Britt Burt and Brock Ramey

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.

Articles

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.

Deregulatory steps taken by the White House, Department of Energy, Department of Interior and Environmental Protection Agency have loosened regulation of the oil & gas industry. This has helped spur dramatic gains in domestic oil and gas production.

As yet, nothing similar has been achieved in power. Indeed, coal use to generate electricity (by utilities, independent power producers, and commercial and industrial customers) is projected to fall to 538,000 short tons in 2019 and 526,000 short tons in 2020, a decline of about 50% over the last 15 years.

While the fate of ACE may not be known for a year or more, no one has announced plans to build a new coal-fired generator since the draft ACE rule was issued more than a year ago. However, President Trump’s efforts to overturn President Obama’s environmental rule limiting carbon dioxide (CO2) emissions from power plants were welcomed by the National Mining Assn. as well as three major electricity trade groups. Despite the actions of the president and his EPA administrator, energy markets have spoken longer and louder. Nothing in the foreseeable future is expected to change that. Based on the tracking of planned spending in the power industry, we see an even more pronounced version of what has been observed for years: coal being eclipsed by natural gas and renewables as the leading source of new-build electric generation. One piece of good news: developers’ top-line plans to build new electric generation have trended upward in recent years, hovering around 212,000 megawatts (MW) for the three most recent five-year periods, well above the trough of roughly 160,000 MW from the three earlier five-year period.

Not all of this generation capacity will get built. Historically, roughly 25% are either cancelled or delayed in any given year. That average obscures differences between differently fueled power plants: natural gas-fired power plants have lower rates of cancellation or delay than renewable energy plants. Renewable energy generation, mainly solar and wind, is expected to account for 72% of all new-build generation projects scheduled to begin construction between 2020 and 2024. By contrast, renewables were expected to account for about 57% of all new-build generation between 2019 and 2023 in last year’s forecast. Natural gas is expected to be the fuel for approximately 26% of new generation over the 2020–2024 period. Last year, gas was projected to fuel about 41% of all new-build generation constructed between 2019 and 2023. The outlook is clear: U.S. new-build generation over the next five years is expected to be even greener, but less gassy, than in prior five-year assessments. As always, technology, economics and the sentiments of utility regulators play important roles in shaping the long-term outlook for U.S. power generation. Notable this year is the small-but-growing trend among state utility regulators to oppose new gas-fired generation in favor of renewables, distributed generation, battery energy storage projects and customer programs to reduce energy use or shift peak demand periods. Developers even plan to build more new fuel oil-fired generation than coal-fired generation over the next five years.

Coal Mining Employment Source: Federal Reserve Bank of St. Louis

The Federal Reserve Bank of St. Louis uses Bureau of Labor Statistics data to track employment across a range of industries including coal mining. Its most recent depiction of coal-mining employment documents the decline of coal-fired generation in the U.S. Three decades ago, nearly 180,000 people were working in the coal-mining industry. That dropped to about 53,000 in mid-2019.

Coal-mining interests point to the last three years, where employment increased by around 4,000, as evidence that the Trump administration’s commitment to end the “war on coal” has succeeded in staunching the bleeding. Before you can rebuild, mining interests would say, you have to stop the bleeding. U.S. asset owners have closed over 546 coal-fired units representing aggregate generating capacity of about 102,000 MW in the last decade, according to the Energy Information Administration (EIA).

Source: U.S. Energy Information Administration

Operators intend to close another 17,000 MW or so by 2025, the EIA said.Federal environmental regulations like the Cross-State Air Pollution Rule (CSAPR) and the Mercury and Air Toxics Standards (MATS) have played a role in dimming the future of U.S. coal mining and coal-fired generation. But the shale revolution that has unlocked trillions of cubic feet of low-priced natural gas, and continuing improvements in the technologies and economics of renewable generation, also played important roles.

In recent years, different partisan organizations have waged a war of words over “who killed coal?” Some overlook the role that automation played in thinning the employee ranks at coal-mining companies.

All of that notwithstanding, there is only one new-build coal-fired project scheduled to kick off over the next five years: a 75 MW power plant at a magnesium processing plant in Nevada scheduled to begin construction in 2023. That construction kickoff has a low probability of keeping its schedule. Most of the capital invested in the U.S. coal fleet over the next five years will go to in-plant maintenance, environmental compliance, turbine upgrades and the like. Over the next five years, about $7 billion is expected to be spent on these in-plant capital projects.

