Britt Burt and Brock Ramey

The U.S. Environmental Protection Agency (EPA) drafted a third set of greenhouse gas regulations using an explicit Congressional delegation of authority, but litigation is still expected. Although climate change has led to more weather extremes, decarbonization of the U.S. power sector remains a “two steps forward, one step back” exercise.

As the United States prepares to enter the third year of the Biden administration, with its priority to decarbonize the electric generation market, the challenges to decarbonization are so significant as to call to mind the Tennyson poem, “The Charge of the Light Brigade,” which chronicled the ill-fated attack launched by lightly armed British cavalry troops against better-armed Russian artillery forces during the Crimean War. As recounted by Tennyson, the British troops suffered a beating at the hands of the more numerous and better-equipped Russians:

Cannon to right of them, 
Cannon to left of them, 
Cannon in front of them Volleyed and thundered; 
Stormed at with shot and shell, 
Boldly they rode and well, Into the jaws of Death,
Into the mouth of hell
Rode the six hundred.

A seasoned dealmaker with 36 years of inside-the-Beltway experience as a U.S. senator, Joe Biden as President has notched impressive legislative victories to decarbonize the U.S. power industry. The Infrastructure Investment and Jobs Act, enacted in late 2021, and the 2022 Inflation Reduction Act, with $369 billion in federal support for renewable energy, will go a long way to reducing CO

U.S. Power Generation Capacity: Under Development with Construction Kick-off Scheduled During 2024-2028

In May 2023, the EPA issued its third set of draft regulations to reduce CO

emissions from current and future power plants. All significant accomplishments. But permanent? One wonders, given the forces that stand in opposition:

Congressional Republicans, furious about House Speaker Kevin McCarthy’s 11th-hour debt ceiling deal this past spring, are determined to claw back federal spending on renewable energy, among other items, under the rallying cry of fiscal austerity.

Coal-rich states such as Montana, Wyoming, West Virginia, Kentucky, and Utah have enacted various measures to impede the closure or sale of coal-fired generators in their states, prop up in-state coal mines, and preserve the flow of tax revenues into state coffers.

In the closing hours of the 2023 Texas state legislative calendar, lawmakers approved, and Governor Greg Abbott signed into law, a bill creating a $10 billion fund to support the construction of new gas-fired generation, as well as the modernization of existing gas-fired generators. Republican-elected officials and fossil-fuel interests staunchly oppose the EPA’s May 2023 draft Clean Air Act rule designed to limit CO

 emissions from power plants. Legal challenges are sure to come, perhaps even before the rule is finalized, and yet another trip to the U.S. Supreme Court appears likely. 

If such a legal challenge does make its way to the highest court in the land, the composition of the court seems unfavorable to those who seek to decarbonize the power sector. In 2022, the justices ruled 6-3 against an EPA effort to cut carbon emissions. Shortly after that decision, Congress closed the regulatory loophole that gave the justices such pause. Will the third time be the charm for this rule, or will the court find yet another reason to intervene?

These and other challenges to decarbonization emerged during 2023 and are expected to continue unfolding in 2024 and beyond to shape the U.S. new-build power business. The industry has an outlook that extends for decades, but small changes in the near term can lead to dramatically different outcomes in the long term.

That said, renewable energy continues to dominate the outlook for U.S. new-build power-generation projects scheduled to begin construction over the 2024-2028 period.

The transition to lower-emitting generation fuels has been underway for several years, but the 2022 Inflation Reduction Act’s direction of $369 billion of federal funds into renewable energy is expected to significantly strengthen a years-long trend of heightened investment in new non-emit-ting electric generation.

According to data tracked by Industrial Info Resources, 94% of all new-build power generation projects scheduled to begin construction in the United States between January 2024 and December 2028 will be for renewable energy (see the

Figure 1: Planned New-Build Generation, Renewables vs. Gas

That spending is expected to extend the rush to renewables, but what’s different about the 2024-2028 period is the dramatic increase in the projected volume of new-build construction: Developers plan to build about 482 GW of new generation over the 2024-2028 period, up 22% from last year and at least double the amount of any five-year period in the last 14 years (

By and large, electric utilities have found that their customers like and prefer renewable energy, provided it is cost-competitive with electricity produced from other fuels.

Figure 2: Planned New-Build Capacity Additions Shoot Up

The COVID-19 pandemic, now apparently receding into the rear-view mirror, turned much of the discussion about the energy transition into a rueful recognition of the importance of supply chains. In 2023, electric utilities were forced to defer, or rebid, planned renewable energy additions, citing rising component prices and delayed delivery dates. Evergy, an electric utility serving customers in Missouri and Kansas, caught some negative publicity from members of the environmental community in mid-2023 after it went public with a revised schedule and mix of generating options that included building new gas-fired generation, per requirements of its grid operator, and keeping some operating coal generators open past their planned retirement dates. Other utilities have had to rejigger their clean-energy plans, some more publicly than others.

Ultimately, state utility regulatory commissions, along with grid operators, have the whip hand in deciding what gets built where and when. We expect that the shifting economics of generating electricity will force several public utility commissions (PUCs) to revisit decisions made in earlier integrated resource plan (IRP) dockets.

Texas already has decided: Going forward, natural gas will play a bigger role in the state’s electricity future. Lone Star State politicians were quick to blame—incorrectly, as it turned out—renewable energy for the rolling blackouts and multiple catastrophes triggered by Winter Storm Uri in early 2021. More objective analysis found that frozen natural gas lines and poorly winterized thermal power plants bore a more signifi-cant share of responsibility for that event.

Never letting the facts get in the way of a good story, Texas politicians and the state’s grid operator, ERCOT, have been advocating for an increase in dispatchable, i.e., gas-fired, generation to ensure the lights stay on during weather extremes. The state has weathered some white-knuckled summer peaks in recent years, so the call for more dispatchable generation wasn’t all home-state hoopla.

In mid-2023, Republican Texas Governor Greg Abbott signed into law a bill to create a $10 billion fund to support building new-build gas-fired generation and modernizing existing gas power plants.

