity markets because they depend on an ever-changing transmission system.

“While we tend to think of the commodity being traded in an RTO market as the electrons being produced, it is the transmission availability that is the value with the greatest risk in question,” he said. “Unlike a commodity that is grown, extracted, or manufactured, the transmission system necessarily changes based on the modeling of the system by the ISO or RTO.”

Miller said FERC could increase transparency by making the risk valuation model available to market participants yearly.

He said RTOs‘ risk management tools “have difficulty in measuring stochastic risk, or risk that lies outside normal experience,” such as that experienced in Texas.

“Recognizing the difficulty in assessing risks associated with outages, weather and similar ‘outlier’ events, ISOs and RTOs have tended to rely upon historic prices to assign risk,” Miller continued. “Recent experiences in electric markets make clear the need to do more dynamic forward modeling to capture stochastic risk. While this is easier said than done, it is possible. The advanced Monte Carlo scenario modeling being considered by PJM is an advancement.”

Brown said that power system reliability is “the most fundamental way to protect market stability and avoid market defaults. A robust power system promotes price certainty and removes risk, whereas an unduly stressed system, as we have seen just a week ago, causes tremendous price uncertainty and unreasonable credit risks, to say nothing of the underlying human suffering and potential loss to property.”

RTO Discretion

RTO officials defended their use of discretion in requiring additional collateral when they see increasing risk from a market participant.

“MISO believes all RTOs should have discretion and authority to respond to extreme price volatility,” Brown said. “The … infrequency and unpredictability of such events means a single standard or threshold is unlikely to prevent a default if the markets and price swings are anomalous enough. The best solution MISO has found to address these situations is to set up the rules for the center of the bell curve and have discretion and authority to act swiftly, subject to review, if extreme price volatility arises at the tails.”

Prevratil agreed. “The NYISO cannot predict the specific ways in which a market participant may present a risk of default, so it is critical that the NYISO’s tariffs maintain the flexibility to evaluate the specific circumstances of each situation,” she said.

Noha Sidhom, CEO of Viribus Energy Fund and executive director of the Energy Trading Institute, said ETI is “comfortable with some level of discretion being granted to the RTOs and ISOs regarding requesting additional collateral.

“However, we are extremely uncomfortable granting them the unilateral ability to suspend a market participant’s ability to transact,” she said in pre-filed testimony. “Just as a market participant must demonstrate sufficient risk management protocols and market expertise, it is even more critical that an RTO or ISO be able to demonstrate sufficient processes, expertise and resources to manage credit and counterparty risk.”

One Size Doesn’t Fit

Brown called for FERC to find the right balance between standardization and regional market rules.

“It is one thing to have the RTOs collaborate on intake forms, allowing potential participants to file one form instead of six,” she said. “It is much riskier to impose standard collateral requirements across different markets and products.”

Brown said managing credit risk “is more an art than a science. … Put simply, there is no substitute for people who are knowledgeable about credit and sensitive to developing risks.”

But Eric B. Twombly, a board member of the International Energy Credit Association, said RTOs have a disadvantage in evaluating “red flags” in the due diligence process because of the Federal Power Act’s prohibition against “undue discrimination.”

“Usually, this analysis in a corporate setting involves senior managers who apply subjective judgement as to the level of potential compliance or reputational risk a company and/or its shareholders are willing to accept,” he said in pre-filed testimony. “An RTO/ISO’s subjectivity can be interpreted as discriminatory.”

Actions Needed

Several witnesses had recommendations for actions FERC should take to improve RTO practices.

Klein said RTOs need to become as expert in credit risk management as they are in managing markets and ensuring reliability.

“ISO policies are developed via a stakeholder process that involves compromise,” he noted. “FERC must not allow ISOs and their stakeholders to adopt substandard [credit and counterparty risk management] policies and practices. It should be unacceptable, for instance, for any ISO not to have variation margining when a customer’s mark-to-market trading position moves into the red.”

Miller said FERC should be cognizant that RTOs’ market participants have a conflict of interest between controlling risk and minimizing costs. “In this regard, the stakeholder process often displays these conflicts rather than benefiting from varied perspectives,” he said.

