America’s Hidden Energy Crisis

If Competitive Electricity is Such A Good Business, Why Are Companies Closing Power Plants, Taking Write-Downs, Seeking Bankruptcy Protection and Scrambling for the Exits?

Acasual observer scanning the headlines might conclude that America’s biggest energy challenge involves the Trump Administration’s position on climate change, whatever that turns out to be. But the country faces an equally difficult and — because it is mostly hidden to all but industry insiders — more insidious challenge.

The competitive business model worked reasonably well until a few years ago, when the entire electric power industry sailed into a hundred-year storm, a period of unprecedented stress that continues unabated to this day.

Left untreated, this festering problem will lead to loss of valuable energy infrastructure that has decades of useful life left, more costly electricity, more volatility in electricity prices, higher emissions of carbon and other pollutants, and possibly even less reliable electricity supply.

The problem is the business of generating electricity in those parts of the country that deregulated the power industry in the late 1990s and early 2000s. Since then, electricity has evolved into two very different businesses.

States in the south and southeast resisted the temptation to deregulate. In those states, companies own power plants, transmission lines and the local distribution networks. They operate under a regulatory bargain struck many decades ago. In return for an exclusive franchise, the companies accept an “obligation to serve” any and all who need electricity. They are guaranteed a reasonable opportunity to recover all their costs, plus a reasonable return on their investment.

States in the northeast, mid-Atlantic, midwest and Texas — representing roughly two-thirds of the electricity consumed in the United States — forced their companies to restructure. They separated transmission and distribution (the “wires” business) from the business of generating the electricity. The wires continued as regulated enterprises, but generating electricity became an unregulated, competitive undertaking, with the grid managed by independent regional organizations.

There’s no compelling evidence that the competitive business model is any better. Retail electricity rates in the south and southeast (regulated states) average 9 -10 cents per kilowatt-hour. Some states with competitive markets (Ohio, Texas, Pennsylvania, for example) are also in that range. But electric rates in many other competitive states — notably on the East and West Coasts — are at least 50% higher. Connecticut holds the dubious distinction of having the highest rates in the lower-48, at 17.7 cents per kilowatt-hour.

A Hundred-Year Storm

The competitive business model worked reasonably well until a few years ago, when the entire electric power industry sailed into a hundred-year storm, a period of unprecedented stress that continues unabated to this day.

The stress is caused partly by disruptive advances in technology. For example, horizontal drilling and hydraulic fracturing unlocked vast reserves of natural gas in so-called “tight” formations. This produced a gusher of natural gas at extremely low — and probably unsustainably low — prices. Since natural gas is a dominant fuel for producing electricity, wholesale electricity prices have collapsed along with natural gas prices.

But the stress also comes from other sources. Demand for electricity is growing slowly, if at all, thanks to relatively anemic, halting economic growth since the 2008 recession, and greater efficiency in electricity use. Nationwide, electricity consumption in 2016 was below 2010.

Even companies in regions with relatively robust economies are feeling the pinch. Atlanta-based Southern Co. (which operates in Georgia, Alabama and parts of Mississippi and Florida) expects annual electricity demand to grow only between 0% and 1% for the next four or five years. And companies in more economically-challenged regions, like Columbus, Ohio-based American Electric Power, saw quarterly growth in electricity demand in 2016 range from a low of -0.5% in the third quarter to a high of 0.3% in the fourth.

Inevitably, slow demand growth — or no demand growth — tends to depress prices even further.

It’s not just nuclear plants that are closing. Coal-fired power plants are closing down, too, and not just due to tighter environmental controls. So are gas-fired power plants, including relatively new, high-efficiency facilities. In fact, without subsidies and mandates, wind and solar facilities would probably be tanking, too.

Add to all this the impact of state and federal mandates and subsidies for renewable sources of electricity. The last 7-10 years have seen remarkable improvements in the cost and performance of wind and solar technologies. Still, 29 states and the District of Columbia continue to force renewable energy into the market, by requiring their utilities to buy a certain percentage of their electricity from renewable sources. On top of this, the federal government provides a production tax credit to wind generation and an investment tax credit to solar. Leaving aside personal opinion about the wisdom and merits of mandates and subsidies, it is inarguable that these programs distort markets and, in the case of federal subsidies, suppress wholesale electricity prices even further.

Then add serious problems with design and operation of the competitive markets. These markets typically don’t recognize or value the positive attributes of the resources in place. They’re not always operated so that all costs are reflected in prices. And they operate solely on the basis of lowest short-run marginal cost, when it’s clear that a robust and resilient market must also factor in other factors — long-run price stability, for example, or the value of fuel and technology diversity, or environmental factors, and others.