Republican-led energy-producing states like Texas, Montana, and Wyoming, among others, effectively are working in partnership with U.S. Senator Joe Manchin (D-WVa), chairman of the powerful Energy and Natural Resources Committee, to preserve the role of fossil fuels in the nation’s electricity supply.

Natural gas is expected to hold a strong share of the electric fuels market for the near term, accounting for approximately 41% of electricity generated in 2023 and 40% in 2024, according to the July 2023 Short-Term Energy Outlook produced by the U.S. Energy Information Administration (EIA). Coal’s market share is expected to continue weakening in the near term, sinking from 20% in 2022 to an estimated 15% in 2023, before rising slightly to 16% in 2024. Nuclear’s share of the electric generating mix is expected to hold steady at about 19% over the 2022-2024 period, while solar and wind are expected to continue gaining market share.

New-build coal-fired generation has been a rounding error in recent years, and the 2024-2028 period is no exception. “Early retirement” continues to be the watchword for existing coal-fired generation, with nary a new-build project in sight.

About 133 GW of coal-fired capacity has been retired since 2010, and over the 2024-2028 period, Industrial Info Resources (IIR) expects another 51 GW of coal genera-tion to be retired (

Figure 3: Coal-Fired Unit Retirements: Historical and Projected

But there are about 146 in-plant capital projects, worth an estimated $16.5 billion, that are scheduled to kick off at coal-fired power plants across the United States over the next five years. This broad category of projects includes automation; carbon capture, utilization, and storage (CCUS); debottlenecking; decommissioning and demolition (D&D); efficiency upgrades; environmental remediation; life extensions; upgrades; and uprates.

The states with the largest dollar value of in-plant capital projects are Wyoming (five projects valued at about $2.7 billion); Illinois (eight projects worth approximately $2.4 billion); Texas (19 projects valued at $2.2 billion); and New Mexico (one project worth about $1.3 billion).

The $16.5 billion of planned in-plant capital projects includes CCUS projects. A sharply increased federal tax credit of as much as $85 per ton of CO

 removed has led companies to schedule billions of dollars of CCUS projects to be constructed at coal-fired power plants over the next five years. We are tracking six CCUS projects, valued at $7.4 billion, that are scheduled to be built at stations in Illinois, Texas, Wyoming (which has three projects), and New Mexico over the next five years. These projects are expected to be vying for expanded federal tax credits under section 45Q of the federal tax code. 

Also included in that $16.5 billion sum are approximately 58 coal combustion residuals (CCR) remediation projects that are scheduled to begin construction by the end of 2028. The total investment value
(TIV) of these projects is about $3.6 billion. The states with the greatest dollar value of projects for remediating CCR, also known as coal ash ponds, are Montana, Texas, Indiana, and Missouri.

Coal power plant decommissioning and dismantling (D&D) projects also are included in that $16.5 billion in-plant capital sum. The value of these D&D projects is about $2.3 billion. The states with the largest dollar value of D&D projects include Ohio, Michigan, Indiana, Texas, and South Carolina. 

The grim outlook for coal-fired generation in the United States mirrors the outlook for coal mining. The number of people engaged in coal mining has leveled out at about 41,000, down more than 75% over the last two generations, according to the St. Louis Federal Reserve Bank (

). And the amount of coal burned to generate electricity, after briefly surging in 2021 and 2022 as utilities restocked their fuel-depleted piles, is expected to fall in 2023 and 2024 (

Figure 4: Coal Mining Employment Flattens

King Coal’s woes are a result of many factors—regulatory, legislative, economic, and technological—but another significant contributor is the rise of so-called “respon-sible” investing, where bankers and investment managers at pension funds, mutual funds, and other sources of public and private capital use environmental, social, and governance (ESG) metrics to identify companies in which they want to invest—and those they don’t.

Figure 5: Coal Use at Electric Generators Expected to Decrease in 2023, 2024

Institutional investors with more than $120 trillion of assets under management have adopted the U.N. Principles of Responsible Investing (PRI), which don’t permit investing in or lending to companies in the coal business (

Because each trend spawns a counter-trend, there has been some recent push-back against ESG, or “responsible” investing: 18 states have enacted or proposed legislation restricting the state from doing business with companies that use ESG investing criteria, arguing that those criteria mask a political agenda. 

Figure 6: Surge in Cumulative Investments in “Responsible” Companies and Funds

During 2023, coal generators in a variety of states, including Michigan, Utah, Pennsylvania, Tennessee, West Virginia, and Texas, either were closed or announced premature retirement decisions. Asset owners claimed a variety of reasons for the decisions, but, broadly speaking, there were two reasons: 1) renewable generation, even allowing for its recent price increases, is still more economical than operating existing coal plants; and 2) state and federal environmental regulations and laws made it uneconomic to continue operating those plants.

A countervailing trend to coal unit retirements is the delay in planned retirements due to delays in interconnecting renewables to the grid, supply chain bottlenecks, and permitting delays. In the face of rising electric demand and continued uncertainties surrounding new-build projects, an operating power plant—even one that burns coal—is worth more than projects that remain on the drawing board.

Natural gas generation is feeling the fossil-fuel “splatter” effect that has hobbled coal-fired generation. Even though natural gas only emits about half the CO

 as coal when burned for generation, gas-fired generation still contributes to global climate change.

After a decade when developers made a “dash to gas,” that bloom is off the rose. Only about 4.7% of all new-build generation scheduled to begin construction over the next five years will use gas as a fuel. By contrast, as shown in 

, five years ago that percentage was 41%. A decade ago, that percentage was a still respectable 36%. Gas’ share of the electric fuel market should rise over the next five years, as Texas begins disbursing its $10 billion to support dispatchable generation. But for now, the new-build gas market remains a shadow of its former self.

The regions with the largest share of planned new-build gas generation are the Mid-Atlantic (15.6%) and the Great Lakes (13.6%). At the other end of the spectrum, the regions that plan to build the least amount of gas generation over the 2024-2028 period are New England (0.1%), the Rocky Mountains (0.3%), the Southeast (0.7%), and the Midwest (1.6%). All told, IIR expects about 19 GW of new-build gas generation to be built over the next five years.

