Coal declined, gas and renewables grew in 2022

U.S. electricity generation resource portfolios continued to shift in 2022, with natural gas and renewables increasing their shares of total electric power generation, as coal's share continued to decline, according to data released by federal energy regulators.

The U.S. Energy Information Administration tracks national electric power generation, among other energy metrics. According to EIA, in 2022 the U.S. electric power sector produced 4,090 million megawatt-hours (MWh) of electric power. The greatest fraction of this power came from natural gas, whose contribution increased from 37% of U.S. generation in 2021 to 39% last year.

Renewables continued to grow, led by gains from wind and solar whose combined share of total generation increased from 12% in 2021 to 14% last year. EIA notes that utility-scale solar capacity grew from 61 gigawatts (GW) in 2021 to 71 GW in 2022, while wind grew from 133 GW to 144 GW. Hydropower (6%), and biomass and geothermal (each less than 1%) resource contributions remained stable year-over-year.

Meanwhile, coal-fired power generation continued to decline, decreasing from 23% in 2021 to 20% in 2022. This continues a general trend of declining U.S. electricity generation from coal, which historically fueled most electric power generation, but which was displaced by natural gas in the last decade. Natural-gas-fired power plants typically emit less than half as much carbon dioxide per unit of electricity generation as compared to coal-fired plants. Many coal-fired plants have retired or are facing increased economic pressures to retire, while other coal plants have seen less use. Nuclear power's contributions also decreased slightly last year, falling from 20% in 2021 to 19% in 2022. The Palisades nuclear power plant retired in May 2022.

US retail electric choice holds steady, per EIA

Over a quarter of eligible residential electricity consumers participated in their state’s retail choice program in 2021, according to the U.S. Energy Information Administration. At the national level, participation in state retail choice programs has remained stable from 2019 to 2021, at about 26% of eligible U.S. customers participated in their state’s retail choice program, or 13.2 million U.S. residential electric customers.

How consumers buy electricity at retail is generally a matter of state law. Under the traditional system of vertically integrated utilities, a customer is served by a utility that provides both electricity supply and delivery service, and customers have no choice as to who serves their load. Most consumers nationwide are served by traditional utilities that both generate or purchase power and deliver it to their customers.

But some jurisdictions have restructured their electricity sectors, to give customers retail choice, meaning the customer can choose which provider they want to have supply their energy for delivery by the local utility acting as a "wires company". According to EIA, today 13 states and the District of Columbia have active statewide or districtwide retail choice programs for residential customers. The states include California, Connecticut, Delaware, Illinois, Massachusetts, Maryland, Maine, New Hampshire, New Jersey, New York, Ohio, Pennsylvania, and Rhode Island. In addition, Texas has a mandatory retail choice program; and Michigan, Nevada, Oregon, and Virginia have limited forms of retail choice programs (mostly for non-residential electric customers).

According to EIA, participation by residential retail customers in retail choice programs grew from 2015 through 2019, and has remained stable at 26% through 2021.

Retail choice is generally a matter of state law. Laws vary by state, and can change over time, as can the degree to which customers choose to participate in retail choice programs where they are offered. For example, participation among Ohio residential customers increased from 45% in 2015 to 50% in 2021, while participation by Massachusetts residential consumers increased from 22% to 49%. 

California launched its first Community Choice Aggregator (CCA) program in 2010, allowing local governments to buy power from retail suppliers on behalf of community residents, who have an option to opt-out if they don't want to participate in the program. Under the CCA system, participation in California grew from 2% in 2015 to 30% in 2021.

On the other hand, other states like Illinois and Connecticut have seen declines in residential retail choice participation rates, with Illinois dropping from 57% in 2014 to 31% in 2021, and Connecticut falling from 42% in 2013 to 24% in 2021.

New England EV growth predicted by electric grid operator

New England is poised for significant growth in electric vehicle (EV) use through 2030, according to a draft forecast by the region's electric grid operator. 

