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.

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.

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.

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.

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).

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.

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.

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.

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.

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.

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

Many centrifugal compressors run in applications such as gas gathering, gas storage, or pipeline compression where a wide operating range is required. However, when specifying the desired flow range of a compressor, operators sometimes confuse the function of a compressor with that of a blower.

There are good reasons to occasionally operate a compressor at high flow and low head. But a compressor, by definition, is designed to compress gas by an elevated pressure ratio. A blower (or fan), on the other hand, essentially produces volume flow over a minimal pressure differential or head.

One of the first questions is: Why does it matter? When the compressor runs at high flow and low head, it will have a low efficiency. It is usually not economical to operate there. However, during start-up operations, such as when a pipeline or storage facility is to be filled, the machine will run at a very low pressure ratio. The capability to maximize flow is advantageous.

Overall centrifugal compressor performance is mechanically limited by its maximum allowable speed, the torque its shaft can handle, the power provided by its driver, and several other factors. But beyond that, the aerodynamic performance is defined by the head versus flow characteristic map where, at a given speed, maximum flow is limited. This limit is often referred to as choke, stonewall, or overload limit.

Many manufacturers define a distinct overload limit, and others provide performance maps where the speed lines end somewhere in mid-space. In tests and actual operation, we find compressors where the head at constant speed drops vertically at high flows, while other compressors show a more gradual reduction. The rapid vertical drop, usually called stonewall, is due to the flow choking when it reaches sonic speed.

The purist’s definition of maximum flow is the flow at no pressure rise over the compressor. That’s not practically feasible since there are always pressure losses that increase with flow. The only exception may occur when running a compressor, against atmosphere, with both suction and discharge nozzle open. However, that’s not a common application. So generally, maximum flow is a somewhat arbitrary definition at best.

Understanding the physics of the range limit of a centrifugal compressor requires understanding its behavior as it enters the high-flow region. As the compressor moves away from the design point toward higher flows, the flow into the compressor components like the impeller or diffusor, becomes aerodynamically less favorable with high incidence angles, separation, blockage, and increased viscous losses.

"It doesn’t matter whether the aerodynamic maximum flow is limited by choke or an increasingly inefficient impeller."

Classical choke means that a shock forms across the flow channel when the flow reaches the speed of sound inside a restricted passage. This defines the maximum actual volume flow through that flow channel, and in particular, this volumetric flow will not increase even if the downstream pressure is reduced.

This stonewall limit on the head-flow characteristic map shows as a rapid drop of the head as the compressor transitions into the high flow areas. However, this type of choke does not occur within many compressors, especially when lighter gases are compressed, or the pressure ratios are low. Rather than going rapidly vertical, the head gently slopes downward as flow is increased. In these cases, the flow never chokes; instead increased aerodynamic losses are responsible for the gradual head reduction.

In many cases the maximum flow is limited by other considerations, such as thrust load or the excitation of aero components, including impeller blade flutter. The axial thrust in a compressor is created by the pressure difference between the front and the backside of each impeller, which changes with the operating point of the individual impeller. Most of this thrust is balanced by a balance piston (in the case of a back-to-back machine, by other impellers). The residual thrust acts against the thrust bearing and, depending on thrust bearing capacity can overload the bearing when the compressor operates near choke.

Similarly, high-flow incidence angles on the impeller blade leading edges can generate unsteady aerodynamic forces that can excite the natural frequencies of the blades and cause structural damage at high flows. Most manufacturers define a conservative maximum flow limit that takes all these limitations into account.

Where does that leave us? It doesn’t matter whether the aerodynamic maximum flow is limited by choke or an increasingly inefficient impeller. More serious concerns are mechanical in nature, such as thrust load or aerodynamic excitation, because they may require additional flow restricting valves in the system, especially during startup and shutdown operations.

But one should always remember: A compressor is not a blower. ■

Choke: Your centrifugal compressor is not a blower

Every year, our Turbomachinery Handbook features two thorough market analyses from Industrial Info Resources (IIR) and Forecast International. Let’s look at the numbers to see what they tell us.

The IIR review of the U.S. power market makes it clear that renewables rule. Coal and nuclear are gone in terms of new build. Natural gas has been sidelined in the Northeast, Texas, Midwest, Rocky Mountain region and West.