In sum, it’s hard to imagine a more “perfect storm” of negative factors all arriving at about the same time, all pushing wholesale electricity prices down, down, down.

When Low Prices Aren’t Always Such a Good Thing

To the average consumer, low electricity prices sound like a good thing. And so they are, unless they’re so low that the companies operating the power plants cannot generate sufficient revenue to stay in business. The competitive electricity markets in the United States have reached that point. Today’s situation is simply unsustainable.

To be sustainable, a competitive market — for crude oil, gasoline, tires, orange juice, electricity or any other commodity — must satisfy the needs of consumers, suppliers, asset owners and investors, regulators, policy-makers and other stakeholders.

“We continuously expect our electric industry to solve a complex ‘simultaneous equation’ in which the countless decisions of myriad actors need to produce a reliable, efficient and increasingly clean supply of electricity,” Susan Tierney, one of the most respected observers of electricity issues and a principal with a consultancy called The Analysis Group, told federal energy regulators several years ago.

In Tierney’s view, the markets today are not solving that “simultaneous equation” correctly: “Something has to change for the numbers to support a sustainable, healthy and vibrant electric industry capable of meeting system operators’ technical necessities, consumers’ implicit needs, policy-makers’ explicit demands, and investors’ inherent requirements. That entire equation must be satisfied,” she says, “or the system isn’t sustainable.”

The distress is most visible — or perhaps most talked about — in America’s nuclear energy industry, which produces about 20 percent of U.S. electricity supply, and about two-thirds of the country’s carbon-free electricity. Since 2013, six nuclear reactors have shut down permanently. That leaves 99 operating reactors. Three more reactors are planned to be shut down before 2020, two more in 2020-2021, and two more in the mid-2020s. And there are others at risk.

The common wisdom holds that the nuclear plants can’t compete in a world of low-cost natural gas, and isn’t that just too bad but markets are cruel places where only the strong (or the lowest-cost) survive. As is often the case, the common wisdom is wrong.

It’s not just nuclear plants that are closing. Coal-fired power plants are closing down, too, and not just due to tighter environmental controls. So are gas-fired power plants, including relatively new, high-efficiency facilities. In fact, without subsidies and mandates, wind and solar facilities would probably be tanking, too.

The entire competitive generation segment of the electric power industry is struggling.

Across the board, companies are dumping the power plants that, as recently as 10 years ago, were their crown jewels.

In its annual assessment of the competitive electricity business late last year, Moody’s Investors Service, the credit rating agency, maintained its negative outlook on the entire sector: “Against persistent headwinds, [the] fundamentals remain negative,” Moody’s said. In a separate analysis, the rating agency noted the economic stress facing some nuclear plants, but found that over 66,000 megawatts (MW) of coal-fired generating capacity in 16 states is also at risk (out of roughly 100,000 coal-fired megawatts operating in those states). And despite the Trump Administration’s rhetoric, this coal-fired capacity is not at risk because of environmental requirements or the Obama Administration’s Clean Power Plan. Moody’s criterion was simple economics: “at-risk” is when fuel, variable operating and maintenance (O&M) costs and fixed O&M exceed $30 per megawatt-hour.

Running for the Exits

So the electric power companies operating in competitive (or “merchant”) markets are in full flight from the business of generating electricity, and they have been for several years. Between 2003 and 2015, electric industry revenues moved from 64-percent regulated to 78-percent regulated.

Across the board, companies are dumping the power plants that, as recently as 10 years ago, were their crown jewels.

Instead, they’re putting their capital into upgrading and strengthening the “wires” business (transmission and distribution), because it’s regulated and safe. They’re assured of capital recovery and steady, predictable earnings.

Power plants are out. The “wires” business (transmission and distribution) is in. Transmission and distribution are regulated, and provide stable cash flows and predictable earnings.

Chicago-based Exelon is a poster child for this strategy. Exelon is one of the largest merchant generating companies in the United States, with roughly 33,000 MW of capacity, much of it nuclear. But it’s not a happy business. Only heroic state government intervention in 2016 in New York and Illinois saved seven Exelon reactors that were slated for premature shutdown over the next several years. The states provided “zero-emission credits” — basically a way to compensate the nuclear plants for producing carbon-free electricity, in much the same way that “renewable energy credits” value the contribution from wind and solar. It will take similar state government action to save other nuclear plants at risk in Ohio, Connecticut, Pennsylvania and Texas.