Klein and others said the commission should consider requiring that all FTR markets include “regular and periodic market pricing through balance-of-period auctions,” as have been adopted by NYISO, PJM, MISO and ERCOT. “These auctions offer important liquidity, price transparency and competition to the FTR market and allow these ISOs to regularly assess and revalue market participant FTR portfolios, allowing for more accurate margining and identification of exposures.” ISO-NE, CAISO and SPP lack balance-of-period auctions, although SPP is considering it.

Nodal Exchange COO Demetri Karousos said the “key risk” to swaps trading is a “daisy chain of defaults” in which “one counterparty defaults to another counterparty, which in turn defaults to another counterparty, and so on. This is exactly what” triggered the 2008 financial crisis, with the collapse of the mortgage-backed securities market.

Karousos talked about his exchange’s proposal linking FTR auctions to futures markets. Under its proposed construct, the RTO would continue to run FTR auctions. FTRs would then be exchanged for a futures contract between the RTO and a clearinghouse. The FTR payment mechanism would be replaced with an exchange for related position, “variation margins extending from the futures contracts that are established on the exchange,” he said.

This new product “produces opportunities for secondary market trading, providing much greater liquidity … and improved hedging. It improves transparency [and provides] improved default protection.”

Rob Marsh, chief investment officer for Monolith Energy Trading, said the commission also should include mark-to-auction reviews as well as balance-of-period auctions.

“Variation margin should be utilized to secure the market to changing risk profiles. While mark-to-auction is the obvious tool for calculating variation margin, additional data, such as day-ahead and real-time price volatility and the financial condition of market participants, should be considered in the variation margin models,” he said. “No market participant should be able to clear a portfolio that they are undercollateralized to hold.”

He also called for a holistic view of credit requirements, with constant re-evaluations. “Too often, credit policy changes have been reactive rather than proactive. They are tailored to specifically address the last default, rather than comprehensively examined to determine their underlying flaws.”

Klein said the commission must eliminate RTO policies that allowed “’heads I win, tails you lose’ trading strategies,” such as those that led to the 2018 GreenHat and 2008 PowerEdge defaults in PJM, which allowed market participants to take big risks with insufficient collateral. (See Report: ‘Naive’ PJM Underestimated GreenHat Risks.)

Brown called for eliminating “shortcuts, such as allowing past FTR revenues to offset the collateral posted,” noting that transmission congestion changes over time.

The RTO officials listed the changes they have made in their rules since the GreenHat debacle, calling them evidence of a much-improved risk posture. But Sidhom said “many of the changes accepted by the commission over the past year simply require the market participant to self-report a material change.

“This is insufficient,” she said. “The burden should be placed on the RTO or ISO to conduct continuous due diligence.”

Brown acknowledged it’s too soon to say whether the recent rule changes have addressed the RTOs’ risks. “More time is likely necessary to evaluate the full value of these adjustments,” she said.

Multiple witnesses stressed the need for finding protections that don’t create unnecessary barriers to entry.

Klein criticized SPP’s proposal to require financial entities trading transmission congestion rights, its version of FTRs, to provide $20 million in unencumbered funds, excluding holding collateral at other ISOs. “Such a policy exceeds the $10 million ‘Eligible Contract Participant’ (ECP) standard noted in FERC Order 741 and may represent an unnecessary and an anticompetitive barrier to entry. We view the $10 million ECP standard as sufficient.”

Several witnesses said RTO’s credit experts should be involved in the development of new market rules. Someone like Bloczynski “should be at every single ISO and should be coordinating with market design,” said Ruta Skučas, a partner with Pierce Atwood who represents the Financial Marketers Coalition in RTOs.

Bloczynski agreed, saying “cross-departmental communication should be organic and ‘baked into’ the culture of the organization.”

Skučas said that the more targeted the products, the less credit risk the markets face. She added that a best practice is for RTOs to allow trades on any node, but it’s not available in every market. In NYISO, for example, “generators can only use virtual products at the zonal level,” so “anything happening at the nodal level, they can’t hedge.”