By contrast, about $19.1 billion of new-build natural gas-fired generation projects that were scheduled to kick off during 2024-2028 have been canceled or placed on hold, according to IIR’s data. The states with the greatest dollar value of project delays or cancellations are Texas (nine projects valued at $6.6 billion), Michigan (six projects valued at $ 2.5 billion), West Virginia (two projects valued at $1.4 billion), and Florida (six projects valued at $1.1 billion). 

As large as these numbers are, they pale in comparison with the prior five-year period (2019-2023) when developers canceled or placed on hold 224 proposed new-build natural gas-fired projects valued at $80 billion. For that period, the greatest dollar value of cancellations and project delays were Texas (41 projects valued at $18.2 billion), Pennsylvania (25 projects valued at $7.7 billion), Virginia (seven projects valued at $4.9 billion), Ohio (eight projects valued at $4.5 billion), and New Jersey (seven projects valued at $4 billion). 

The wave of proposed gas plant cancellations and deferments doesn’t reflect the sharp political divide between blue and red states. Deep-red states like Texas, Florida, Indiana, and Ohio are among the leaders in gas-fired project cancellations or deferments, alongside deep-blue states like California, New Jersey, New York, and Pennsylvania.

Whatever the drivers—remember Tip O’Neill’s famous quip that all politics is local—the dash to gas has slowed dramatically. What could revive it? Widespread generation-related power outages. Perhaps Texas had solid reasons—beyond supporting the home team—to create a $10 billion fund to build or modernize gas-fired generation. 

As the United States sweltered under an unrelenting heat dome during the summer of 2023, fingers were crossed that power plants that were being run hard and long would hold up.

Developers who canceled or placed proposed gas-fired power projects on hold cited the shifting economics of electricity generation, driven by technology advances and regulatory or legislative mandates to build non-emitting generation. For example, New York’s plan to fight climate change envisions 70% of all electricity coming from non-emitting generation. California’s renewable portfolio standard (RPS) requires 60% of electricity to come from renewables by 2030 and 100% by 2045. 

The Golden State recently reported that RPS-eligible resources accounted for more than 37% of electricity delivered to custom-ers in 2021. But there are signs that the Golden State may be rethinking its stance on gas, at least for the near term. In a mid-year 2023 article, “California just can’t kick its coastal gas plant addiction,” the 

“Three natural gas-fired power plants in Huntington Beach, Long Beach and Oxnard were supposed to shut down in 2020, under a regulation designed to protect marine life. But (in 2020) officials voted to let the polluting generators keep churning out power another three years, just a few weeks after California experienced its first rolling blackouts since the early-2000s energy crisis. Now regulators are gearing up to approve another three-year extension, which would allow the plants to run through 2026. It’s only the latest illustration of the difficult balancing act California faces in its quest to phase out planet-warming fossil fuels and show the rest of the world that addressing the climate crisis is possible.”

The hand of environmental regulators in the state was forced after several summers of wildfires and power outages led to unpopular public safety power shutoffs (PSPS), where investor-owned utilities were given permission to preemptively shut off power in certain areas under red-flag conditions: high heat, low humidity, and high winds. Those conditions, coupled with failing utility equipment, have sparked extremely destructive wildfires in recent years. But even the PSPS could not stop rolling blackouts in certain areas during the blazing hot summer of 2022.

The state’s environmental regulators, forced to choose between people without power during broiling summers or fish that could be harmed by warmer water from gas-fired power plants, opted for people over fish.

The decision also was shaped by the state’s deepening “duck curve,” in which there is a surplus of renewable power during off-peak periods, like mid-day during the summers, and a shortfall during summer afternoons. Dispatchable gas-fired generation to the rescue! At least, for the short term.

California has not greenlighted a new-build gas power plant. Instead, it is trying to get a few more years of service out of the gas-powered generators on the coast, until battery energy storage becomes large enough, reliable enough, and economically viable so that it can replace gas generation. Gradually, gas generation will fade in California.

But gas is proposed as the fuel to power several large planned CCUS projects in the Golden State. Overall, gas will be used in about 4% of new-build generation constructed in the western United States over the next five years; by contrast, developers plan to build far more renewable generation—about 49 GW worth—in that region over that timeframe.

Gassier regions include the Great Lakes, where about 6 GW of new-build gas generation is slated to start turning dirt over the next five years. Developers also plan to begin construction of about 5 GW of gas generation in the Southwest during 2024-2028. In the Mid-Atlantic, about 3.6 GW of new gas generation is expected to begin construction over the next five years.

Electric asset owners have paid more volatile prices in recent years when com-pared with the quieter period of 2015-2020 when prices averaged a little more than $3 per million British thermal units (MMBtu) (

). But Winter Storm Uri in early 2021, and Russia’s invasion of Ukraine in early 2022, briefly brought gas price volatility back with a vengeance, according to the EIA. Market forces of supply and demand have since reasserted control, driving pieces back down to pre-Uri levels.

Figure 7: Gas Prices Paid by Electric Generators since 2002

Electric generators are expected to pay an average of between $3 and $4 per MMBtu during 2023 and 2024, the agency predicted. Longer term, the EIA expects gas use for electric generation to fall about one-third, from approximately 12 trillion cubic feet (Tcf) in 2022 to less than 8 Tcf by 2030, though the agency’s Annual Energy Outlook acknowl-edged there could be a high level of variance under alternate scenarios (

). Demand for gas among electric generators will fall as renewables capture market share.


In mid-2023, as heatwaves broiled large sections of the United States, grid operators and the North American Electric Reliability Corp. (NERC) warned, once again, that the U.S. electric supply was one banana peel away from a catastrophic crash. Judging from the surge in announced new-build generation plans in recent years (

), developers and utilities have taken notice, though only 5% of new-build generation over the 2024-2028 period is expected to be fired by natural gas (

Figure 8: Gas Demand From Electric Generators Projected to Decline Through 2030

King Coal ruled the electric kingdom for most of the 20th century. Gas was great—for a decade or two. Now, we are several years into a period where renewables rock.