According to the draft ISO New England Inc. Load Forecast Committee 2023 CELT Transportation Electrification Adoption Forecast released in February 2023, various federal and state policies incentives promote EV adoption, as do economic and environmental concerns, though their impacts on EV adoption in New England remain uncertain. For example:

• The federal Inflation Reduction Act creates tiered incentives for consumers to buy new personal light-duty EVs, which must meet increasingly strict vehicle assembly and domestic-material sourcing requirements, as well as incentives to buy used EVs or commercial light, medium, and heavy-duty EVs.
• U.S. Environmental Protection Agency’s (EPA) Clean School Bus Program has $5 billion available over the next five years (FY 2022-2026) through the Bipartisan Infrastructure Law, to replace existing school buses with zero-emission and low-emission models. This money is available to school entities through EPA and state programs like the Maine Department of Education's Maine Clean School Bus Program.

As part of its mission to forecast regional energy demands, ISO-NE prepares a transportation electrification forecast to forecast the energy and demand impacts associated with the uptake of electric vehicles (EVs) within selected categories of vehicles: light-duty personal vehicles, light-duty fleet vehicles, medium-duty delivery vehicles, school buses, and transit buses.

ISO-NE's latest draft transportation electrification adoption forecast includes two adoption scenarios that reflect different assumptions about the pace and extent of transportation electrification within each state: a theoretical “Full Electrification” adoption scenario (intended to represent an upper bound based on state emissions goals and associated EV adoption targets) and a projected "Draft CELT 2023" adoption scenario (intended to reflect the likely pace and level of EV adoption over the next 10 years given the current understanding of individual state goals, policies, and programs, as well as uncertainty in the timing of goal achievement and extent to which electric vehicles will be utilized to accomplish goals).

For personal light-duty EV adoption, the draft forecast projects an increasing pace of EV adoption over the ten-year period through 2032. For example, it projects that 2023 will see 85,901 of these EVs added, while 2032 will see an incremental 468,679 EVs added to the stock, for a 10-year total of 2,724,923 personal light-duty EVs added from 2023 through 2032. This is a significant increase from ISO-NE's prior 10-year forecast, which projected that 1,521,796 of these EVs would be added between 2022 and 2031.

ISO-NE's latest forecast shows similar growth in other categories of EVs, including flight light-duty (projecting that a cumulative total of 240,713 will be added regionwide by 2032), medium duty-delivery (3,352), school bus (6,505), and transit bus (833). Within each category of EV, ISO-NE's model provides state-specific annual data. For example, ISO-NE's forecast projects that Massachusetts will hew close to the "Full Electrification" scenario, contributing more than half the total number of personal EVs, while New Hampshire will lag relative to "Full Electrification" in the forecast.

By 2032, ISO-NE now projects about 3,000 MW of winter transportation electrification demand, with nearly 1,600 gigawatt-hours of transportation electrification energy per month by 2033, and accounting for up to about 9% of monthly regional gross electric energy consumption from the grid.

FERC sets New England gas-electric forum for June 2023

U.S. utility regulators have scheduled a second New England Winter Gas-Electric Forum, to be held this June in Portland, Maine, to continue discussions from a forum held last fall regarding the electricity and natural gas challenges facing the New England region. According to the Federal Energy Regulatory Commission, the objective of the June 20, 2023 forum is "to shift from defining electric and natural gas system challenges in the New England Region to discussing potential solutions, including both infrastructure and market-based solutions."

New England's wholesale electricity price is strongly influenced by the price of natural gas. The federal government, New England's regional electricity grid operator, and states like Maine have all found that recently increased energy costs in New England are a result of higher natural gas prices. Beyond price impacts, electric system reliability can depend on ensuring that natural gas-fired power plants can access adequate amounts of fuel. 

On September 8, 2022, FERC convened a forum in South Burlington, Vermont, to discuss the electricity and natural gas challenges facing the New England region. According to FERC's public notice for the September 2022 forum, its purpose was "to bring together stakeholders in New England to discuss the challenges faced historically during New England winters and discuss the stakeholders’ differing expectations of challenges for future winters. The objectives of the forum are to achieve greater consensus or agreement among stakeholders in defining the electric and natural gas system challenges in New England and identify what, if any, steps are needed to better understand those challenges before identifying solutions." 