She also argued that participants should be able to choose between products that carry energy risk, such as PJM’s incremental offers and decrement bids, and products such as up-to-congestion transactions. “This allows for management of energy risk exposure while providing a natural link between liquid delivery points and actual physical assets,” she said. Products with greater granularity will become even more important as more intermittent resources “seek to hedge their positions,” she added.

Ted Thomas, chair of the Arkansas Public Service Commission, said FERC’s Office of Enforcement also has a role in protecting the markets. “We need to keep gamers out of our market with rigorous enforcement,” he said. “Go manipulate LIBOR. Go manipulate GameStop stock. Stay the hell out of our markets.”

February 26, 2021

AEP CEO Calls for More Stringent Reliability Measures

American Electric Power CEO Nick Akins used the company’s year-end earnings review Thursday to call for stepped-up reliability measures following a winter storm that ravaged the Texas grid.

Akins said 2020 was a year of “tremendous challenges, the likes of which we have never seen, and it appears that 2021 has thus far had its own set of challenges.”

“A little over a month into the year, and we’ve experienced ice storms in the East and record cold temperatures in the West,” Akins said.

AEP Texas followed ERCOT: Grid was ‘Seconds and Minutes’ from Total Collapse.)

“During this event, our focus centered on responding to the directives from ERCOT to ensure that the flow of available power continued throughout this crisis. We also worked with our communities to identify critical load such as hospitals and other first responder resources in an effort to mitigate the impacts of key resources within our communities,” Akins said.

Downed AEP distribution lines after last week’s winter storm | *AEP*

“This event serves as a sober reminder as to the critical nature of our nation’s energy supply and maintaining and supporting not only our economy, but also our fundamental way of life,” he added.

AEP Texas is a transmission and distribution utility in ERCOT, not a generator or a retail electric provider, Akins reminded shareholders. He said AEP expects little, “if any,” financial impact from the Texas event.

He said AEP load-shedding in SPP was minimal, but fuel costs were high during the storm. The company will seek alternative fuel cost recovery mechanisms to lessen ratepayer impacts.

Three AEP wind farms in the ERCOT region experienced cold weather outages Feb. 10, he said.

“We expect all three wind farms to be returned to full availability soon,” Akins said, emphasizing that the financial impacts from the wind outages would be immaterial.

Akins also said AEP’s Appalachian Power and Kentucky service territories sustained significant ice and tree damage to the transmission and distribution system in recent back-to-back storms. Restoration crews continue to make headway on the damage, and AEP intends to file for cost recovery of storm-related impacts, he said.

Call for Action

“These events, along with others around the country, have indicated the need for specific policy changes that focus on further refinements in reliability and resiliency of the grid,” Akins said. “Specifically, we would encourage more robust reliability assessments across electric, gas and other critical infrastructure classes determined where interdependencies exist and market designs that promote adequate capacity levels and increased generation reserve margins to provide a sufficient safety net during emergency situations.”

Akins called for winterization standards for power plants and natural gas delivery systems.

He said if “substantial” parts of the country are depending on natural gas, utilities should make sure plants and pipelines are able to perform under tight conditions. He also said better interregional transmission planning across RTOs’ seams and more DC ties into Texas can “enable regions to lean on each other in times of crisis.”

“All stakeholders must do better to address the issues that led us to these failures that have impacted so many customers at the worst possible time,” he said. “Whether it’s winter and summer weather event reliability or the speed at which the clean energy future can occur, AEP stands ready to be an active participant in resolving these issues, both from a state and national perspective.”

Akins predicted he would soon be testifying about the events. He said utilities should have greater insight into the “interaction and interoperability” of generation resources with distribution and transmission systems.

Akins said utilities need to make and announce clean energy decisions this year. He said AEP will propose in its integrated resource plan up to 330 MW of new renewable energy to serve Southwestern Electric Power Co. in the 2025-2028 time frame.

AEP has accelerated its carbon-reduction goals, targeting an 80% decrease from 2005 levels by 2030 and net-zero carbon emissions by 2050.

“I am reminded of one of my favorite movies, ‘Gladiator,’ in which Maximus Decimus Meridius says, ‘The time for half-measures and talk is over,’” Akins said. “It is time for serious execution by AEP to transform ourselves to embrace our clean energy future on behalf of and for our customers and communities.”