According to data tracked by IIR, about 460 GW of new-build renewable generation is scheduled to begin construction over the next five years, roughly 94% of all new generation.

Our traditional caveat applies here. IIR doesn’t believe all this planned new generation will begin construction accord-ing to this schedule. This is particularly true for renewable generation, which has become more competitive over the years but still has some reliance on state and federal tax credits and incentives.

Our power plant database continues to show a high level of dynamism for planned renewable generation: Each day, new projects are added to our database while others are deferred or canceled. In our experience, as much as half of all planned renewable generation projects eventually are canceled or placed on hold—nearly double the rate for proposed gas-fired generation.

No matter how the future unfolds, this is what we know today: Renewables are expected to account for approximately 94% of all planned new-build generation projects in the United States over the next five years.

By region, the areas with the greatest planned reliance on new-build renewable energy are New England (99.9% of all scheduled new-build construction), the Rocky Mountains (99.1%), the Midwest (98.3%), and the Northeast (96.3%). The least green regions, the Great Lakes and the Mid-Atlantic, still show renewable energy projects accounting for more than 80% of planned new-build power projects over the 2024-2028 period.

By type of generation, solar continues to be the leader: Approximately 45% of all new-build renewable generation built over the next five years is expected to be solar, continuing a yearslong trend where power from the sun is rising, while wind power is slowing (

Figure 9: Solar Owns a Strong Plurality of the New-Build Renewable

Battery energy storage systems (BESS) continue to make sharp gains in new-build construction kickoffs: Those systems are expected to account for nearly 20% of all new-build renewable generation over the 2024-2028 period, up from 17% last year and virtually nothing in the prior years.

This extraordinarily green future may not fully come to pass if Congressional Republicans are successful in clawing back some of the estimated $369 billion in investments designed to slash CO

Another potential headwind blowing against renewable generation is the yearslong interconnection queue, driven in part by the sheer number of proposed projects. Significant delays in connecting new generation have taken place at most RTOs and ISOs, including PJM, MISO, SPP, and even ERCOT. In PJM, some projects have been delayed at least 24 months because they were unable to secure an interconnection agreement.

Like other sectors of the power industry, renewable developers and utilities are still working to remove supply-chain bottlenecks that have caused project costs to rise and in-service dates to be pushed back. Some sectors have fared better than others, but supply-chain delays have led to shortages of panels, inverters, and transformers.

Supply-chain snafus also are threatening plans to build wind turbines offshore. President Biden aims to have 30 GW of offshore wind operating by 2030, but the U.S. Department of Energy’s most recent estimate is that only 7 GW will be spinning by 2029. In addition to a global shortfall of underwater cables and inverters, these proposed projects face opposition from commercial fishermen and environmental activists worried about the impact offshore wind could have on their livelihoods and the underwater ecosystem, most notably whales and dolphins.

For all the forces driving the renewable generation buildout and the construction of new BESS, resource competition and prices have emerged as significant headwinds. Electric vehicles (EVs), BESS projects, and renewable energy generators all use, to some degree, the same minerals: lithium, nickel, cobalt, manganese, and graphite. Also, EVs use much more copper than their internal combustion counterparts. Demand for EVs, BESS, and renewable generation has surged, putting upward price pressure on the minerals.

There remains a pitched debate over whether the projected supply of these clean energy minerals will be sufficient to meet projected demand, and at what price.

The International Energy Agency (IEA) released a midyear 2023 report, 

, with an anxious undertone. “At a pivotal moment for clean-energy transitions worldwide, we are encouraged by the rapid growth in the market for critical minerals, which are crucial for the world to achieve its energy and climate goals,” said IEA Executive Director Fatih Birol. “Even so, major challenges remain. Much more needs to be done to ensure supply chains for critical minerals are secure and sustainable.”

The first unit addition to the Alvin W. Vogtle Nuclear Power Station was brought online on July 31, 2023, billions of dollars over budget and years late. Unit 4 is expected to begin commercial operations at the end of 2023 or the start of 2024. And thus, will end the much ballyhooed “Nuclear Renaissance,” perhaps better titled “Nuclear Renaissance Part 1,” as hopes are rising about its sequel: small modular reactors (SMRs). 

Presently, IIR is tracking about 2 GW of new-build nuclear that is scheduled to begin construction over the next five years. This includes: 

809 MW in the Rocky Mountains, split between the Utah Associated Municipal Power Systems (UAMPS) at the Idaho National Laboratory and TerraPower’s Natrium project at the Kemmerer brownfield site in Wyoming

798 MW in the Southeast at the Oak Ridge Clinch River brownfield site

320 MW in the Southwest, the Seadrift project is scheduled to be built at a Dow Chemical site in Calhoun County, TX 

Overall, new-build nuclear is expected to account for less than 1% of all new generation over the next five years.

Given the last 50 years of performance by the nuclear industry, with any type of reactor design and cooling systems, we have our doubts the industry can clear even that low bar.

In 2020, the UAMPS project secured a $1.355 billion grant from the U.S. Department of Energy to build up to 12 SMRs at 60 MW each. At the end of 2022, it reduced the number of units and increased the size of each SMR so that the net result was about 462 MW, down from the 720 MW originally envisioned.

One reason for the reduced scope: NuScale, the developer, in early 2023 said the target price for power from those SMRs had jumped 53%, to about $89 per MWh, up from an earlier estimate of $58 per MWh. Construction of the project is scheduled to begin in early 2025, and the units are expected to be operational by 2030.

The microgrid sector of the power industry continues to grow as the push for decarbonization, resiliency, and distributed energy resources moves forward.

Over the last couple of years, federal legislation, such as the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, as well as state-level regulations and the reliability-related conclusions of cities, military bases, commercial customers, and industrial concerns, have combined to expand the prospects for microgrid installations.

Moving into 2024, IIR expects spending in this sector to continue to climb, with more than $500 million in projects scheduled to begin construction that year alone. We expect that number will grow as we move deeper into the 2024-2028 period.