At the September 2022 event, lead-off speaker Charles Dickerson, President and CEO of reliability organization Northeast Power Coordinating Council (NPCC) described the regional context for New England's gas-electric relationship:

The problem in New England is in the wintertime there are only so many gas pipes feeding natural gas into the New England area, and those gas pipes can be constrained. They're going to be constrained for two reasons.

One, they're going to be constrained because of the physics. There's nothing we can do. The pipe is only so big no matter how big we make it, and we're not going to be changing the price of the existing price any time soon I don't believe. So, there's a physical limit to how much gas can flow through those pipes.

The other constraint that's on the operators is a policy constraint which made sense, that basically says in periods of very low temperatures, commercial and industrial users of gas needs are going to be supporting it into residential people who need fuel for heating, which makes sense. So if we have a generator that's using natural gas, and we have a pipe constraint, and even if we didn't have the constraint, we would have to curtail the usage of generating facilities that use gas from those pipes, so that residential customers can use them.

It begs the question what must be done? I would submit through our review that liquefied natural gas is probably a good path for that until we get through the transition. ...

The next speaker, a director of Operational Performance and Training for regional electricity grid operator ISO New England Inc., continued the discussion:

So in terms of close calls we've had a number of close calls over the past couple of decades, primarily as a result of the region's constrained natural gas system, its reliance on imported fuels, and vulnerability to correlated contingencies. So nearly 20 years ago, back in January of 2004, the events first shed light on New England's constrained pipeline and the risk associated with that.

Only 10 years later during the polar vortex we saw similar events: constrained pipelines, operational challenges, and in this case reserve deficiencies. Moving forward a little bit closer to today, we've seen more recent issues particularly during the winter of 17-18 where we were only days away from running out of useable fuel in the region.

Anybody that was in New England at that time, or had interests in the region, probably remembers this winter.

Another speaker, Commissioner Patrick Woodcock of the Massachusetts Department of Energy Resources, described reliability concerns arising under the status quo including these constraints:

I do think however, what is in my mind is on ISO's description of the 2017-2018 cold snap. And I remember that very well. I remember the frostbite that I got as I was talking to ISO about the depletion of our energy reserves. That was a one in 100 year event and I really do not see market arrangements really being adequate to ensure that generators will make arrangements for that event. 

And we were really on the cusp if there was another N minus 1 event lost to nuclear power plant. We were at the point where we were going to have to really start talking about contingencies and rolling blackouts in New England. That's what we need to prepare for.

In a follow-up request for public comments, FERC summarized the September 2022 forum's scope as including "the historical context of New England winter gas-electric challenges, concerns and considerations for upcoming winters such as reliability of gas and electric systems and fuel procurement issues, and whether additional information or modeling exercises are needed to inform the development of solutions to these challenges." 

To continue the discussions, FERC has now scheduled a second forum to be held this June. According to Commission chair Willie Phillips, the June 2023 event will focus on what he calls "the Commission’s primary job: ensuring reliability of the grid to continue safe and secure delivery of energy services to consumers." 

Reliability is Job No. 1. Each winter, natural gas supply constraints during extreme weather places the New England electric grid and its nearly 15 million residents at risk for rolling blackouts ... I believe addressing this risk is urgent and I am hopeful that we can continue the productive discussions from the last forum as we shift our focus to having stakeholders propose potential solutions to address the winter reliability challenges in the region.

The Commission has also described the objective of the upcoming June 2023 forum as "to shift from defining electric and natural gas system challenges in the New England Region to discussing potential solutions, including both infrastructure and market-based solutions." 

US added record-low amount of interstate gas pipeline capacity in 2022

The least U.S. interstate natural gas pipeline capacity on record was added in 2022, according to the U.S. Energy Information Administration, and nearly all the new capacity was from compressor upgrades, not new pipeline.

EIA is a division of the federal Department of Energy, whose work includes collecting, analyzing, and disseminating independent and impartial energy information to promote sound policymaking, efficient markets, and public understanding of energy and its interaction with the economy and the environment. EIA's data and analysis includes electricity, natural gas, oil, and other forms of energy commodities and related infrastructure.