Earnings and Post-COVID Hopes

AEP earned $2.2 billion ($4.44/share) in 2020, compared with $1.9 billion ($3.89/share) a year earlier. The utility has upped its 2021 guidance to $4.55 to $4.75/share.

Profits were shaped by favorable taxes and investments and “certain regulatory outcomes that went our way,” Akins said.

However, Akins said AEP is disappointed in the outcome of Appalachian Power’s triennial rate case in Virginia, where state regulators in November denied the utility a rate increase.

AEP is seeking a rehearing and appeal of the decision with the Virginia Supreme Court.

“More to come on that,” Akins promised.

CFO Julie Sloat said load in AEP’s service territories generally fared better than other parts of the country because the areas had shorter and fewer economic shutdowns in response to the COVID-19 pandemic. The pandemic also provided opportunities for cost-cutting through inexpensive virtual training and travel reductions.

Sloat predicted the commercial and industrial sectors would steadily recover “as we migrate back to our post-pandemic lives” in 2021. She said load from schools, churches, restaurants and hotels is picking up, and overall load recovery “will likely track with vaccinations.”

Akins said he was optimistic about load recovery and growth in 2021. He said AEP load still trails pre-COVID levels but is improving. A push to harden grid infrastructure, especially following last week’s winter storm, should also bolster industrial load, he said.

Despite the obstacles of 2020 and early 2021, Akins predicted a promising year as the nation emerges from the pandemic. He paraphrased the lyrics to Johnny Nash’s “I Can See Clearly Now”: “I can see clearly now the rain has gone — and we can remove all obstacles in our way to a bright sunshiny day.”

February 26, 2021

New PG&E CEO Promises ‘Hometown Experience’

During a conference call Thursday, new PG&E Corp. CEO Patti Poppe said she toured the devastation in the town of Paradise, Calif., on her first day in office. The Camp Fire, ignited by utility subsidiary Pacific Gas and Electric’s equipment, killed 85 people and destroyed more than 14,000 homes there in November 2018.

“I met with my coworkers who live in the community, whose own lives were forever impacted by the Camp Fire,” Poppe said as part of her first earnings report. “We’re so grateful to those who have the strength and the courage to represent PG&E through the rebuilding effort.”

Later, she said, she visited the city of San Bruno, where a PG&E gas pipeline exploded in 2010, killing eight, leveling part of a suburban neighborhood and shooting a fireball 1,000 feet in the air.

Catastrophic fires in 2017, 2019 and 2020 compounded PG&E’s safety problems. The company emerged from bankruptcy in June after paying billions of dollars to fire victims and insurers and pleading guilty to 84 counts of involuntary manslaughter in the Camp Fire. (See PG&E Sentenced; Bankruptcy Plan Approved.)

Poppe, the former CEO of Michigan-based CMS Energy, became PG&E’s fifth acting or permanent CEO in the past four years in January. (See Struggling PG&E Nabs CMS Energy’s CEO.)

Like those before her, Poppe vowed change as she laid out her vision for the state’s largest utility, which reported GAAP losses of $1.05/share for 2020 and earnings of 9 cents/share for the fourth quarter, compared to losses of $14.50/share and $6.84/share, respectively, in 2019.

Poppe said that a “triple-bottom-line mindset” would guide the utility’s performance this year and beyond. Known as “TBL” in economics circles, the philosophy holds that companies will do better if they focus on social and environmental responsibility along with profits.

“We will embrace the triple-bottom-line mindset of serving people, our planet and California’s prosperity,” Poppe said. “This mindset will find an intersection between the need to safely deliver energy and meet the clean energy aspirations of Californians. I’m optimistic that there is a bright path forward with a triple bottom line enabled by a laser-like focus on performance.

“Priorities to get us moving in 2021,” she said, include writing what she called a “clear sky playbook.”

“We have a best-in-class emergency response playbook, and we’re going to complement that by writing the PG&E clear-sky playbook so we can predictably deliver every day, not just during and after a crisis,” Poppe said. “I’m putting together a team of senior leaders that’s developing that clear-sky playbook, underpinned by a lean operating system, to predictably deliver us on our commitments and outcomes. We’re bringing the best of a functional organizational design — standards, processes and scale — to deliver a regionalized hometown experience for the communities and customers we serve.”