Industrial energy producers are feeling the push to install microgrids through either site-specific unit additions or through third-party agreements for microgrids to be installed onsite by a third-party owner-operator. One of the drivers in the industrial manufacturing sector is a renewed federal government push for all federal and military sites to have a microgrid installed by 2030.

Articles

Renewables continue to rock the new-build electric generation market, but gas-rich Texas, and some locals, are pushing back.

U.S. Power Industry Outlook 2024

Energy issues typically don’t move voters, with a few narrow exceptions. That seemed particularly true during the presidential election season. The Covid-19 pandemic and the social and economic calamity it created crowded out nearly every other issue.

Both presidential candidates had energy platforms. But rare was the TV talking head who argued for one or the other candidate based on their energy plans.

Energy companies have a keen interest in who occupies the White House, of course, no less than who controls the House and Senate. Regulations, laws and presidential decrees shape the business environment in which the electricity business operates. But as the Trump administration continued its efforts to achieve “energy dominance,” largely through regulatory action, the focus has largely shifted to courts and corporate boardrooms.

"Social trends and norms like working remotely could have a longstanding impact across the U.S. economy."

The transformation of the U.S. electric generation industry continued in 2020. However, several companies pressed the “pause” button on construction plans for new generation as the nation struggled to defeat the pandemic and repair the economic destruction it caused.

Still, the broad outlines for the 2021-2025 period are clear: renewables, often buttressed by battery energy storage systems (BESS), are expected to continue to crowd out coal and, increasingly, gas-fired new-build generation.

Electricity demand growth, anemic before Covid-19, took a dive as businesses closed and many worked remotely. Residential electric demand grew, but not enough to offset the loss of commercial & industrial load. As states reopened their economies during the summer and infection rates soared, commercial establishments like bars, restaurants and theaters were once again shuttered, causing electricity demand to fall a second time.

"Renewables, often buttressed by battery energy storage systems, are expected to continue to crowd out coal and, increasingly, gas-fired new-build generation."

Covid-19 therapies could come in 2021. But the reality is that the 2021-2025 period will start off on a depressed baseline for the industry.

Social trends and norms like working remotely could have a longstanding impact across the U.S. economy. Increased digitization means more work can be done remotely. Who wouldn’t opt for Zoom meetings in their den instead of a drive-time slog? Over the course of 2020, employees and employers grew more comfortable with remote working arrangements.

It’s unclear exactly how a shift to remote working could affect electric demand or plans to construct new generation capacity. Data tracked by Industrial Info Resources (IIR) shows developers plan to begin construction of about 214 GW of new generating capacity over the 2021-2025 period (Figure 1). That’s almost exactly the same as what was planned to kick off in the last three five-year periods (2018-2022, 2019-2023 and 2020-2024) and well above construction plans for the 2015-2019, 2016-2020 and 2017-2021 periods.

Figure 1: Top-line plans to build new generation. Source: Industrial Info Resources.

In aggregating planned construction kickoffs, all the planned construction activity won’t take place according to the developers’ schedule. In any given five-year period, roughly 30% of planned construction kickoffs will be cancelled or postponed; permitting issues, supply chain disruptions, regulatory decisions and inability to secure financing can reshape developers’ plans.

Approximately 80% of new-build generation scheduled to begin construction between 2021 and 2025 is expected to be renewables, mostly wind and solar (see map). Gas-fired generators will account for about 18% of new-build generation, with nuclear taking about 1% of the market.

Note that this is a particularly dynamic market. While their zero fuel costs give renewable energy projects a cost advantage compared with other types of generation, many renewable projects will require backup power. That points to increased demand for gas turbines and gas-fired reciprocating engines.

Figure 2: Consumption of coal by U.S. electric generators.
Source: Electric Power Monthly and Short-Term Energy Outlook reports, U.S. EIA.

Longstanding trends like the decline in coal used to generate electricity (Figure 2) and the declining number of people working as coal miners (Figure 3) accelerated in 2020. Though coal use by electric generators is expected to increase a bit in 2021, there is little reason to think either trend will take a significant, longstanding positive turn over the next five years.

Figure 3: Coal mining employment.
Source: Federal Reserve Bank of St. Louis.

Roughly 94 GW of coal-fired generating capacity was retired between 2010 and 2019, and another 33 GW is scheduled to retire over the next five years (Figure 4).

During 2020, state-level integrated resource planning (IRP) processes at utilities from Portland, Oregon, Tucson, Arizona and Jacksonville, Florida, all came to the same conclusion: accelerate the reduction or elimination of coal-fired power. Continued low prices for natural gas as well as improved economics of renewable energy, coupled with regulators’ wish to see increased funding for conservation and energy-efficiency programs, all combined to squeeze the share of the power market served by coal.

Figure 4: Coal-fired generating capacity retirements.
Source: Industrial Info Resources.

The U.S. Energy Information Administration (EIA) projects that the share of electricity produced by coal will fall from 24% in 2019 to about 18% in 2020 before rising to 21% in 2021. By contrast, coal accounted for nearly half of the electricity generated in the U.S. as recently as 2009. The EIA calculated demand for coal by electric generators would fall about 194 million short tons in 2020 from 2019 levels, but rise about 75 million short tons in 2021 (Figure 5).

Figure 5: Changes on demand for coal in the U.S. Source: EIA.

Coal advocates witnessed a number of negative developments for their interests in 2020, including:

• PacifiCorp released multibillion-dollar request for proposals (RFP) for new generation in mid-2020. Though billed as an “all-source” RFP, PacifiCorp’s interest was in securing renewables and closing coal-fired plants. In a separate RFP, the utility was seeking bids for as much as $1.8 billion in new transmission projects, mainly to carry electricity from remote sites to population centers. PacifiCorp had committed to closing about 2,800 MW of coal-fired generation by 2030. It accelerated the retirement dates for several of its units as part of the IRP process.