If you take everything west of the Mississippi, natural gas will amount to roughly 8% of all power generation plant construction planned over the next five years. East of that line the picture is a little rosier. 39% for the Great Lakes region, 53% for the Southeast, and 43% for the Mid-Atlantic. However, the Northeast is down to 22% and the grand prize goes to New England at 1%.

New England appears to represent a grander experiment than California or Texas when it comes to the establishment of policy heavily favoring renewables. The Golden State and the Lone Star State can at least look forward to plenty of sunshine as well as excellent natural corridors with strong winds. New England does not boast such riches. Further, it has been steadily shuttering nuclear and coal plants. Within a few years, it could become overly reliant on wind and solar. Will the lights stay on in Boston, Bridgeport, and Burlington? And Harrisburg, Hackensack, and Harlem? Let’s hope so.

It will be interesting to see if GE can strengthen its position in the coming years or if Siemens and Mitsubishi gain ground.

I happened upon a Turbomachinery Handbook from 10 years ago. Back in 2010, Forecast International correctly predicted a steep drop off in new gas turbine capacity additions between 2013 and 2019. But few expected the decline in the number of gas turbines being sold. In 2010, 11,480 machines were forecast to be built over the next ten years. In this new report, the total is down to 4,291 over 10 years.

Solar Turbines led unit sales back in 2010. It traditionally accounted for more than 30% of units sold. This year, it is down to third place with 20% of the market, beaten by GE (30%) and Siemens Energy (22%).

The decline is not so steep on value of gas turbines to be sold per decade – down from a prediction of $138 billion over 10 years in 2010 to $102 billion in the new study. This indicates a shift to bigger-ticket, large-capacity turbines and away from smaller machines.

On the vendor side, GE dominated all others with 43% of predicted gas turbine sales value in 2010. It sits about the same level today. But its competitors are closing the gap. Siemens Energy moved from 14% share to 26%; Mitsubishi Power from 11% to 15%. With GE emerging from a few years of reorganization, it will be interesting to see if it can strengthen its position in the coming years or if Siemens and Mitsubishi gain ground.

Be sure and read our two market reports to gain insight into the U.S power market and worldwide gas turbine trends. As well as our regular columns, Q&A, news, and products, the Turbomachinery Handbook also contains detailed company listings and equipment specifications.

The listings are compiled each year by the meticulous Bob Maraczi. They consist of alphabetized and categorized lists of companies in the many disciplines that make up the turbomachinery sector. Bob is thanked for his great work.

The specifications were compiled for the first time by associate editor Rory Pasquariello. He has done a fine job gathering specs from a great many companies in equipment areas such as electric power generation, combined cycle, gas turbines, compressors, expanders, and steam turbines.

The 2021 Turbomachinery Handbook, then, is one to keep handy all year round. Its value extends far beyond that of a regular issue. ■

How the last ten years compare to the next ten

Forecast International predicts that the power generation market for gas turbines will continue to contract as it has done for the past five years. Sales in the ten-year period 2019 to 2028 will total $96.045 billion, 10.6% less than last year’s sales projection for the 2018-to-2027 period.

The market decline is likely to continue through 2021. However, an upturn should then take place and continue each year until the end of the projection period in 2028. This contraction is a direct result of the spreading crisis caused by overcapacity in the power generation equipment sector and the resulting softness of prices. Companies are selling fewer power generation gas turbines than they had predicted and are receiving a lower unit price for each sale. As a direct outcome, GE, Siemens and Mitsubishi Hitachi Power Systems (MHPS) have undertaken major restructuring to reduce costs and rationalize production. These measures, though, are proving of only limited effect and a more fundamental reorganization appears necessary.

At present, GE controls 47.4% of the projected market by value, Siemens 21.9% and MHPS 19.3%.* These three OEMs control 88.6% of the total market. The remaining 11.4% is comprised of a dozen or more companies led by Ansaldo Energia at 6.3%, followed by Mitsubishi Heavy Industries (MHI) at 3.3% and Solar Turbines at 3.3%. The remaining group of manufacturers collectively accounts for less than 1%.

For the near term, there appears to be little relief from the current market depression. The situation of reduced demand, manufacturing overcapacity, and soft prices will continue until at least the early 2020s. Only after these factors have worked themselves out is recovery expected to take place. Once the middle and far-term periods are reached, it is predicted that the industry will be dominated by large combined-cycle facilities in the industrialized nations.