One of PG&E’s proposed reforms involves “regionalization” by establishing a number of semiautonomous management units around the state.

PG&E’s system requires substantial capital investments, and customers deserve more disciplined cost performance, Poppe said.

“Our work will deliver for our customers and investors,” she said.

The Camp Fire tore through Paradise, Calif., on Nov. 8, 2018, killing 85 people. | *Tanner Hembree/USDA Forest Service*

PG&E has continued to attract negative publicity and harsh criticism, just before and during Poppe’s tenure.

In November, California Public Utilities Commission President Marybel Batjer told PG&E that it could face a stricter regimen of oversight and enforcement because of concerns about its line maintenance. A proposal in the matter was issued Thursday, with a vote scheduled April 15. (See PG&E Faces ‘Enhanced Oversight’ by CPUC.)

On Feb. 3, federal Judge William Alsup, who is overseeing PG&E’s criminal probation stemming from the San Bruno explosion, said he would likely impose new probation terms, requiring the company to improve its vegetation management and public safety power shutoff (PSPS) practices, following the Zogg Fire in September.

Alsup said he believed the fire — which killed four people, including a mother and her 8-year-old daughter who died fleeing the flames — was started by a tree falling on a PG&E power line in rural Northern California. (See PG&E Files Wildfire Plan Under Intense Scrutiny.)

Poppe said Thursday that PG&E would continue to use PSPS to prevent fires in high-risk areas.

On Wednesday, John Trotter, a retired state appellate court justice and the trustee of a wildfire victims trust established during PG&E’s bankruptcy, sued 23 of the utility’s former executives and officers for causing the Camp Fire and the October 2017 wine country fires.

The fires “were the outgrowth of separate and distinct wrongful acts and omissions by the defendants in breach of the defendants’ fiduciary duties of care and loyalty to the company,” the lawsuit said.

The trust, valued at $13.5 billion when the bankruptcy concluded, owns a 22% equity stake in PG&E and represents approximately 80,000 fire victims.

February 26, 2021

Granholm Confirmed by Bipartisan Vote

The Senate on Thursday voted 64-35 to confirm former Michigan Gov. Jennifer Granholm as the 16th secretary of energy.

Later in the evening Granholm was sworn into office by Vice President Kamala Harris.

Fourteen Republican senators, including Minority Leader Mitch McConnell (Ky.) and former Energy and Natural Resources Committee Chair Lisa Murkowski (Alaska), joined every Democrat in supporting Granholm’s nomination. Sen. Dan Sullivan (R-Alaska) did not vote.

The ENR Committee on Feb. 3 voted 13-4 to advance Granholm’s nomination, but only three other Republican members of the committee joined Murkowski in voting “aye” on the Senate floor: Steve Daines (Mont.), John Hoeven (N.D.) and James Risch (Idaho). (See “Granholm Approved for Senate Floor Vote,” EPA Nominee Regan Receives Bipartisan Support.)

Before Thursday’s vote, the committee’s ranking member, Sen. John Barrasso (R-Wyo.), repeated his criticism of President Biden’s energy-related executive orders, including his ban on new oil and gas drilling leases on federal lands, saying he could not “in good conscience” vote for Granholm. Still, he praised her personally and expressed confidence in her ability to run the Energy Department.

The Senate on Wednesday had voted 67-32 to invoke cloture on the nomination, setting up Thursday’s vote.

Granholm “has the leadership skills, the vision and the compassion for people that we need at the helm of the Department of Energy to face the climate challenge,” ENR Chair Joe Manchin (D-W.Va.) said before the vote. “I believe she is extremely well-qualified to lead the Department of Energy.”

The American Clean Power Association “congratulates Secretary Granholm on taking the helm of the Department of Energy,” CEO Heather Zichal said in a statement. “Having worked on energy policy with Secretary Granholm, I know that she is committed to the Biden administration’s interlinked goals of boosting the U.S. economy and combating climate change.”

“We look forward to working with her and other leaders across the administration to build on the existing partnership that has enabled the electric power industry to respond quickly and decisively to all manners of threats to the grid,” the Electricity Subsector Coordinating Council said.