Last year’s reprieve didn’t really solve Exelon’s bigger problem, however. In a recent assessment, UBS equity analyst Julien Dumoulin-Smith sees the earnings-per-share contribution from Exelon’s generation subsidiary collapsing — from $1.40 per share in 2014 to an estimated 25-cents per share in 2020. Why would any company want to stake its future on a business with such unappetizing earnings potential?

Exelon’s leadership has reinvented and repositioned the company over the last several years to deal with this. From a base that included two big distribution companies — Commonwealth Edison in Chicago and PECO in Philadelphia — the company acquired Baltimore Gas and Electric in 2011 and Potomac Electric in 2016. By so doing, the company ensured that it would always be able to cover its dividend to shareholders, and provide earnings growth, through the regulated side of the business — making it relatively indifferent to continuing economic pressure on its generating business.

Exelon is investing its growth capital — $20-billion-or-so over the next four years — in its regulated businesses, where it can earn predictable returns. And it’s harvesting free cash flow from its generating subsidiary to pay down debt and invest in its regulated utilities. Of $6.8 billion in free cash flow expected from Exelon Generation over the next four years, more than 75% will go to debt reduction and its regulated business.

Misery loves company, and Exelon has lots of it.

American Electric Power (AEP) has sold, or is in the process of selling, most of its generating assets in competitive markets. At the end of January, AEP closed on the sale of four large power plants — three gas-fired and one coal-fired, totaling 5,200 megawatts (MW) of capacity — to a private equity group. During the third quarter of 2016, the company took a $2.3-billion impairment charge to write down the value of its remaining merchant generating assets (about 2,700 MW, mostly in Ohio). In all its presentations to investors, AEP emphasizes its large capital investment in transmission and distribution, and brands itself prominently as “The Premier Regulated Energy Company.”

New Orleans-based Entergy is winding down its merchant generation business. It closed (or will close) two nuclear plants and a gas-fired combined cycle plant in New England and a nuclear plant in Michigan. It sold another nuclear plant in upstate New York to Exelon. Entergy is so anxious to exit merchant generation that it finally agreed in January to do what New York Governor Andrew Cuomo has been trying to accomplish for years — close down the two Indian Point reactors on the Hudson River, about 35 miles north of New York city.

Akron-based FirstEnergy intends to exit the competitive electricity generating business no later than mid-2018, and will either sell or shut down its power plants operating in competitive markets — including several coal-fired plants and three nuclear power stations. (The company is urging Ohio legislators to follow the lead of New York and Illinois, and provide zero-emission credits to save the Davis-Besse and Perry nuclear plants.) In January, the company found a buyer for several power plants — including gas-fired plants in Pennsylvania and its share of a hydroelectric plant in Virginia. One of the gas-fired facilities is a relatively modern (commissioned in 2003) high-efficiency combined-cycle plant. During the fourth quarter of 2016, the company wrote down the value of its competitive generating assets by $9.2-billion ($5.8 billion after tax). FirstEnergy continues to warn investors that its competitive generating subsidiary may be forced to seek bankruptcy protection. And like AEP, FirstEnergy takes great pains to remind investors in its presentations that it is putting capital to work in its regulated businesses and “Transforming into a Regulated Energy Company.”

When There Is No Exit

These companies, at least, have large regulated transmission and distribution subsidiaries to fall back on.

The “pure play” independent power producers — names like NRG, Calpine and Dynegy — are not so fortunate.

NRG closed on February 17 at a little over $17 a share — better than the $10.54-a-share in January 2016, but down more than 50% from its 10-year high.

Dynegy reached $36 a share in mid-2014. It’s now hovering just above $9 a share, and UBS moved the company several weeks ago to “sell”.

Calpine hit $22.87 in June 2008, slipped to $4.95 in March 2009, recovered to $23.76 by June 2014, and is back down to $11.47 a share.

Not surprisingly, these independent power producers (IPPs) are also closing power plants.

Dynegy announced last May that it planned to close 2,800 MW of coal-fired generating capacity in southern Illinois. In December, it requested court approval of a prepackaged bankruptcy plan for its Illinois Power Generating subsidiary to restructure $825 million in unsecured debt.

To call these electricity markets “competitive markets” or “free markets” is to flirt with fantasy. They are seriously compromised by a patchwork of state programs that remove large portions of the market from the competitive supply-demand bidding process.

In California, Calpine has shut down its Sutter Energy Center, a 525-MW gas-fired combined cycle plant that started up in 2001. Dynegy has closed 1,500 MW of gas-fired capacity at its Moss Landing plant on the California coast. And last December, the private-equity owner of the La Paloma plant, a 965-MW gas-fired combined cycle facility that was commissioned in 2003, filed for bankruptcy protection, crippled by a $524-million debt load.