We expect to see heavy investments by utilities such as Dominion Energy, Northern Indiana Public Service Company (NIPSCO), Santee Cooper, the Tennessee Valley Authority and Vistra Energy as well as operating units of American Electric Power, Berkshire Hathaway Energy, Duke Energy, Entergy, NRG and the Southern Company.

Natural gas is expected to secure a smaller share of the new-build market over the next five years. It will account for about 26% of new-build construction, down sharply from recent years.

State utility regulators’ concerns about the potential over-reliance on gas-fired generation is one reason for the expected drop. In 2019, utility panels in California, Arizona and Indiana rejected utility plans to build gas-fired generation. Regulators in states that toughened their renewable portfolio standard (RPS) or ramped up their greenhouse gas emission-reduction program were called upon to issue decisions that would limit new gas generation. There has been a deceleration over the past year of plans to build new gas-fired generation in the Southeast, Great Lakes, South-west and Northeast regions.

The five-year outlook to build new gas-fired generation slipped slightly in the West Coast, New England and the Mid-Atlantic regions and rose a tad in the Rocky Mountains area. A number of utilities in the Southeast, including Florida Power & Light (FPL), Gulf Power and Tampa Electric have cancelled or pushed back the start of construction for new-build gas-fired generation. FPL has been shuttering older, less efficient fossil plants for years, replacing them with high-efficiency natural gas combined-cycle generation. But it made a turn toward the sun and energy storage during 2019.

Plans to build new renewable energy generation — defined as solar, wind, hydro and other — soared over the last 12 months. There are plans to begin construction on about 131,000 MW of renewable generation over the next five years. That is roughly 72% of all new-build generation. Historically, nearly 33% of renewable generation projects are either cancelled or delayed. Still, the dominance of renew-able energy is an inescapable fact, contained in integrated resource plans (IRPs) from utilities around the country.

New-build solar is expected to account for just over half of the renewable generation built between 2020 and 2024. The economics of renewable energy continue to improve. On a cost per kilo-watt of installed of capacity, wind generation costs have fallen 69% over the last decade, and further reductions are possible, according to a mid-2019 research report from Lawrence Berkeley National Laboratory and the National Renewable Energy Laboratory. Photovoltaic (PV) solar generation costs also have dropped more than 70% over the last decade, according to research from the Solar Energy Industries Association (SEIA) and Wood Mackenzie Power & Renewables. That cost decline has helped fuel dramatic gains and projected gains of PV deployment.

Planned growth for solar PV generation. Source: SEIA/Wood Mackenzie Power & Renewables

In addition to aligning well with environmentally conscious regulators, renewable energy is popular with customers, particularly commercial and industrial (C&I) customers who may be operating under a green supply chain mandate from headquarters. In years past, those directives led to increased purchases of green energy from local utilities, but more recently the drive to go green has meant installation of distributed renewable generation at a C&I customer’s site.

Deloitte’s Resources 2019 Study, released in mid-2019, noted that many U.S. businesses have targets for renewable energy procurement. Customers are driving this trend. The study said a portion of business support for renewable energy procurement is due to consumer demand, with 67% of consumers voicing concerns about climate change and the environment.Businesses, Deloitte wrote, “see a connection between green (resource management programs) and green (financial gain). And more than ever, they see energy procurement as a way to create value, not as a cost.”

Plans to construct new renewable energy generation account for nearly all of the planned generation additions in the Midwest over the next five years. Several areas — the Rocky Mountains, South-west, West Coast and New England regions — expect to have renewable generation account for roughly three-quarters of generation that will be built over the next five years.

The Northeast, too, is poised to increase its reliance on renewable generation. During 2019, New York and New Jersey announced plans to ramp up clean energy plans, that include a healthy dose of offshore wind generation. New York wants to have 9,000 MW of offshore wind generation by 2035; over the summer, it began negotiations with developers of two offshore wind farms totaling 1,696 MW. Under the recently enacted Climate Leadership and Community Protection Act (CLCPA), the state has committed to getting 70% of its electricity from renewable resources by 2030.In mid-2019, New Jersey signed a contract with Danish developer Orsted for 1,100 MW of wind generation located about 15 miles off the coast of Atlantic City. Other states on the East Coast have moved forward with planned offshore wind projects.