“There are a great many challenges and opportunities facing the energy sector as we transition to the grid of the future and confront climate change,” FERC Chairman Richard Glick tweeted. “I know you will do an outstanding job leading the Department of Energy!”

February 26, 2021February 2, 2024

RIPUC Rejects Program for Low-income Customers

The Rhode Island Public Utilities Commission last week unanimously rejected a proposal from National Grid to remove barriers for low-income customers to access the benefits of clean energy.

“At best, this is a poorly developed concept, and taken at its worst, it’s a gimmick and a thinly veiled attempt by the utility to increase their profits from the Renewable Energy Growth Program, while claiming to be doing it in the name of equity,” Commissioner Abigail Anthony said at a Feb. 18 PUC meeting.

National Grid proposed to expand on the state’s Community Remote Distributed Generation (CRDG) incentive program.

“Developers enrolled in the [existing] program get paid by ratepayers an amount that is up to 15% higher than the price needed to build a similarly sized solar facility without the CRDG special features,” PUC Chairman Ronald Gerwatowksi said during the meeting. The project owner would then enroll National Grid’s customers for that facility’s incentive and distributes the extra funds as a bill credit.

Solar facility in Middletown, R.I. | Newport Renewables

National Grid, according to its filing on the proposed program changes, found that low-income customers were underrepresented in the existing program. The utility proposed an increase in the existing rate enhancement by an additional 3 cents/kWh. To qualify for that adder, project owners would have had to subscribe at least 20% of the project’s capacity to low-income customers.

“The purpose of the proposed adder was to increase enrollment of low-income customers in CRDG solar projects in a manner similar to other states’ renewable energy programs,” a National Grid spokesperson told RTO Insider in an email. “The company is committed to addressing low-income customer issues in fulfilling its clean energy goals and will consider alternatives, as the commission recommends.”

Low-income customers enrolled in the proposed program would realize an average annual bill savings of $200, according to National Grid’s filing.

Gerwatowksi said that the intentions of the proposal were good, but the means for accomplishing its objectives “raised questions.”

“We have tens of thousands of customers struggling to pay their bills, and we’re going to be facing mountains of debt when the [pandemic-related] moratorium ends and efforts to increase affordability need to meet the scale of the problem,” Anthony said. “This proposal was a distraction from the work the company should be doing to identify and eliminate all of the inconsistencies in their programs and policies that are causing the electric system to cost more than it needs to.”

The commissioners said they were open to discussing ways to improve on the proposal.

“I think this proposal did identify an opportunity to deliver the benefits of enrolling low-income customers in CRDG but … in a way that doesn’t have added costs,” Anthony said.

February 26, 2021

Calif. Worries High Rates Could Hurt Climate Efforts

California’s energy policy leaders came together Wednesday to weigh the potential impact of the state’s sharply rising electricity rates on its carbon reduction and electrification goals.

The heads of CAISO, the state Public Utilities and Energy commissions, and the legislative committees that oversee energy heard from CPUC staff and academic experts in a virtual hearing on how escalating rates could exacerbate the state’s division between rich and poor and undermine its ambitious programs to fight climate change.

“We begin this work because we understand that meeting our state’s decarbonization and electrification goals will depend on maintaining electricity rates that are affordable for customers,” CPUC President Marybel Batjer said.

Those goals include serving retail customers with 100% carbon-free energy by 2045 and requiring that all new cars sold in the state be zero-emissions vehicles by 2035. (See Calif. Governor Proposes $1.5 Billion for ZEVs.)

In the next decade, however, rates charged by the state’s three big investor-owned utilities will outstrip inflation by a wide margin, CPUC staff said. Ratepayers will have to cover the costs of billions of dollars in wildfire mitigation strategies and transmission and distribution upgrades.

The result: Southern California Edison’s rates will rise by 3.5% annually through 2030; Pacific Gas and Electric’s rates are projected to climb by 3.7% a year; and San Diego Gas and Electric’s rates will increase 4.7% every year for the next decade. Annual inflation, meanwhile, is anticipated to be about 1.9%. And PG&E and SDG&E’s annual rate increases have been twice the rate of inflation since 2013, commissioners said.