Since 1995, EIA has tracked interstate natural gas pipeline capacity additions. According to EIA's most recent report, in 2022, 897 million cubic feet per day (MMcf/d) of interstate natural gas pipeline capacity was added in the U.S, but this was the smallest amount of new interstate pipeline capacity for any prior year:

According to EIA's State-to-State Capacity Tracker, which contains information on the capacity of natural gas pipelines that cross state and international borders, only five new interstate natural gas projects came online in 2022, and these focused primarily on upgrading compressor stations, "with only one project adding a relatively small amount of new pipe."

EIA says interstate capacity additions were low in 2022 for two primary reasons: more growth in intrastate capacity (not captured in its interstate data), and less overall capital expenditures by oil and natural gas companies.

EIA notes that in prior years, interstate pipeline capacity was added from looping and compressor station projects designed to accommodate growing production in Appalachia. While these types of projects were the most common for developing new interstate pipelines, all of the planned projects are  now mostly completed. 

Since 2017, about 70% of the growth in natural gas production has come from wells in the Permian and Haynesville regions which are near liquefied natural gas (LNG) export terminals sited on the Gulf Coast. EIA also notes growth in intrastate projects, including in Texas and Louisiana where intrastate projects, rather than interstate projects, have increased takeaway capacity and connected natural gas production to LNG export terminals. According to EIA:

Building large-scale, commercial natural gas pipelines that cross state boundaries involves a number of contractual, engineering, regulatory, and financial requirements. These requirements may involve more coordination and can take longer to complete compared with intrastate pipeline projects.

EIA has previously noted decreased capital expenditures by oil and gas companies since 2019.

State utility regulators as well as the regional grid operator ISO New England have found that constraints on interstate natural gas pipeline infrastructure drive up the price of electricity for New England consumers.

Maine electricity cost increases driven by natural gas pricing

Maine's increased electricity costs in the past year were yet again driven by increases in the cost of natural gas, according to the most recent annual report from Maine utility regulators.

The Maine Public Utilities Commission regulates electric, gas, telephone, and water utilities, as part of a regulatory system intended by statute to achieve multiple purposes, including to ensure safe, reasonable and adequate service, to assist in minimizing the cost of energy available to the State’s consumers, to ensure that the rates of public utilities subject to rate regulation are just and reasonable to customers and public utilities and to reduce greenhouse gas emissions to meet the greenhouse gas emissions reduction levels.

The Commission issues various reports, including an annual report to the Legislature presenting an overview of the Commission's work in the prior calendar year. The Commission's most recent annual report, released in February 2023, covers the 2022 calendar year.

According to the 2022 report, wholesale electric energy costs nearly doubled year-over-year, driven by increased natural gas pricing:

Wholesale electricity market costs to Maine consumers for the period December 2021 to November 2022 were $1,067,263,891. This is approximately a 77% increase from the $603,233,815 market costs the year prior. Between the two periods, wholesale energy costs increased 86% and capacity costs increased by 29%. The increased electricity costs were driven by the highest natural gas costs the region has experienced since 2014.

These recent gas-driven price increases continue a trend established in prior years, as the 2021 report shows:

Regional wholesale energy prices in the ISO-NE Real-Time market during the 12-month period ending October 31, 2021 averaged $40.7/MWh, about 71% higher than prices during the prior 12-month period. From December 2020 – February 2021, prices averaged $52/MWh, which is about 73% lower than the prior winter period.

According to the 2021 report, with respect to supply rates, "The increases reflect prevailing energy market conditions, including those in the regional electric power market in which prices are strongly influenced by natural gas." The report documents increases in other energy products: between October 2020 and October 2021, natural gas prices increased by 94.8%, and heating oil prices increased by 121.7%; by comparison, between November 2020 and November 2021, wholesale electricity prices increased by 126.3%.

The Maine PUC's findings align with recent reports from regional grid operator ISO New England Inc., which concluded that increased energy costs in New England throughout 2021 and 2022 were driven by high natural gas prices.