But it is important to separate grandiose plans from stubborn reality. Despite its widespread popularity in Europe, where thousands of offshore wind turbines operate, only one offshore wind farm is operating in the U.S.: the 30 MW Block Island project off the coast of Rhode Island, which Orsted spent about $290 million to build. That five-turbine wind farm began operating in late 2016.Plans to build U.S. offshore wind generation typically have been met by pro-longed and vociferous local opposition, which a few years ago doomed the planned $2.5 billion Cape Wind project off the coast of Massachusetts.

Some 24 proposed U.S. offshore wind farms with a total generating capacity of more than 12,000 MW and a total investment value of about $44.4 billion have been cancelled over the last decade. Only days before New York Governor Andrew Cuomo announced that negotiations had begun with two developer teams for 1,696 MW of offshore wind, a different developer abandoned plans to build offshore wind farms off the coast of Long Island. Will states invoke force majeure to override local opposition to offshore wind as well as land-based utility-scale solar farms? It is hard to see how many of those projects will get built otherwise over the next five years.

Only one new nuclear power plant (Blue Castle, Utah) is scheduled to begin construction over the 2020–2024 period. But that two-unit plant, which has a price tag of around $20 billion, has experienced more than a decade of delays, and there are serious doubts that it will ever be built.

Construction of two new units at the Alvin W. Vogtle Nuclear Plant in Georgia continues to chug along, with projected in-service dates of November 2021 (Unit 3) and November 2022 (Unit 4). The addition of two units at Vogtle is about 77% complete, but the costs — an estimated $25 billion to add 2,234 MW of new nuclear capacity — casts a long shadow over other new-build nuclear projects. At least Southern Company and its Vogtle co-owners can reasonably expect to receive electricity for their investments in that project.

No such luck for utilities that tried to add two new nuclear units at the Virgil C. Summer Nuclear Power Station. After spending a reported $9 billion in the project, South Carolina Electric & Gas and Santee Cooper abandoned it a few years back. The only thing it has generated is controversy, as investigations have dogged the two utilities since construction was cancelled in 2017.

Aside from the Blue Castle nuclear project, there are plans to invest about $3.3 billion in small modular reactors (SMR) by the Utah Associated Municipal Power Systems (UAMPS). These are the only new-build nuclear generation projects on the horizon.However, about $9 billion of work at nuclear plants is likely to be spent over the next five years. Most of that is earmarked for decommissioning and demolition (D&D) of shuttered nuclear plants in New Jersey, Vermont, Michigan, Pennsylvania, Massachusetts and Iowa. That book of business may grow once owners of shuttered nuclear plants in California, Nebraska and Florida finalize their D&D plans.

Roughly $1 billion in planned D&D spending for two nuclear plants in Ohio — Perry and Davis-Besse — looks like it will be pushed back. During the summer of 2019, the Ohio legislature passed, and the state’s governor signed, legislation that provided about $1 billion in subsidies over seven years to the plants, owned by a unit of FirstEnergy Corporation. The owner said the plants would be closed if the subsidies did not come through.In addition to nuclear D&D work, other in-plant capital projects in nuclear plants are scheduled to begin between 2020 and 2024. These projects include nuclear refueling, construction of dry cask storage units, steam generator replacements, water system upgrades and controls upgrades.

Battery energy storage systems (BESS) have grown rapidly in recent years, and are expected to grow even faster in the next few years. One reason is the technology’s flexibility. Some call BESS the “Swiss army knife of the energy industry.”

These systems can provide voltage support to the transmission and distribution grid, store renewable energy, relieve overloaded distribution transformers, provide uninterrupted or backup power and operate as part of a microgrid. This asset class is here to stay.

More than 700 MW of BESS have been installed in the U.S. to date, and an additional 4,000 to 7,000 MW should come online by the end of 2022. Roughly 4,000 MW are either under construction now or are expected to begin construction by the end of 2020.

The areas with the most active pursuit of BESS include the West Coast, Southwest, Southeast and the Rocky Mountains.Another factor behind BESS’ dramatic growth trajectory: Order 842 from the Federal Energy Regulatory Commission (FERC), which required battery storage technologies to be used and compensated as a stand-alone resource or in conjunction with other generation resources.