General Electric and Siemens both produce turbines in this output range, but others exclusively make small machines. With turbines of this size, Solar remains the market leader with about 2.9% of the value of the gas turbine market. Solar’s Mercury model is particularly popular with customers. MAN and Kawasaki occupy a smaller portion with a combined 0.5% in terms of value.

In terms of unit production, Solar occupies roughly 20.5% of the total market. Slightly less publicized are the Ukrainian and Russian turbines. The Ukrainian company, Zorya-Mashproekt, once provided a large portion of the industrial and marine gas turbines destined for Russia.

Russia is now producing turbines through United Engine Corporation (UEC) comprised of NPO-Saturn and Aviadvigatel, which both produce turbines with the latter producing mainly aviation engines. Although technical details about these machines are difficult to ascertain, installations are generally available. For 2018, UEC Saturn installed 194 units with 1,535.7 MW of output. UEC Saturn has less than 1% of the market in terms of value and holds nearly 3% of total unit production.

Capstone remains the market leader in microturbines. FlexEnergy is next, occupying about half of Capstone’s footprint. Both companies combine to account for nearly 95% of the market in terms of value as it currently stands. Ansaldo Energia offers a 100 kW machine, but little is known about sales performance.

New European microturbines are also coming to market. MTT’s EnerTwin, Bladon’s 12 kW machine and Aurelia’s 400 kW turbine have yet to sell in significant numbers so forecasting is speculative. The 2019–2028 timeframe should see a doubling of these new machines’ market share in terms of value.

At the other end of the scale, power output of large gas turbines continues to increase. While 200 MW was considered large a few years ago, outputs at five times that figure are not uncommon. Gas turbines an order of magnitude more powerful are entering the market. A growing number of these large turbines are deployed with heat recovery units in combined cycle power plants claiming efficiencies of more than 60%.

It should also be noted that a 400 MW gas turbine costs significantly less than two 200 MW turbines. The difference increases steadily as the output of the larger turbines goes up. When building big, centralized power generation facilities, it is more economical to use the largest models. This makes the market situation more complex. A major power station requires a state-of-the-art electrical grid to distribute the generated power. This is not available in some parts of the world. In such cases, the cost of establishing such a grid must be included within the economic analysis of the project. The added capital cost of establishing distributed generating capacity using numerous smaller turbines may be less burdensome than the costs of providing a distribution network.

The same may apply to fuel sourcing. If coal is abundant and the infrastructure to transport it to the point of use already exists, these factors may override the advantages of gas. This may be a factor in the continued procurement of coal-powered steam turbines in some regions.

In the long term, escalating demand for electric power will continue to increase the worldwide demand for gas turbine-based power plants that use the latest technology. Thus, it is likely that the market will recover, and investment is likely to focus on industrial gas turbines with the highest outputs. This can be expected in areas, such as China, North Korea, Vietnam, Indonesia, Thailand, Brazil, and the Middle East.

Analysis of the sector has become more complicated as the primary drivers have shifted from technical and economic to political and environmental. Stated goals include reduction of emissions and cutting down on the use of fossil-fuel resources. Subsidies promoting the use of renew-able resources and low-emissions fuels distort the market, complicating the relationship between energy demand and generation capacity. In recent years, too, a significant proportion of increased electricity demand has been met not by adding generating capacity, but by improving grid efficiency.

The development of modern control systems also has reduced the amount of spinning reserve as a proportion of baseload capacity. A case could be made that the shift from a simple bilateral relationship between supply and demand to the current, highly complex multilateral relation-ship is at the root of today’s problems.With so many factors influencing the marketplace, it is important to recognize that gas turbine procurement is no longer directly related to increasing power demands.

The option of obtaining additional gas turbines is one of many that exist. The same effect may be obtained by converting an existing simple-cycle plant to combined cycle through the installation of a heat recovery steam generator (HRSG) and a steam turbine. An indirect approach may be to invest in grants to improve energy efficiency rather than in new power generation facilities.

*Figures include subsidiaries and licensees.

By Stuart Slade and Carter Palmer, Forecast International

Stuart Slade is the Senior Industrial & Marine Gas Turbines Analyst at Fore-cast International. This article provides data compiled from Forecast International’s Platinum 4.0 information and analysis service.

Carter Palmer is an Industrial & Marine Gas Turbine Analyst at Fore-cast International with a focus on smaller gas turbines and microturbines.

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