California Electricity Rates — Projections show PG&E rates compared with inflation through 2030 | *CPUC*

Electricity costs outpacing inflation by such a wide margin is a “very troubling finding,” Batjer said. Though not as dramatic as some had feared, the increases are more likely to hurt lower-income households that are sensitive to even small increases in monthly bills, she added.

The state must figure out how to maintain affordability and reliability while continuing to fight climate change, she said.

Batjer and the other CPUC commissioners were joined on the virtual dais by CAISO CEO Elliot Mainzer and members of CAISO’s Board of Governors, the state’s energy commissioners, and the chairs of the Senate and Assembly energy committees.

CPUC Commissioner Genevieve Shiroma called the unusual gathering a “who’s who of California energy.”

Shiroma led the effort that produced the draft white paper that formed the basis for the hearing and future efforts. She said it wasn’t fair to keep saddling ratepayers, regardless of income, with fixed costs for infrastructure upgrades.

“We as a commission cannot continue to approve larger and larger revenue requirements,” she said. “We need to do a better job of considering the cumulative impact of the rate increases we approve … and we need to be diligent in ensuring that … we approve [increases] only for programs where we have strong evidence that the benefits will outweigh the costs.”

A primary concern is that rising electricity rates will prevent the adoption of electric vehicles and the replacement of gas furnaces and water heaters with electric units.

California is among the states with the highest retail electricity prices , averaging 20.45 cents/kWh in December versus the national average of 12.8 cents/kWh, according to the U.S. Energy Information Administration.

That could thwart the electrification of transportation, a major policy goal in California, with about 800,000 electric vehicles currently on the road and millions more anticipated. The movement to electrify buildings has been rapidly gaining momentum, with dozens of cities and counties adopting electrification ordinances that exceed state building codes in recent years.

“Higher bills make meeting our policy goals much harder,” CPUC Energy Division Director Ed Randolph said.

The white paper describes the problem but does not provide immediate solutions, Randolph said. Among the issues lacking ready alternatives is the state’s need to prevent catastrophic wildfires sparked by utility equipment, such as those in 2017-2020, and rolling blackouts like those in August.

“Once we looked at the drivers of the increases and the ways we could reduce utility costs, it was hard to pinpoint places where we should cut back on spending,” he said. “The biggest drivers of bill increases are wildfire mitigation spending and transmission buildout. While we can look at ways to be more efficient in these investments, I don’t believe we can recommend not making [them]. They are critical to reducing wildfires, maintaining reliability and avoiding outages such as the ones that happened last summer in California and just happened in Texas.

“We also know that investments in clean energy infrastructure are absolutely necessary to meet our state policies, and analysis shows that these investments have minimal impact on bills or could even save Californians money over time” by reducing rates because of increased demand, he said.

The CPUC and its sister agencies, utilities and stakeholders must find ways to minimize costs and keep electricity affordable, Randolph said.

“Hopefully this en banc [hearing] is a start of that joint effort,” he said.

‘A Tale of Two States’

Paul Phillips, CPUC manager of retail rates, said the rate dilemma highlighted the often extreme income equality in California.

“It really has become a tale of two states,” Phillips said, while presenting the white paper’s findings. “We have wealthier coastal homeowners who tend to invest in distributed energy resources,” mainly rooftop solar, and have a better sense of how to lower their own electric costs. Inland communities of lower-income workers don’t have those resources, he said.

In an afternoon session, Severin Borenstein, a CAISO board member and University of California, Berkeley professor, echoed the theme. He presented the results of a study he and two colleagues from the Energy Institute at UC Berkeley’s Haas School of Business authored, titled, “Designing Electricity Rates for An Equitable Energy Transition.” Nonprofit think tank Next 10 commissioned the study.

The report said California’s strategy of recovering fixed utility and social program costs from lower-income ratepayers is “a headwind in the state’s efforts to combat climate change through electrifying transportation and buildings, which many see as critical steps to a low-carbon future.”

“The state’s three large investor-owned electric utilities recover substantial fixed costs through increased per-kilowatt hour (‘volumetric’) prices,” it said. “With nearly all fixed and sunk costs recovered through such volumetric prices, the price customers pay when they turn their lights on for an extra hour is now two to three times what it actually costs to provide that extra electricity — even when including the societal cost of pollution.

