Vice President of Global Power Industry Research for Industrial Info Resources (IIR), which is headquartered in Sugar Land, Texas, and has six offices in North America and 12 international offices.

Britt Burt

Conventional wisdom held that President Biden’s plan to decarbonize the U.S. Power industry was wounded critically, if not fatally, by the one-two punch of the U.S. Supreme Court’s Clean Air Act ruling in West Virginia v. EPA and U.S. Senator Joe Manchin’s (D-W.Va.) resistance to supporting Biden’s plan to fight climate change.


But Manchin reversed course and agreed to support a slimmed-down piece of legislation, the Inflation Reduction Act of 2022, that would direct an estimated $369 billion to renewable energy and climate-change measures. That law broadened and extended the federal government’s intervention in the power industry that stemmed from the 2021 Infrastructure Investment and Jobs Act (IIJA), which directed tens of billions of dollars into various aspects of electric power generation and grid reliability and resilience. But the U.S. power business appears to be headed for cleaner and greener pastures, according to new-build power plant data tracked by Industrial Info Resources (IIR).


Whether the U.S. generating fleet is cleaning and greening fast enough to make a dent in global climate change is the question. The Paris Agreement of 2015 pledged to take action to limit global temperature gain to either 1.5°Celsius or 2°C above pre-industrial times. The globe is nearly there, with cumulative temperature gain of approximately 1.2° C through 2022.
As the U.S. emerged from COVID-19 restrictions in 2021 and the government distributed trillions of dollars of aid, consumers engaged in “vengeance spending,” scooping up cars, taking vacations, and renovating homes.


The reckoning started in late 2021 and mounted in 2022 as prices rose for all goods and services — including energy. Gradually, the U.S. public became familiar with supply chain bottlenecks. Across the U.S. economy, inflation rose to a four-decade high, scrambling the energy sector. For the power generation industry, the wait list for new transformers stretched as long as three years.


As natural gas prices shot up, coal made some opportunistic market-share gains among operating power plants. But the sharp price increase of fossil fuels is expected to cause U.S. electric demand growth to revert to the mean of between 0% and 1% in 2022 and 2023, according to a global electricity report from International Energy Agency (IEA).


There is, however, no evidence that gas vs. coal jockeying for market share among operating power plants has had any bearing on the power industry’s new-build rush to renewables.


Figure 1: Annual carbon emissions from coal-fired power plants.


In 2014, when then-President Barack Obama first proposed his Clean Power Plan to reduce carbon emissions from coal-fired power plants by an estimated 870 million metric tons by 2030 compared with a 2005 baseline. The rule was finalized in 2015, but was never implemented because the U.S. Supreme Court, in a highly unusual step, blocked it. Years of litigation followed. The Clean Power Plan was the most litigated rulemaking that never went into effect in U.S. history.


While litigants wrestled, the market moved. For more than a decade, electric utilities, perhaps seeing the writing on the wall but certainly driven by the Clean Air Mercury Rule of 2005 and the Mercury and Air Toxics Standards rule finalized by the EPA in 2012, began closing coal-fired generators or switching them to burn natural gas instead. Federal activity on carbon regulation was also backstopped by state public utility commissions, which compelled utilities to file integrated resource plans (IRPs) on their proposed long-term electric generation options. Increasingly, those IRPs focused on decarbonization as well as low-cost options. As renewable energy became more competitive with traditional fossil-fueled generation, regulators pressed utilities to switch to the cleaner generation.


Long before the Supreme Court handed down its decision in West Virginia v. EPA, the market accomplished what lawmakers and regulators could not: meaningfully reducing CO2 emissions from coal-fired power plants. Between 2005 and 2020, according to the U.S. Energy Information Administration (EIA), CO2 emissions from coal-fired power plants dropped by about 1.2 billion metric tons — far exceeding the aims of the Obama Clean Power Plan (Figure 1).


As a demonstration of how far and fast the market has moved, renewable energy is now expected to account for about 94% of all new-build power plant construction over the 2023-2027 period. That is up from 88% of all new-build project kick-offs only a year ago. Five years ago, renewable energy was expected to account for about 56% of all new-build power plant activity over the 2018-2022 period.


For the 2023-2027 period, the rush to renewables is generalized across the U.S., but is particularly pronounced in New England, where renewables are scheduled to account for 100% of planned power plant construction, the Midwest (98%), the West Coast and Rocky Mountains (both 96%), and the Northeast (92%) (see map).


Overall, developers have scheduled the construction of about 405 GW of new generation over the next five years. That is up about 28% from a year ago, and nearly double the planned capacity additions from two years ago (Figure 2).

Not all of that new generating capacity will be built as scheduled over the next five years. Depending on the technologies involved and developers’ ability to secure financing, lock down offtake arrangements, and achieve regulatory support, we typically see between one-quarter and one-half of all announced projects delayed or cancelled. Higher interest rates mean that fewer projects will pencil out. But then again, as we have seen over the last 30 years, new power projects are announced on a near-daily basis.


Bottom line: Renewable power developers are in the green, and carbon-based developers are singing the blues.


Figure 2: Planned new-build capacity additions increase sharply.

Figure 3: Coal burn by U.S. electric generators.


IIR is not aware of any new-build coal-fired power project that is scheduled to begin construction between 2023 and 2027. This continues a long downward trend for new-build coal as well as in the number of coal miners and overall coal use by the power sector. Coal burned by U.S. electricity generators is expected to fall slightly in 2022, to about 482 million metric tons, and a further decline for 2023 is forecast by EIA (Fig. 3). Employment in coal mines held steady at about 38,000, as mines and their customers rationalized the demand for and supply of thermal coal (Fig. 4).

Figure 4: Coal mining employment continues to drop.