• Northern Indiana Public Service Company (NIPSCO) continued efforts to “green” its generation portfolio. It plans to retire about 1,600 MW, or nearly 80%, of its remaining coal-fired generation by 2023, and to exit coal-fired generation completely five years later. It came down to dollars and cents: Utility officials said replacing coal-fired generation with cleaner resources is expected to save customers more than $4 billion over 30 years. One of the coal-fired plants NiSource expects to retire in 2023 is the R.M. Schahfer Generating Station, which began operating in 1976.

• JEA (Jacksonville Electric Authority) and FPL (Florida Power & Light), joint owners of the 848-MW Unit 4 of Plant Scherer in Georgia, agreed in mid-2020 to retire that unit on January 1, 2022.

In decrying the early retirement of Unit 4 at Plant Scherer, Michelle Bloodworth, president and chief executive at America’s Power, a coal industry advocacy group, told a trade publication: “Coal-fueled power plants are one of the nation’s most-fuel secure sources of electricity, which means they are more reliable and resilient than almost any other source of electricity. The retirement of Unit 4 at Plant Scherer is part of an unfortunate trend that is leaving the electricity grid less fuel secure even though many policymakers are expressing concerns about the loss of fuel-security.”

However disruptive the premature retirements of coal-fired units may be to local communities, there’s little doubt that more are on the way.

Platte River Power Agency, a Fort Collins, Colorado-based joint action agency, in late 2018 adopted a goal of 100% non-carbon energy mix. Meeting that goal will require closing the recently built 280-MW Rawhide Unit 1 coal-fired plant in 2030, 16 years earlier than scheduled. Its generation will be replaced by wind, solar and battery energy storage.

Colorado Springs Utilities, also in Colorado, in June 2020 decided to close its two coal-fired plants by 2030 and ramp up its investments in renewables and battery energy storage. “The industry is moving to decarbonize, and we don’t intend to stand still,” Aram Binyamin, chief executive, said in an interview.

As has been the case for several years, there are no plans on the horizon to build new coal-fired power plants. Over the next five years, the commercial opportunities that exist within the coal fleet are in-plant capital, environmental remediation and dismantlement & demolition. We estimate those opportunities amount to about $10 billion over the 2021-2025 period.

For much of the last decade, gas and coal have waged an intense fight for market share among electric generators, with gas taking an ever-larger share of the fuels market (Figure 6). But in 2020, as states like California and New York adopted ever-stricter renewable portfolio standards (RPS) and decarbonization plans, gas’ share of the market, estimated at about 40%, began to slip.

Figure 6: Coal vs. gas in U.S. electric power generation. Source: EIA.

As shown in Figure 7, gas-fired power projects were all the rage for the 2018-2022 planned period, where four regions (Great Lakes, Northeast, Southwest and West Coast) each had plans to build between 10 GW and 20 GW of new gas-fired electric generation. Following a surge in the Southeast, where nearly 25,000 MW were planned to be constructed during the 2019-2023 period, new-build announcements have trended down sharply across the U.S. over the last two years.

Figure 7: Planned new-build gas-fired generation, by five-year period. Source: IIR.

Over the next five years, developers plan to build nearly 10 GW less gas-fired generation than they planned only a year ago: 39 GW in 2021-2025 vs. 48 GW in 2020-2024. As recently as 2018, developers had a five-year plan to build as much as 88 GW of gas-fired generation (Figure 8).

It’s not because the fuel isn’t cheap. Gas prices have been low for years. They are projected to stay there for the foreseeable future. Rather, state regulators, who must certify new-build construction projects, have grown increasingly concerned about how carbon dioxide emissions could be accelerating climate change. That, plus economic factors, have combined to squeeze new-build gas generation.

Regulatory and legislative mandates to increase renewables and cut carbon emissions have shrunk the electric generation fuel pie. At least seven states, including California, Arizona and New York, have effectively banned construction of new gas-fueled generators. Data we are tracking shows that developers have cancelled plans to build at least 33 gas-fired power plants across the U.S. valued at about $13.6 billion that were scheduled to begin construction between 2021 and 2025. Many cited market conditions for their decision. “Market conditions” could be a euphemism for an adverse regulatory environment, or low demand growth, or a variety of other factors.

Increased efficiencies have made renewables like wind and solar increasingly competitive with gas-fired combined-cycle plants. The growing competitiveness of renewables was shown in the U.S. EIA 2020 Annual Energy Outlook, released in early 2020. Though recognizing that there were variances across regions, the agency’s estimated levelized cost of electricity (LCOE) for new-build generation showed that, when the effect of tax incentives was included, renewables had a lower LCOE than a new-build gas-fired, combined-cycle generator. But when the tax incentives were removed, combined-cycle generation had a LCOE that was several dollars less on a megawatt-hour basis than renewables (Figure 9). This particular estimate of LCOE from the EIA was for new-build generators that entered service in 2022, measured in 2019 dollars, on a capacity-weighted basis.

Figure 8: Plans to build new gas-fired generation fall sharply. Source: IIR.

Figure 9: Levelized cost of electricity for new-build plants entering service in 2022 (measured in 2019 dollars). Source: EIA.

And then there is the PR push. Over the last decade, in an effort to burnish their credentials as environmentally conscious businesses, utilities started distancing themselves from coal and embracing gas. These days, many of those same utilities are embracing renewables and distancing themselves from gas. Utilities across the country, including Duke Energy, Florida Power & Light, Southern Company, American Electric Power and Salt River Project, announced plans of varying aggressiveness to decarbonize their generating fleet. Since those utilities already closed most of their coal-fired units, the current plan to decarbonize focuses on building renewables and either closing operating gas plants or cancelling plans to build them.

Across the U.S. during the 2010-2019 period, about 48 GW of gas-fired generation capacity was closed. Looking forward a decade, another 13.27 GW are scheduled for retirement.

As Yogi Berra said, “It’s tough to make predictions, especially about

Less-efficient, simple-cycle steam generators account for many of the gas plants that have been closed or are slated for closure. Some of those units had earlier switched from coal, but could not operate at an efficiency that kept them competitive. Similarly, some older combustion turbine plants are being replaced due to lower efficiency.