FERC has asked all regional transmission groups to complete a comprehensive review of potential deployments of BESS technologies by the end of 2020, but some groups have asked for an additional year to complete the analytic work.

The U.S. has over 650 MW of microgrids up and running, and another 200 MW are scheduled to go live by the end of 2019. Roughly $1 billion of microgrid construction projects are scheduled to begin construction this year. That $1 billion is a down payment on about $2.85 billion of microgrid projects that are in an early stage of development or plan to begin construction by 2026.

C&I customers, as well as government agencies, are drawn to microgrids for the same reasons they are considering BESS: power reliability and power quality. Manufacturing and service businesses, such as finance, are relying to an ever-greater degree on reliable power. Many define their needs as five nines (99.999% availability).

Driven by burgeoning demand from C&I customers, educational institutions and units of government, the microgrid business could balloon into a $20 billion market by 2026. In recent years, these customers have taken steps to insulate themselves from electric disruptions caused by natural disasters such as wildfires and earth-quakes as well as severe weather like Hurricane Harvey and Superstorm Sandy.

For certain types of customer, cost is less important than staying online 24/7/365. In addition to the autonomy from the grid that microgrids offer, cybersecurity makes them attractive to the military as well as units of federal, state and city governments.

There is a cost, sometimes a hefty one, to these benefits. Depending on which bells and whistles a customer wants, building a microgrid costs between $1.5 million and $3.8 million per installed MW of capacity. Depending on the complexity and scale of a microgrid, costs for controls, software and switching systems have a mean cost of about $155,000 per installed MW of capacity, with a range of $6,200 to $470,000 per installed MW of capacity.

The regions most interested in micro-grids are the same regions that have been hard-hit by severe weather in recent years: The Southwest (especially the Gulf Coast), Southeast and East Coast. Microgrids, like BESS, remain in a relatively early stage of development, subject to the same kinds of risks and uncertainties as any emerging technology.

Distributed energy resources (DER) have grown, though they are still a nascent part of the electricity business. IIR expects this sector to continue growing over the next five years. As a category, DER includes a broad range of resources: rooftop solar, community wind or solar, BESS, electric vehicles (EVs) — basically anything that is not utility-scale and that does not burn fossil fuels. Public policy, including supportive FERC and state utility commission decisions, have helped DER grow. For larger-scale DER, FERC Orders 828 and 842 provide for compensation if the resources provide generation or frequency support. Utility generation owners have had some concerns about implementing Order 842, but DER can also rely on FERC Order 828 for support in the market.

Spending on DER looks likely to accelerate sharply in the coming years. Between 2016 and 2018, roughly 450 MW of DER came online, according to data tracked by IIR. Over the 2019–2020 period, we see as much as 3,000 MW of DER beginning to operate. The regions with the greatest level of DER project activity are the Southwest, West Coast and the Great Lakes.

Industry veterans accustomed to building baseload coal and nuclear generators may scoff at the industry’s plan to invest so heavily in building renewable generation over the next five years. They may question the rush to build BESS, microgrids and DER.

We do not expect all of these planned projects to be built. But neither do we expect to see a resurgence of the traditional baseload coal and nuclear generation projects over the next five years. Those days are gone, at least for the foreseeable future, barring some dramatic “black swan” event like a reliability crisis or a dramatic run-up in the price of natural gas.

The U.S. power generation business still is in an early “discovery” mode about integrating renewable generation and BESS into the grid. And the proliferation of microgrids, though tiny by comparison to the U.S. generating fleet, remains in an early stage of exploration. All of these are disruptive trends that bear watching.

At the end of the day, most generation plans must still pass muster, to one degree or another, with each state’s utility regulatory commission. Right now, those regulators are increasingly operating under a “greener is better” mandate from their governors, legislatures and citizens.

The novelist F. Scott Fitzgerald, author of The Great Gatsby, remains a widely read author in part because he was an eternal optimist. He often wrote with a sense of wonder about the dramatic changes — technological, social, economic — he witnessed in the early years of the 20th century. At one point, this is how he explained his optimism about the future:

“I saw the improbable, the implausible, often the ‘impossible,’ come true.”

That is not a bad perspective to bring into the next five years.

Britt Burt is 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.

Brock Ramey is 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 industrialinfo.com or email power-group@industrialinfo.com

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.