The IRA and IIJA laws provide some federal dollars for carbon capture and sequestration (CCS), which could help existing coal-fired power plants stay open. But we think those credits, on their own, will not be enough to help make any proposed new-build coal plants move forward. Over the next five years, most of the project spending that will take place among coal-fired power generators is expected to be for: dismantlement & demolition (D&D); environmental remediation, such as closure and cleanup of coal ash ponds; and in-plant capital spending on maintenance and upgrades.


We estimate that about $2.85 billion will be spent on D&D activities at U.S. coal plants over the 2023-2027 period. An additional $4.4 billion is scheduled to be spent on environmental remediation over that time. A third category of coal plant project spending, in-plant capital spending, covering boiler revamps, fuel switching, generator rewinds and turbine refurbishments, will reach about $820 million over the next five years. And $600 million is expected to be invested in planned maintenance at coal-fired generators over the next 2023-2027 period.


Although Coal Country welcomed the Supreme Court decision in West Virginia v. EPA, and cheered Joe Manchin’s months-long resistance to the president’s climate legislation, there was scant possibility that either would reinvigorate coal-fired generation or lead to the construction of new coal-fired generation. Mid-summer analyses from Morgan Stanley and Glenrock Associated were even bleaker: the Supreme Court decision in West Virginia would not create an opportunity to extend the lives of existing coal-fired generators, much less build new plants, analysts said. The court decision may be a setback for the Biden administration, “but utilities aren’t changing their plans,” according to Paul Patterson, an equity analyst with Glenrock Associates. He added that most of the action on reducing greenhouse gas emissions (GHGs) from the power sector has been driven by state policies, federal tax incentives, and corporate green power purchasing decisions. In the absence of federal action, there were plenty of other drivers pushing coal to the margins.

Once a coal plant is deactivated and mothballed, it’s not economic to reverse course and bring it back online. Approximately 115 GW of U.S. coal-fired generation was closed between 2011 and 2021. Going forward, we expect another 44 GW of coal-fired generation to be closed by 2025 (Fig. 5).

Numerous asset owners announced the closure of coal-fired power plants in 2022 or moved up the closure dates. During the year, the PJM Interconnection deactivated about 3.2 GW of coal-fired generation, most of which was owned by Energy Harbor. AES announced plans to exit coal by 2025. Duke told investors it would be coal-free by 2035. Xcel Energy plans to stop using coal by 2032. Public Service Company of New Mexico announced plans to close two units of its San Juan complex in September. There were many other announcements along these lines.


Another driver working against new-build coal generation is the rise of Environmental, Social and Governance (ESG) investing. More than 3,400 institutional investors have signed the U.N. Principles for Responsible Investing (PRI), and their assets under management (AUM) exceeded $121 trillion as of March 30, 2021 (Fig. 6). That means developers seeking to build new coal-fired generation have fewer places to source their capital.

Figure 6: ESG investing continues to grow.

In a cruel irony, it may be that the most valuable assets owned by retired or retiring coal-fired power plants are their transmission lines and their land. Numerous coal-fired plant sites — including those in Illinois, Colorado, Nevada, New Mexico, North Dakota, Nebraska, Minnesota and Maryland — are slated to be transformed into renewable energy and/or battery energy storage projects in the next few years, according to an investigation by The New York Times. In addition, two retired coal-fired power plants in Massachusetts and New Jersey are scheduled to be converted to receive power generated by offshore wind farms. Further out, Bill Gates-backed TerraPower has plans to build a small nuclear power plant on the grounds of a Wyoming coal-fired power plant that is scheduled to be closed in the late 2020s.


The outlook for new-build natural gas generation in the U.S. has dimmed considerably in recent years. Looking forward to the 2023-2027 period, that erosion is expected to continue. Over the next five years, new-build natural gas generators are scheduled to account for only 5% of all new powerplants scheduled to be built. Last year, that percentage was about 11%, and five years ago it stood at about 41% (Fig. 7).

Figure 7: Proposed New-Build Generation, Renewables vs. Gas


What happened? One view is that gas became a victim of the “Carbon is Public Enemy #1” campaign undertaken by environmental organizations. A more nuanced perspective is that the hands of regulators have been tied by state laws and goals on renewable portfolio standards (RPS) and GHG reduction. Gas has a bleak future in states that are driving down their GHGs while increasing their RPSs.


On a percentage basis, the Mid-Atlantic region has the highest share of proposed new-build gas generators in the U.S., accounting for about 14% of all new power plants scheduled to be built over the 2023-2027 period. Following the Mid-Atlantic are the Great Lakes (12%), the Northeast (8%) and Southwest (7%). In terms of raw numbers, the Southwest has scheduled construction of the greatest amount of new-build gas-fired generation, at 5,456 MW, followed by the Great Lakes (5,376 MW) and the Mid-Atlantic (3,033 MW) regions.
Over two dozen proposed gas-fired generators that were scheduled to be built over the next five years have been cancelled. The aggregate value of those proposed projects exceeds $13 billion. The states with the largest number of project cancellations on a project-dollar basis are: Virginia ($1.8 billion); Texas, Pennsylvania and New Jersey ($1 billion each); and Florida, California and West Virginia (all slightly less than $1 billion each).


An additional 41 new-build gas-fired generation projects with aggregate value of $15.8 billion were scheduled to begin construction over the next five years but have been delayed. Texas is far and away the state with the largest dollar-value of project delays, at more than $8 billion, followed by Michigan ($2 billion) and Ohio ($1 billion). COVID-19 has been the cause of some of those project delays. The pandemic caused labor and materials shortfalls that have affected the entire power industry. Some of these delayed gas power projects could become reactivated over the next five years.


Organized wholesale regions like ERCOT (Electric Reliability Council of Texas) and MISO (Mid-Continent Independent System Operator) have sounded alarms of a potential generation shortfall in recent years, and the heat dome of Summer 2022 stretched those regions to the limit. Electric emergencies or rolling blackouts could focus the minds of regulators on the need for more dispatchable capacity. This bears watching, as events could cause regulators to relent and permit some new gas power development.