But slumping electric demand and continued declines in the cost to construct renewable generation have led some utilities and power developers across the U.S. to pull the plug on plans to build new high-efficiency gas-fired power plants in 2020:

• Florida Power & Light cancelled plans to build a 1,429 MW combined cycle gas-fired power plant in Hendry County, Florida. That project had a total investment value of about $1.5 billion.

• Invenergy cancelled plans to build a 900 MW power plant, the Clear River Energy Center, in Rhode Island. That project was valued at about $1.1 billion.

• Panda Power Funds cancelled plans to build the 1,000 MW, $850 million Hummel Power Station in Pennsylvania.

• Another casualty: The Long Island Energy Center, a 752 MW, $800 million project being developed by Caithness Long Island.

Xcel Energy, too, has been going green for years, investing billions of dollars in wind farms and solar facilities across its eight-state footprint. In mid-2020, the utility asked its Minnesota regulators for permission to accelerate the deployment of nearly $3 billion in planned projects centered on clean energy, resiliency, and keeping customer bills low. Notably, that plan did not include any new gas-fired generation. Xcel Energy was responding to a call from the Minnesota Public Utilities Commission for utilities to investigate investments they could make that would help the state’s economy recover from the economic devastation caused by the COVID-19 pandemic.

As shown in Figure 10, for all sorts of reasons, the dash to gas in the new-build generation market has slowed markedly from earlier years.

Figure 10: Proposed new build generation: Renewables vs. gas. Source: IIR.

As has been the case for the last few years, renewables are getting an ever-larger slice of the new-build generation pie. About 173 GW of new renewables capacity is scheduled to begin construction over the 2021-25 period.

As with all such projections, there will be cancellations and delays. Not all the planned capacity additions will begin construction according to schedule. Renewable energy projects have a higher rate of project fallout, about 30%, compared with 25% of gas plants that get deferred or cancelled. Still, project developers have a very large pipeline with a deep green hue.

The regions with the greenest hue include New England (where renewables account for about 99% of all scheduled new-build projects on a GW basis), the Southwest (89%), the West Coast (88%) and the Rocky Mountains (86%).

In terms of amount of renewable generation scheduled to be built, the Rocky Mountains region is in first place, with plans to build about 49 GW over the next five years, followed by the Southwest (37 GW), the Northeast (19 GW) and the West Coast (18 GW). As shown in Figure 10, renewables will capture four out of every five gigawatts of planned new-build generation.

Figure 11 shows that wind, with a market share of about 38%, is expected to be the largest type of renewable generation built over the 2021-2025 period. That’s a reversion to the mean and a reversal from last year’s analysis, when solar was nearly double that of planned wind farm construction, 51% to 26%, in the new-build renewables market.

Figure 11: Market share of new-build renewable generation. Source: IIR.

Wind’s fortunes are benefitting from a late-2019 one-year extension of the federal Production Tax Credit (PTC) and an increase in its value. Prior to that extension, wind projects that began construction in 2019 were eligible for a federal tax credit of about one cent per kilowatt-hour (kWh) of energy produced. With the one-year extension due for expiration at the end of 2020, wind energy projects beginning construction in 2020 were eligible for a credit of 1.5 cents per kWh. The federal largesse led to a surge in wind energy project construction in 2020.

Guidelines provided by the Internal Revenue Service (IRS) define “begin construction” as either starting pre-construction activities or legally committing to a portion of the heavy equipment needed for a particular plant i.e., construction could “start” on a project during 2020 but not be completed for several years.

The solar power industry did not get its Investment Tax Credits (ITC) extended or increased in that late-2019 tax bill. Solar generation projects are eligible for a 26% tax credit for projects that began construction in 2020. In 2021, the credit falls to 22%, and after 2021, the ITC falls to 10%. Federal tax policy has long had a significant impact on renewable energy project development. As a case in point, we expect that when the PTC expires at the end of 2020, wind farm construction will fall by nearly $9 billion from 2020 to 2021. Construction of solar power, conversely, is expected to rise in 2021 compared with 2020, so developers can capture the 22% ITC before it falls to 10%.

As they are sited remotely, far from load centers, the fate of many utility-scale renewable energy projects depends on having sufficient transmission system capacity to bring the green juice from where it is generated to where it is needed.

But when governments give, they also can take away. Some states, such as California, are starting to cast a doleful eye on large-scale transmission projects, seeing them as harmful to the environment and a throwback to the prior era of central station generation. Instead, some regulators advocate smaller-scale (less than 1 MW capacity) solar generation that could power a neighborhood. Of course, regulators have encouraged rooftop solar panels for residential, commercial, industrial and institutional customers for years.

Renewable energy projects also were hard hit by two supply chain disruptions in 2020: the Covid-19 pandemic and the Trump administration’s imposition of tariffs on solar panels imported from China, the world’s largest solar panel manufacturer.

By early 2021, construction on Unit 3 of the Alvin W. Vogtle Nuclear Power Station is expected to be finished, according to the most recent estimates from operator Georgia Power. Unit 4 is scheduled to come online sometime in 2022. That would end the saga of adding two units to Vogtle, a project originally budgeted at about $12 billion that more than doubled to an estimated $27 billion. The new units were originally scheduled to come online in 2016 and 2017. If the final cost tally holds at $27 billion, that would work out to about $12 million per megawatt of installed capacity — far and away the most expensive power project, both in aggregate costs and on a cost-per-MW basis, ever built in the U.S.

With the 2017 termination of efforts to add two units to the Virgil Summer nuclear power station, the Vogtle project remains the only nuclear project that is still being built in the 2021-2025 period. To be sure, there are other proposed new-build nuclear power projects that have scheduled construction to begin during that five-year period, but we doubt construction will begin on any of those projects according to schedule. There are serious questions as to whether any of those projects ever will be built.

The Tennessee Valley Authority (TVA) has been postponing the start of construction for small modular reactors (SMRs) at its Clinch River site in Tennessee almost since the project was first announced a decade ago. Current thinking is that construction could start in late 2027. The first SMR reactor design was recently approved by the Nuclear Regulatory Commission (NRC).