“This massive gap between retail price and marginal cost creates incentives that inefficiently discourage electricity consumption, even though greater electrification will reduce pollution and greenhouse gas emissions,” the report said.

Between 66 and 77% of the costs that California IOUs recover from ratepayers are “associated with fixed costs of operation that do not change when a customer increases consumption,” it said. “This includes much of the costs of generation, transmission and distribution of electricity, as well as subsidies for low-income household and public purpose programs, such as energy efficiency assistance.”

The shift to behind-the-meter solar generation has disproportionately shifted cost recovery onto customers who do not have rooftop solar, the report said. More affluent homeowners now consume “modestly” more energy than low-income households, it said.

The study recommended changing the way utility infrastructure and social programs are financed. One approach, it said, would be to raise revenue from sales or income taxes, “ensuring that higher-income households pay a higher share of the costs.”

That might not sit well with voters, it acknowledged.

“A more politically feasible option could be rate reform — moving utilities to an income-based fixed charge that would allow recovery of long-term capital costs, while ensuring all those who use the system contribute to it,” the report said.

“In this model, wealthier households would pay a higher monthly fee in line with their income.”

In his presentation, Borenstein said the state’s Franchise Tax Board could either provide refunds to low-income ratepayers or disclose customers’ income brackets to the utilities that collect the fees.

“We’ve thought about enforcement issues, and we think there are ways to do it,” Borenstein said. “It would be a lift, but the alternative is not only, I think, going to undermine decarbonization but, also, we’re basically balancing the costs of all of the carbon-reduction programs on the backs of the people who are least able to pay for it.”

February 26, 2021

Cold Weather Standards Team Sticking to Year-end Target

The team modifying NERC’s standards for cold weather preparedness confirmed in a webinar Thursday that the joint inquiry by the ERO and FERC into the recent power outages in Texas and neighboring states will not affect its schedule for completing Project 2019-06, which remains on track to be finished “by the end of the year.” (See Anger Rises over Texas Power Restoration.)

However, NERC Senior Standards Developer Jordan Mallory also acknowledged that the effort “is a high-priority project” for the organization. She said the standard drafting team (SDT) has been actively conducting industry outreach and is confident that “we will only need one more ballot” after the current formal comment period, which ends on March 3.

NERC Panel Delays Action on Cold Weather Prep.)

Team Credits Industry Feedback for Improved Product

Industry reaction to previous postings have been lukewarm at best, as noted at September’s meeting of NERC’s Standards Committee, where the standard authorization request (SAR) was approved. (See “Cold Weather SAR Approved,” Gen Operators Cool to Winter Preparedness Standard.)

cold weather preparedness standards — NERC’s Jordan Mallory (left) and SPP’s Matthew Harward | © *ERO Insider*

SPP’s Matthew Harward, chair of the SDT, said at Thursday’s webinar that the constructive criticism had helped the team create a proposal that would be acceptable to more stakeholders. He emphasized that the team is aware that “a one-size-fits-all approach will not be the most efficient way” to address the issue, and that it had focused on giving generator owners “flexibility … to make many determinations based on their own situations.”

The proposal currently out for comment involves three updated standards: EOP-011-2 (Emergency preparedness), IRO-010-4 (Reliability coordinator data specification and collection) and TOP-003-5 (Operational reliability data).

Changes to EOP-011-2 include adding new requirements for cold weather preparedness plans on the part of generator owners, along with data specifications and collections for balancing authorities and annual maintenance and inspection requirements. IRO-010-4 would be modified to include data specification requirements and cold weather parameters for reliability coordinators, while updates to TOP-003-5 would include those requirements for transmission operators.

The team is also seeking comment on the implementation plan, which would see all new requirements take effect one year after the new standards are accepted by FERC. Harward emphasized that despite the team’s confidence in their work, they still welcome feedback from stakeholders to make sure they are on the right track.

If “you have a suggestion — another standard or new standard … where these requirements should go — please submit comments, because those are very valuable to the drafting team to help us navigate where to place the standards,” Harward said.