It is too soon to declare new-build gas plants a dead artifact of the 20th century. The thousands of MW of renewable energy that are operating, under construction or scheduled to be built will need to be backed up. That challenge outstrips the current capabilities of battery energy storage systems, even leaving aside the technological challenges of lithium ion battery systems, as well as concerns over the available supply of lithium. Pumped storage hydro facilities could be paired with intermittent generation, but the cost and timeline for building new pumped-storage facilities is daunting. In short, as much as policymakers and developers want to quickly move toward higher reliance on non-emitting generation, we see a continued need for new-build gas-fired generation.

In addition to new-build generation, IIR is tracking more than $13 billion in planned in-plant capital spending at U.S. gas plants over the next five years. Also, developers, engineers, and analysts are investigating the potential to co-fire gas plants with hydrogen.


Figure 8: A more granular view of renewables.


Even before Senator Manchin reversed course over the summer and supported the president’s slimmed down climate-change bill, plans to build renewable energy generating capacity over the next five years were exploding. They have risen to about 379 GW or 94% of all planned new-build capacity over the next five years. Last year, renewables were scheduled to account for 88% of all new-build construction over the 2022-2026 period. Five years ago, for the 2018-2022 period, that percentage was 55%.


In assessing the new-build generation market, we did not include renewable energy plants that could get built due to the Inflation Reduction Act of 2022, as the thinner version of “Build Back Better” was tabbed. That proposal, with an estimated $369 billion in clean electricity funding, includes Production Tax Credits (PTCs) for wind, solar and battery energy storage, among other things. The PTC for solar power would be new, as that industry has depended on Investment Tax Credits (ITCs) for years. If anything, our estimate for the new-build renewable generation market for the next five years could be conservative.


On a percentage basis, the U.S. regions with the greenest hues are: New England (where 100% of new-build generation is expected to be renewable); Rocky Mountains and West Coast (each 96%). On a MW-basis, the regions leading the green power parade are: Rocky Mountains (133 GW), Southwest (78 GW), Great Lakes (39 GW), and West Coast (36 GW). Again, we don’t expect all this planned renewable generation to be built as proposed. But the 2023-2027 period is starting off with an enormous number of renewable energy projects.


“Other” renewable energy projects, such as hydropower and geothermal, are expected to account for as much as 49 GW, or about 12% of all renewable capacity scheduled to be built over the next five years. Hydropower, in particular, is expected to benefit from some $754 million in incentives contained in the Infrastructure Investment and Jobs Act, signed into law in late 2021 by President Biden. New-build hydro could also benefit from the Inflation Reduction Act of 2022, depending on how the enabling legislation is written: Will hydro be defined as a “renewable” source of energy? Given that people define “renewable energy” differently, we thought it would be helpful to provide a more granular look at how plans to build renewable energy break down.


The “run to the sun” has accelerated in recent years. In a category once dominated by wind power, plans to build solar generation have taken a decisive lead, with 49% of planned renewable new-build capacity, or about 184 GW, set to begin construction over the next five years (Fig. 8). Areas with the greatest amount of planned solar generation construction include the Rocky Mountains (55 GW), Southwest (52 GW), Great Lakes (26 GW) and West Coast (13 GW). A huge countervailing factor that could limit the growth in new-build solar is the rise in prices that started to become evident in 2021. The supply-chain bottlenecks and soaring costs for materials have derailed or delayed some of these planned solar projects.


Among renewable projects, wind power has long been the hare to the solar industry’s tortoise. But for the next five years, wind power will fall into second place with about 22% of all new-build generation, or about 82 GW. The U.S. regions with the greatest amount of wind power project activity over the 2023-2027 period, measured on a GW basis, include the Rocky Mountains (about 23 GW), Midwest (17 GW), Southwest (10 GW), and New England and Great Lakes (9 GW each).

Figure 9: BESS operating capacity shoots up.

Figure 10: Actual and planned BESS capacity.


Plans to build battery energy storage systems (BESS) have skyrocketed in recent years. Developers have announced plans to build as much as 64 GW of BESS over the next five years. Data from the EIA shows that developers proposed to sharply increase large-scale BESS projects between 2022 and 2024. Operational BESS capacity more than tripled in 2021, to 4.6 GW from 1.4 GW in 2020, according to the EIA (Fig 9). Most of that capacity was being deployed by regional transmission organizations (RTOs). Going forward, construction of new BESS capacity is expected to surge. The EIA projects BESS capacity will shoot up from an estimated 4.6 GW in 2021 to about 22 GW by 2025 (Fig. 10). About 382 BESS projects are scheduled to be built over the next five years, valued collectively at about $81.1 billion. The regions with the greatest amount of BESS construction activity are the: Rocky Mountains, with 76 projects valued at $33.3 billion; Southwest, with 109 projects valued at $23 billion; and West Coast, with 76 projects valued at $12 billion.


The first iteration of the nuclear renaissance looks like it will be ending with a whimper, not a bang: the last new-build nuclear power project, the two-unit addition to the Alvin W. Vogtle Nuclear Power Station, is scheduled to finish construction in 2023. Years late and billions of dollars over budget, the Vogtle unit additions, totaling 2,234 MW, were expected to be the showcase of a revived nuclear industry when they were announced in 2008.


The two new units now have an estimated $32 billion price tag, nearly three times the original cost of $12 billion. If the units are brought online in 2023, it will be roughly seven years after the first unit was scheduled to begin commercial operations. The owners, led by project manager Georgia Power Company, are embroiled in litigation over who pays what for the project. And GPC can expect some tough questioning from the Georgia Public Service Commission when prudency hearings begin.