Another SMR project remains under development. This one, scheduled to be built in Idaho, has a 2023 kickoff year. We remain doubtful this project will hold to its schedule. The NRC approved its first 50 MW SMR reactor design in late August after a 42-month review.

That leaves the Blue Castle Nuclear Power Station in Utah as the only other new-build nuclear generation project scheduled to begin construction over the next five years. That two-unit project is expected to utilize two AP1000 reactors, the same reactors being deployed at the Vogtle station. Initial costs are estimated at $20 billion. That project, first announced in 2008, has gone through numerous changes and delays. At this point, ground is scheduled to be broken in 2025.

The disastrous experiences at the Summer and Vogtle stations long ago soured power executives on new-build nuclear. The Blue Castle or SMR projects may kick off near the end of the 2021-2025 period, but we doubt it. We remain unconvinced that any of those projects will ever be built.

With most power unit uprates having been either completed years ago, postponed or cancelled, that leaves refuelings and decommissionings as effectively the only nuclear power spending during the next five years.

"Power-sensitive retailers, manufacturers and healthcare organizations are growing more interested in microgrids."

It’s unfortunate that the power industry’s upbeat predictions about a nuclear renaissance a decade ago were never fulfilled. Had the shale revolution not lowered natural gas prices, and if renewable energy projects’ efficiencies stayed low, things might have turned out differently.

The Chapter 11 bankruptcy of Westinghouse in 2017 made a bad situation worse, but by then the industry’s enthusiasm for new-build nuclear power had long since evaporated.

The energy storage sector has experienced sharp growth in recent years. Looking out over the 2021-2025 period, spending is expected to increase dramatically. We include various technologies in this sector, including various types of battery energy storage systems (BESS), ice thermal storage, flywheels and fuel cells.

This sector is drawing so much interest because the technologies can be used to meet a variety of needs: generation support for renewables and fossil-fueled generation, grid stability and security for T&D assets, and microgrid integration, among other uses.

Not too long ago, energy storage technologies were an interesting but underexplored technology cluster. Now, storage has become a multibillion-dollar part of an industry in transition. But during 2020, development and deployment of lithium-ion BESS has been slowed by supply chain snafus created by the pandemic.

About 200 U.S. storage projects are currently being tracked, excluding pumped storage, which are scheduled to begin construction over the next five years. Their total value is about $21 billion. Roughly two-thirds of that projected spending is for BESS. Not all energy storage projects will begin construction according to their current timelines. But it is clear that the days of storage being dismissed as a niche industry are long gone.

Developers have scheduled construction to start on about 8 GW of BESS projects over the next 24 months across North America. Over the next five years, the U.S. regions with the greatest level of BESS activity are the West Coast, Rocky Mountains, Northeast and Southwest.

The 2021-2025 period is expected to see continued emphasis on BESS research & development — particularly related to safety — as well as increased numbers of pilot demonstrations and full-scale commercial deployments. BESS has become the belle of the electrical ball. Whether utilized as standalone power generation or in renewable energy or grid support, this sector of the power industry has expanded dramatically and is expected to continue doing so.

Regulatory treatment of investments in energy storage projects is critical. In 2018, the Federal Energy Regulatory Commission (FERC) issued Order 841, supporting the integration and compensation for energy storage. In a mid-2020 decision, the U.S. Court of Appeals for the D.C. Circuit upheld FERC’s Orders 841 and 841A, which established a framework for electric storage resources to participate in wholesale markets.

The court ruled that “keeping the gates open to all types of electric storage resources — regardless of their interconnection points in the electric energy systems — ensures that technological advances in energy storage are fully realized in the marketplace, and efficient energy storage leads to greater competition, thereby reducing wholesale rates.” The FERC adequately explained its refusal to permit a state opt-out for these resources, the court decided, noting that the burdens created by electric storage resources were outweighed by the benefits they created.

Most Regional Transmission Organizations (RTO) have been working hard to integrate storage. While an appeal of the D.C. court’s ruling always is a possibility, we think the court’s ruling clears away most of the regulatory clouds that have been hanging over energy storage.

"Spending by non-utilities on industrial energy production has taken off massively in recent years."

Spending on microgrids has increased in recent years, often driven by prolonged power outages following severe weather. Utilities and commercial & industrial customers have scheduled more than $1 billion of microgrid construction projects to start in 2020.

Microgrids have the potential to serve a wide array of commercial, industrial, institutional and military customers — really any type of non-residential customer that cannot tolerate prolonged power outages. Power-sensitive retailers, manufacturers, and healthcare organizations are growing more interested in microgrids. They are viewing microgrids either as a back-up for grid-supplied power or as a way to island themselves from the electrical vicissitudes of the grid.

The quality and cost of grid-delivered electricity exert a powerful impact on microgrid deployment. The higher the cost of grid-supplied electricity, the easier it is to make a case for a microgrid. Similarly, poor-quality power trips off advanced machinery at customer sites, leading to delays and waste.

Microgrids are increasingly showing up in airports, city centers, emergency response organizations, and as a backup for industrial sectors supply. Microgrids that include generation assets can play a role in reducing electric peaks from nearby utilities as well.

Another driver for growth could be the public safety power shutoffs (PSPS) enacted in California in 2019 to protect against wildfires sparked by electrical equipment. With California perennially in wildfire mode, we expect growing interest in microgrids by California-based businesses and institutions.

Renewables expected to surge and fossil-fueled power to sag in new-build generation market.

U.S. Power Industry Outlook 2021

EPA Administrator Andrew Wheeler said he thought the rule could lead to the construction of new coal-fired power plants. Shortly after the rule was published in The Federal Register, a coalition of 29 states, cities and the District of Columbia sued to block ACE’s implementation. It is likely that litigation over this clean air rule, like litigation over the Obama administration’s Clean Power Plan rule, could go all the way to the U.S. Supreme Court.

President Donald Trump’s goal of achieving energy dominance took several steps forward in 2019. In the power business, the most significant move was the finalization of the Afford-able Clean Energy (ACE) rule in June.