As difficult as the Vogtle experience has been, and for the Virgil C. Summer Nuclear Power Station before it, at least those plants succeeded in getting steel in the ground. Another nuclear plant announced at the same time as Vogtle, the Green River Blue Castle Nuclear Power Station in Utah, hasn’t made it out of the starting gate, and may never. That two-unit project, with total generating capacity of 2,000 MW, has been under development since 2008. It was designed to use two Westinghouse AP1000 reactors before Westinghouse exited the nuclear business with a 2017 Chapter 11 bankruptcy. Currently, the developer plans to begin construction in 2025. There are more questions than answers for that Utah project.


For a lot of reasons, utility leaders have been looking elsewhere for carbon-free generation that can be dispatched. The thinking now is the future is smaller — specifically, small modular reactors (SMR). One SMR design, from NuScale Power, received an approval from the U.S. Nuclear Regulatory Commission in August 2020. The Utah Associated Municipal Power Systems is trying to develop SMRs at Idaho Falls, Idaho. And Terra Power is eyeing construction of a different type of nuclear reactor, a sodium-cooled plant to be built at a soon-to-be retired coal-fired power plant in Wyoming. Both of those projects are scheduled to begin construction toward the end of the 2023-2027 timeframe. Also near the end of 2023-2027, the Tennessee Valley Authority and OPG (Ontario Power Generation) plan to begin construction of SMRs in Oak Ridge, Tennessee.


The Inflation Reduction Act law contained production tax credits for nuclear, recognizing its role in decarbonizing the electricity industry. IIR doesn’t think those tax credits will be enough, on their own, to lead to new-build nuclear power plants over the next five years, but they would help keep existing plants open. On that front, license-renewal applications for several plants are likely over the next few years, including Comanche Peak (Units 1 & 2) in late 2022, Perry in 2023 and Clinton in 2024. IIR also is tracking almost $1.5 billion in scheduled maintenance activity and more than $33 billion of in-plant nuclear capital spending over the next five years. These figures don't include new-build nuclear construction projects.


In another sign of a nuclear resurgence, some in California are advocating that Diablo Canyon remain open after its scheduled closure dates of 2024-25, to provide generation and grid support for the energy-hungry Golden State.


Project spending by commercial, industrial, and institutional (CI&I) customers to construct non-utility generation in the U.S. has increased in recent years, and  IIR expects that trend will continue over the 2023-2027 period. There are various drivers:

•	Renewable onsite generation is being constructed by CI&I customers for decarbonization or GHG-reduction goals.
•	Some large customers have been investing in onsite generation to ensure always-on power.
•	Some are building onsite generation to offset the rising cost of electricity from utilities.
•	Large energy-hungry operations like data centers and bit-coin-mining operations have built industrial energy producers (IEPs) to ensure predictably priced power.
•	Local environmental regulations are causing some to replace diesel-powered generators with natural gas or even renewable natural gas.
•	Some power-sensitive manufacturers have resorted to building generation when local power quality is low.
•	CI&I customers that are remotely sited are installing independent power generation to ensure 24/7 operations. 

Sometimes this non-utility generation powers a microgrid. Other times it is for standby or emergency uses. As more companies in the CI&I sector tabulate the true cost of power outages or low power quality, we expect a growing number will choose to install their own generation.


New opportunities for this generation are presenting themselves. Although the idea behind distributed generation is that it will be used to power a particular site, ISOs and RTOs increasingly are seeking to interconnect the non-utility generation with the grid in order to provide reserve power or voltage support when grid-connected generation is stressed or stretched. Several independent system operators (ISOs) and RTOs across the country count on these resources to be ready to operate when the grid needs them. ERCOT, the system operator that supports most of Texas, is counting on these generators. Several times during 2022, ERCOT has called upon these resources to help meet the state’s peak electric demand.


Other states, such as New York and California, are pushing to connect these independent energy generators to their respective grids. Some studies have shown that use of onsite generation assets can cut overall power generation spending by 20% or more. As the rising price of natural gas pushes up the price of power purchase agreements, the installation of onsite power assets is becoming more appealing. IIR is tracking plans to spend more than $10 billion on non-utility generation over the 2023-2027 period. That number does not include smaller generation assets, such as rooftop solar or generators that have less than 300 KW of capacity.


Non-utility generation, like all other segments of the power business, is working to repair its damaged supply chain. The current three-year wait for transformers, plus bottlenecks and rising costs for solar photovoltaic and battery energy-storage materials, are evidence that broken supply chains are nowhere near repaired.


Microgrids are becoming more popular among CI&I customers for the same reasons as independent energy production. When powered by renewable generation, microgrids sometimes are part of an organization’s decarbonization push. When powered by fossil fuels, microgrids may backstop utility-supplied power. Microgrids can be part of grid strengthening and hardening, as we see after each bout of extreme weather.


Spending on microgrids could reach several billion dollars annually during 2023-2027. CI&I customers and utilities are finding that microgrids can fill an important need. Some utilities deploy them as part of a multifaceted effort to prevent wildfires, or to support remote communities at risk of outages.


The industrial sector looks to microgrids for onsite power during times of need and for protection against cybercriminals. Microgrids also provide power to the grid during peak demand. Industrial Info is tracking plans to invest more than $2.4 billion in microgrids over the next five years, (not counting potential commercial or residential). Microgrid projects are experiencing supply chain shortages, and competition for required skilled workers and equipment.


In the same way that transmission organizations and local utilities sometimes call on independent energy generators to fire up and provide generation or capacity to the grid during times of high demand or resilience events, microgrid operators are receiving similar emergency requests for grid support.


Over the 2023-2027 period, we expect new-build power to be characterized by market disruptions including: Technologies that generate electricity or support transmission and distribution; economic assessments of options; environmental regulations and exigencies surrounding generation; the regulatory framework; inflow of federal funds to support generation technologies; and consumer expectations.


The predicted rise of electric transport will likely add new strain to electric distribution networks and generation. But now, the power industry faces another disruption from employee expectations. A growing number want greater work flexibility. If employers want to win the war for talent, they need to learn to flexible and responsive to this aspect of industry disruption. 

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Britt Burt is Vice President of Global Power Industry Research for Industrial Info Resources (IIR), which is headquartered in Sugar Land, Texas, and has offices in North America and around the world.

Brock Ramey is a North American Power Specialist for IIR, which provides global market intelligence for companies in the power, heavy manufacturing and industrial process businesses. For more information see www.industrialinfo.com or email powergroup@industrialinfo.com

Articles

CAN ANYTHING REVERSE THE RUSH TO RENEWABLES?

U.S. POWER INDUSTRY OUTLOOK 2023

"Elections have consequences,” goes the political adage. That was particularly true for the electricity generation business during the first year of the new administration. On Day 1, President Biden issued a flurry of executive orders, including one to make the electric generation business carbon-free by 2035 as a step toward a net-zero carbon economy by 2050. 

All federal agencies were instructed to review, with an eye to reversing, all actions taken by the Trump administration that might conflict with or undermine the new president’s commitment to decarbonize the electricity business and the broader economy. 

“Confronting the carbon crisis” became a catchphrase. In some ways, this follows in the wake of the electricity business, which has been decarbonizing for years. That trend has been the product of federal and state tax incentives, state regulatory mandates, and technological gains that have improved the cost competitiveness of renewable energy. A growing preference for no- or low-carbon electricity also continued to gain traction among consumers and businesses during 2021.

A January 20, 2021, executive order revoked several executive orders from his predecessor on energy and electricity. Other Day 1 moves included returning the U.S. to the Paris Agreement and establishing an interagency working group to determine the social cost of greenhouse gases. Former EPA Administrator Gina McCarthy also became the first-ever White House national climate advisor. 

“The world must be put on a sustainable climate pathway to protect Americans and the domestic economy from harmful climate impacts, and to create well-paying union jobs as part of the climate solution,” the executive order stated.

The U.S. transformation from hydrocarbon-based electric generation to lesser or non-emitting generation accelerated during 2021, and most experts see further acceleration in the years to come. 

Although the COVID-19 pandemic cut overall electricity demand by 3.9% in 2020, the virus did not alter the existing trend to build fewer new power plants that burned coal or gas. For the 2022- 2026 period, Industrial Info Resources (IIR) expects renewables will continue to constitute the overwhelming majority of new-build U.S. electric generation projects, accounting for about 88% of all new electric generation capacity. Gas will account for about 11% over that five year period, with nuclear, fuel oil and coal sharing the remaining 1% of new generation construction (see map).

About 316,000 megawatts (MW) of new-build generation projects are being tracked with a scheduled construction start date between 2022 and 2026. Not all planned projects will be constructed according to their original schedules. Depending on the technologies involved, and developers’ ability to secure financing, offtake arrangements, and regulatory support, we typically see between one-quarter and one-half of all announced projects delayed or cancelled. But then again, new projects are announced on a near-daily basis. 

While all 316,000 MW of new generation are not expected to be built as announced, the trend for the 2022-2026 period is clear and consistent with longstanding projections: cleaner and greener new-build generation. 

And while coal has been out of favor in the new-build market for some time, the black rock certainly came to the rescue of existing electric generators and consumers in 2021. 

Once COVID-19 vaccines became readily available, U.S. consumers responded with a vengeance, driving up gross national product (GNP) and with it, electricity demand. For 2021, the U.S. economy is expected to grow 6.6%, and another 5% in 2022, according to mid-year 2021 projections from the U.S. Energy Information Administration (EIA). Based on projected strong economic growth (and assuming COVID is contained), the agency forecasts 2021 electric demand to grow about 2.7%.

Figure 1: Electric generators expected to increase use of coal in 2021, 2022 Source: Electric Power Monthly and Short-Term Energy Outlook reports, U.S. Energy Information Administration.

Rising electricity demand in 2021 came as natural gas prices were on the upswing, rising about 60% through the first seven months of 2021, to about $4 per million British thermal units (MMBtu). For 2021, the EIA projected gas will average $4.46 per MMBtu. 

Generators that could switch fuels increased their use of coal in 2021, driving up coal use about 17% compared with 2020 (Figure 1). The EIA’s preliminary estimate of coal use in 2022 by power generators shows a decline of about 9% in 2022, as asset owners switch back to what they assume will be lower-cost gas. But as wave after wave of summer heat drove up electric demand, gas prices similarly went upward while coal stayed relatively flat. Could coal hold onto some of its newfound gains in the electric fuels market in 2022? 

Figure 2: Coal inventories at U.S. generators forecast to fall below five-year average Source: U.S. EIA Short-Term Energy Outlook (July 2021).

Figure 3: Investors jump onto ESG train Source: United Nations Principles for Responsible Investment.

Electricity generators drew down on their coal inventories to meet rising demand, according to EIA estimates (Figure 2). Roughly 23% of U.S. electricity was generated by coal in 2021, up from 20% in 2020, the EIA said. In 2022, coal’s market share is expected to fall to 21%. Existing coal- and gas-fired generators continued their bare-knuckled fight in the electric fuels market, where a shift of a few pennies per MMBtu can cause generators to swing from one fuel to the other. 

New-build coal-fired generation, however, continued to struggle in 2021 and faces a bleak future over the 2022-2026 period. Another recent force increasing King Coal’s misery has been the rising influence of environmental, social and governance (ESG) investing, which effectively bans investment in the coal business. By some calculations, ESG assets under management (AUM) soared to more than $100 trillion by the end of 2020 (Figure 3). 

During 2021, generators across the U.S. announced plans to phase out coal in the pursuit of net-zero carbon emissions. That trend is expected to continue in 2022 and beyond. 

The Tennessee Valley Authority (TVA), for example, has retired or announced the retirement of about 8,600 MW of coal-fired generation. It is evaluating the impact of retiring the remaining 6,000 MW of its coal fleet by 2035. That retired generation has been replaced by adding nuclear, solar and gas-fired generation as well as upgrading its hydroelectric power stations. 

In a mid-year 2021 announcement, TVA said it planned to invest about $1 billion to build new gas-fired combustion turbine generators totaling approximately 1,500 MW. The new facilities will replace aging gas-fired combustion turbines. 

In announcing that decision, Jacinda Woodward, senior vice president of power operations at TVA, said, “As we continue to evolve our generation portfolio, natural gas is the right choice at this time because it provides the flexibility and reliability we need to add more solar energy. It’s important to remember that solar power is an intermittent generation source, but natural gas delivers reliable electricity even when the sun doesn’t shine.” TVA will continue to consider natural gas’ role in its fuel mix as it studies the closure of its remaining coal fleet by 2035 while adding about 10,000 MW of new solar generation. 

TVA’s announcement came during a year when asset owners from Oregon to Florida announced plans to accelerate their move away from coal. During 2021, coal plant closure announcements were made by numerous asset owners, including Consumers Energy, Alliant Energy, Vistra, GenOn, Xcel Energy, PPL, Minnesota Power, NRG, Mississippi Power, American Electric Power and Lakeland (Fla.) Electric. 

Figure 4: Planned new-build capacity additions jump sharply Source: Industrial Info Resources.

IIR expects a surge in renewable energy construction over the 2022-2026 period, which would push overall new-build generation for that period to nearly 316,000 MW, up nearly 50% from the five-year plans of only one year ago (Figure 4).

At mid-year 2021, roughly 42,000 people were working as coal miners, up slightly over the year-earlier number of about 39,700. But the ranks of coal miners have thinned by about 75% since 1985, according to data tracked by the St. Louis Federal Reserve (Figure 5). 

Figure 5: U.S. coal-mining employment rises a bit. Source: Federal Reserve Bank of St. Louis. 

In recent decades, employment in industry has been crippled by increased automation of mining, coupled with demand being crushed by ever-more stringent environment regulations, and the rising competitiveness of substitute fuels like gas and renewables. 

U.S. generators closed more than 100,000 MW of coal-fired generation between 2010 and 2020, and another 34,000 MW is expected to close during the next five years, according to data tracked by IIR (Figure 6). Though some states, like Wyoming, have tried to erect legal barriers to the closure of coal mines and coal-fired power plants, most observers don’t think those laws will be upheld by the courts. Economics more than laws will determine the future of coal and coal-fired generation in the U.S. 

Over the 2022-2026 period, construction is unlikely to begin on any new-build coal-fired power plants. Capital spending at coal generators will be for environmental remediation, particularly cleaning up coal ash ponds, and in-plant capital improvements like turbine upgrades.

Figure 6: U.S. coal-fired generating capacity retirements, actual and planned Source: Industrial Info Resources.

Construction on about 35,000 MW of new-build natural gas-fired generators is expected to start during the 2022-2026 period. That’s about 11% of the 316,000 MW of new generation that developers plan to begin building during that fiveyear timeframe (Figure 7). The areas with the greatest amount of planned new-build gas generation are the Great Lakes, the Mid-Atlantic, the Southwest, the Rocky Mountains, and the Northeast. Very little new gas generation is scheduled to be built in the Southeast, Midwest, or West Coast. 

Figure 7: U.S. planned new-build gas generation continues to decline Source: Industrial Info Resources.

Developers and asset owners who have delayed or cancelled gas-fired, newbuild generation typically cite “market forces” as the reason for their decision. That covers a wide range of factors, including an inability to obtain financing, reach offtake agreements, or secure transmission rights. As gas pipelines start to run into opposition, stymied gas pipeline projects like the Atlantic Coast Pipeline are another market force with which developers have to contend. Finally, another powerful market force is a state’s regulatory regime, and several have turned against gas in recent years.

Renewables will continue to constitute the overwhelming majority of new-build U.S. electric generation projects. 

That’s certainly the case in California, Arizona and New York, where state commitments to reduce greenhouse gas emissions in the electric sector or increase the percentage of renewable energy in the electric mix work against gas. In addition, methane emissions have emerged as another market force working against natural gas generation. Methane is a much more potent greenhouse gas than carbon dioxide, at least over the short term.

The cancellation or delay of approximately 48 new-build gas-fired power plants has been documented in 25 states that were scheduled to begin construction in 2021. The total investment value of those plants was about $12.6 billion. As more states, and possibly the federal government, enact measures that cut against gas-fired generation, the number of new-build generation projects should continue to decline over the 2022-2026 period. 

Figure 8: Planned new-build gas-fired generation, by region over five-year periods (GW) Source: IIR.

About 35,000 MW of new-build gas-fired generation is scheduled to begin construction between 2022 and 2026. That is down a little over 10% from last year’s five-year tally and about 60% less than what was planned to kick off construction during the 2019-2023 period.

It was not that long ago that the power industry was proclaiming a “dash to gas,” as coal plants closed and before sharp declines in renewable energy costs. But recent trends shows a dramatic slowdown in new-build gas generation. Though most U.S. regions show a decline in planned gas-fired project kickoffs, the most dramatic declines are in the West Coast and Southwest (Figure 8).

Figure 9: Proposed New-Build Generation, Renewables vs. Gas Source: IIR.

Gas’ loss has been renewables’ gain. Renewables are now projected to account for about 88% of all U.S. new-build generation capacity over the 2022- 2026 period, roughly eight times the amount of gas-fired generation scheduled to be built over that time (Figure 9). That gap has widened over time. In 2018 looking at a five-year construction cycle between 2019 and 2023, renewables were scheduled to account for about 57% of all new-build generation scheduled to be built in the U.S compared with 41% for gas. But renewables’ improving cost competitiveness stemming from efficiency gains, coupled with a growing embrace by regulators and Corporate America, has widened its lead in the new-build race.

Over the next five years, solar is expected to surpass wind for the first time in utility-scale renewable energy construction (Figure 10). The widespread popularity of rooftop solar, both for residential and commercial settings, is not reflected in Figure 10, so the growing popularity of rooftop solar likely would give that energy source an even larger slice of the renewables’ pie.

Fig. 10 Planned Renewables Construction, 2022-2026 Source: Industrial Info Resources.

About 1,450 renewable energy projects are scheduled to begin construction over the next five years. Those projects have a total investment value of about $390 billion. 

Again, all of those projects are unlikely to begin construction as scheduled. But over the next five years, the new-build renewable power business looks particularly green in the Rocky Mountains, the Southwest, the Great Lakes and the West Coast (Figure 11). 

Figure 11: Dollar value of planned new-build renewable energy generation Source: Industrial Info Resources.

Figure 12: Dollar value of planned new-build windpower, by region Source: Industrial Info Resources.

Nevada and Arizona are the states in the Rocky Mountain region with the largest dollar value of solar projects under development. In the Southwest, solar project activity is taking place almost exclusively in Texas. The Great Lakes region also has a robust pipeline of solar projects being developed, with Ohio and Indiana in the lead, followed by Kentucky and Illinois, according to project data being tracked. 

Although fewer wind projects are being developed than in prior years, mostly because the areas with the best quality wind resource already have been tapped, the Rockies, Midwest, Southwest and New England are the regions with the largest dollar-value of wind power projects scheduled to begin construction between January 2022 and December 2026 (Figure 12). The Rockies, Wyoming, New Mexico, and Arizona are the regions and states with the largest dollar value of wind projects under development, according to data tracked.

The $390 billion of renewable energy projects under development include 27 offshore wind projects valued at about $39 billion. The Atlantic Ocean is far and away the leading body of water for proposed offshore wind power projects. The Biden administration wants to see as much as 30 gigawatts (GW) of offshore wind power developed in the Atlantic Ocean by 2030.

When politicians try to fight against markets, markets often win. We saw that most clearly in the Trump administration, which unsuccessfully fought against market forces to try to restore coal in the electric fuel mix. But Biden is taking the opposite approach, working to accelerate market-driven changes already well underway.

While in years past renewable energy projects would have had to include the cost of a transmission line to bring the energy to a market hub, several renewable energy projects announced during 2021 plan to be built on or near large shuttered plants to take advantage of existing transmission infrastructure.

Examples are NextEra Energy’s plan to construct a 690 MW solar plant next to its closed Duane Arnold nuclear plant in Iowa, and Xcel Energy’s plan to build a 460 MW solar plant on the site of its soon-to-be-closed Sherco plant in Minnesota. There should be many more over the next five years. Use of existing transmission lines also enables a developer to fast-track their project around clogged queues in regional markets.

The outlook for new-build nuclear is as bleak as the outlook for renewables is upbeat. The only planned new-build nuclear project, the Blue Castle nuclear power station in Utah, continues to be developed, with a planned construction start date of spring 2025 and a projected start-up date of mid-2032. The Blue Castle project is expected to utilize two 1,100-MW advanced passive reactors from Westinghouse. This project has been on the books for more than a decade, and its projected costs have mounted as its commercial operation date has been pushed back. There is a very low probability of this project ever getting built.

At the other end of the spectrum, a small modular reactor (SMR) project called the Carbon-Free Power Project continues to be developed by the Utah Associated Municipal Power Systems (UAMPS), a group of community-owned electric utilities across the intermountain West. 

In 2020, the group received a ten-year, $1.4-billion grant from the U.S. Department of Energy to develop and deploy 720 MW of SMRs in 60-MW modules. Originally, 12 were planned to be built at the Idaho National Laboratory in Eastern Idaho, with construction starting in 2025. But plans for that project were scaled back in mid-2021, as some UAMPS utilities rethought their participation in the project. 

Now, the UAMPS project envisions constructing only six modules, but a spokesperson for the group said these modules will be more efficient than previously thought. Instead of 720 MW consisting of 12 60-MW modules, the project now consists of six modules of 77 MW each, for a total of 462 MW.

Across the country in Tennessee, the Tennessee Valley Authority (TVA) is also contemplating SMRs as part of its plan to decarbonize generation. The agency has big hopes for the smaller nuclear generators, but its long-term resource plan does not contemplate construction beginning until 2027 at the earliest. 

The only new-build nuclear project still being constructed in the U.S. is the two-unit addition to the Alvin W. Vogtle Nuclear Power Station in Waynesboro, Georgia. Helmed by Southern Company subsidiary Georgia Power, Unit 3 expected to begin operating sometime during 2022. Unit 4 is scheduled to begin operating about one year later. 

As the project missed milestone after milestone in recent years, a construction oversight panel filed ever-gloomier reports about the costs and in-service dates of the two new units. A mid-2021 report from that oversight panel cast serious doubt on Georgia Power’s projected in-service dates for Units 3 and 4, and said construction costs could be as much as $2.4 billion over the most recent agreed-upon amount. 

Whenever those units are finished and whatever their eventual cost, expect a pitched fight at the Georgia Public Service Commission (GPSC) over how much of its investment Georgia Power can recoup from its customers. The unit addition’s other three owners, all municipal agencies, are not jurisdictional at the GPSC. But whatever that panel decides about Georgia Power’s 45.7% stake in the two new units could cast a long shadow over the other three owners’ regulatory decisions about the prudence of that investment, the quality of construction, and the effectiveness of construction management.

The other owners of Vogtle units 3 and 4 are Oglethorpe Power Corporation, a 30% owner, the Municipal Electric Authority of Georgia, which has a 22.7% stake, and Dalton Utilities, a 1.6% owner. Most of the value of work scheduled to be performed on nuclear plants over the next five years exists at the other end of the product life cycle: dismantling and decommissioning shuttered nuclear plants. A dozen closed nuclear stations are awaiting D&D work totaling about $19 billion. 

Roughly two dozen in-plant capital projects for nuclear generators are being tracked, including steam generator replacements, control upgrades, and extended power uprates. The value of this work is about $1.8 billion.

The outlook continues to brighten for battery energy storage systems (BESS) to become a more significant part of today’s marketplace (Figure 13). Regulators are providing incentives and allowing it to enter regional markets as a stand-alone generation resource. BESS is utilized for many applications, including: stand-alone generation resource; grid stability; renewable energy utilization; and storage for thermal generation.

Figure 13. Sharp increase expected in deployment of battery energy storage systems Source: US EIA.

Demand for BESS is rising, particularly in areas prone to natural disasters. The fast-paced push in the West Coast and Southwest to integrate these systems into electric markets is another factor creating a boom in this sector. 

In ERCOT, there is over 40 GW of BESS in early-to late-stage development being proposed for 2021-2023. This number may decline as projects confront permitting challenges, financing hurdles, and regional transmission constraints. 

Another driver for BESS growth is the late-2020 extension of the federal Investment Tax Credit (ITC) for solar energy. The guidelines grant ITCs to BESS assets based on its proximity to solar generation, its ownership, and whether it was being charged at least 75% of the time. The extension of the Production Tax Credit (PTC) for wind energy did not include a BESS provision. 

Like many other projects, BESS suffered COVID-19 supply-chain issues. The strong demand growth for lithium may act as a limiting factor in the near term, as projected demand for that metal, used in electric vehicles, cell phones, smart devices as well as battery energy storage projects, far exceeds estimated supply. There have been calls to expand lithium processing facilities in the U.S., but any such project would be years away from commercial operations. 

About 3.5 GW of battery energy storage that will become operational in 2021 is being tracked, an 80% increase over the capacity that began operating in 2020. Another 4.3 GW of BESS capacity is slated to come online in the U.S. by the end of 2022. The West Coast and Southwest are the regions with the highest level of project activity for BESS.

Currently, the U.S. has 115 operational microgrids that include over 2 GW of generation, according to the EIA. The referenced microgrids range from a segment of 500 kW to more than 100 MW.

Right now, these microgrids are being installed at military bases, universities and colleges, hospitals, police, fire and first responder stations, industrial complexes, government centers, and other settings where a high value is placed on having uninterrupted power. The annual spend to install microgrids is expected to be just below $1 billion in 2021. 

The pandemic dramatically slowed the deployment of microgrids in 2020 and 2021, and may not see a rebound until the pandemic and all its variants is conclusively defeated. COVID created a near-term pause in deployments, but growth should resume, possibly by mid-2022. The regions with the highest interest in microgrids are the West Coast and Southwest.

Natural disasters and prolonged power interruptions tend to drive microgrid deployment decisions, and there has been no shortage of natural disasters and power outages in recent years. Years of wildfires in the West, flooding, hurricanes, and the Texas grid breakdown of February 2021 are likely to lead a wider appreciation of the benefits of microgrids that utilize distributed generation such as solar or wind plus BESS. 

The cost of a microgrid will not be irrelevant in a company’s or agency’s planning. But we expect more projects will achieve financial viability when entities sharpen their proverbial pencils and take a closer look at the cost of a microgrid compared to the cost of power interruptions or unreliable power. 

Utility-scale microgrid projects, on the other hand, have encountered a variety of headwinds — including regulatory, permitting and financing — in recent years. Those headwinds have caused many projects to stall or be shelved. Construction costs continue to be a high hurdle to overcome at an estimated $2.6 million to $4 million per installed MW of capacity. 

State and federal grants for research & development have supported microgrid deployment. Congress is scheduled to consider a clean energy bill that includes up to $1.5 billion for microgrid R&D grants. About $2 billion in planned microgrid spending for 2022 is being tracked, a doubling of planned spending for 2021.

Over the last several years, distributed energy resources (DER) have become a more important element of the power generation business. As a category, DER includes a wide range of assets in smaller-scale settings, typically less than 10 MW in size. Types of DER include: small combined heat and power (CHP) units; wind; solar; battery storage; flywheel; biomass; waste-to-energy incinerators; small hydropower; fuel cells; reciprocating internal combustion engines (RICE); and generation that is part of a microgrid. 

DER also includes onsite power generation located at industrial or institutional sites such as colleges, universities, chemical processing plants, refineries, medical centers, military bases, manufacturing plants, and more. 

More than 29 GW of DER generation currently under development across the country is being tracked, with an additional 1.4 GW of generation in the early planning stage, with possible deployment by 2022- 2023. The regions with the largest planned spend on DER are the Southwest, Northeast, and Rocky Mountains. 

Orders 828 and 842 from the Federal Energy Regulatory Commission (FERC) determined that DERs deserve to be compensated if they provide generation or frequency support. Utility generation owners continue to have some concerns about FERC Order 842. 

In September 2020, FERC issued Order 2222, which expanded the definition of DER to include rooftop solar, electric vehicle charging system (EVC), and other micro-generation sources when coupled together. FERC followed that order with 2222-A, issued in March 2021, which removed other barriers to aggregated DERs in wholesale markets.

It is unclear whether full decarbonization of the U.S. electricity business can be achieved by 2035. But in the current business climate, decarbonization doubters have largely gone underground. Those advocating cleaner and greener power are driving the narrative.

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The Biden Administration stresses new-build renewables, but rising gas prices gave new life to coal-fired generators. 