In California’s case, the culprit is high penetration of renewables, more than low gas prices. The Golden State is a major success story for renewable energy. During 2016, electricity produced from renewable sources in California was almost 20% higher than the year before, and nearly 50% above the previous five-year average. But there’s a dark side to this story. Increasing production of renewable electricity — which floods the market for just a few hours at the same time every day — pushes so-called “thermal” power plants (i.e., gas-fired, coal-fired and nuclear) out of the market during those hours. The thermal plants run less and less, generating less and less revenue, spiraling down toward insolvency.

This wouldn’t matter, except renewables produce only 30–50% of the time — solar typically around the midday hours, wind at night. So the thermal plants are still needed, when the sun isn’t shining and the wind isn’t blowing, to meet demand for electricity and to maintain reliability.

Seriously Compromised Markets

This is a difficult situation — difficult to explain, difficult to fix.

Although much of the attention has focused on nuclear plants shutting down prematurely, the loss of valuable and productive power plants clearly extends well beyond nuclear.

The competitive markets are either poorly designed or crudely designed. They do not fairly compensate resources in place for the value they bring to the grid. Some zero-carbon resources are compensated for providing clean electricity, for example; some are not.

And the markets are distorted by state and federal mandates and subsidies, to the advantage of some sources of electricity and to the disadvantage of others.

The core problem is that many nuclear, coal-fired and gas-fired power plants cannot cover their costs with revenues from the market. Wind and solar facilities do not cover their costs out of the market either, but they have the advantage of other sources of so-called “out of market” revenue, which insulates them from the carnage around them.

In the northeast, wind and solar facilities generate most of their revenue from federal tax credits and state mandates. This insulates them from the market stress experienced by other electricity generators.

In New England, for example, over 70 percent of the revenues for both wind and solar units in 2015-16 were from federal and state programs, such as federal investment or production tax credits or the renewable energy credits (RECs) created by state portfolio mandates. Similarly in New York: a new solar project would have earned 58-69 percent of its 2015 revenues from renewable energy credits and tax credits. Onshore wind units in New York would have received 51-66 percent of their 2015 net revenues from state and federal programs.

In fact, to call these electricity markets “competitive markets” or “free markets” is to flirt with fantasy. They are seriously compromised by a patchwork of state programs that remove large portions of the market from the competitive supply-demand bidding process.

In Connecticut, for example, the state purchases renewable energy for the grid outside the market under several programs authorized by legislation enacted in 2013 and 2015. New York announced last month a $360-million grant to 11 renewable energy projects, just the latest in a series of interventions. Massachusetts enacted legislation last summer requiring the state to execute 15–20 year contracts for 1,600 megawatts of offshore wind and another 1,200 megawatts of hydropower, which will likely come from Canada.

To no avail, the power plant owners in New England complained that the Massachusetts legislation places about 60% of the state’s market off-limits — “the single biggest step away from a competitive electricity market ever taken in New England,” said Dan Dolan, president of the New England Power Generators Association.

If current trends continue, Exelon estimates approximately 60% of the New England market in 2030 will be reserved for state-supported or state-mandated programs; only about 40% will operate as a competitive market.

Leaving aside these structural issues, there is also an element of anti-consumer economic lunacy on display here. At the same time New England is closing down reliable, zero-emission, relatively low-cost nuclear power plants, states are mandating construction of power plants that will produce much more costly electricity.

Economic lunacy: New England is closing down nuclear power plants, which produce electricity for $45-$50 per megawatt-hour (MWh). Instead, the region is building new gas-fired combined cycle plants for up to $78 per MWh, or new offshore wind facilities (for $118-$214 per MWh), or importing Canadian hydro (at $97 per MWh).

The Vermont Yankee nuclear plant (which shut down at the end of 2014) and the Pilgrim nuclear plant in Massachusetts (which will close in mid-2019) both operate (or operated) for $45–50 per megawatt-hour (MWh). (In the nuclear world, these are relatively small plants and thus the highest-cost. The average U.S. nuclear plant in 2015 produced electricity at an all-in cost of $35.50 per MWh, and the large multi-unit sites for less than that.).

In place of Vermont Yankee and Pilgrim, Massachusetts will substitute Canadian hydroelectricity that, by one independent estimate, will cost roughly twice as much ($97 per MWh). Or offshore wind at somewhere between $118 per MWh (according to Lazard) and $137.10-$213.90 per MWh (according to the U.S. Energy Information Administration).

Even if those $50-per-MWh nuclear plants were replaced with the most modern, most efficient gas-fired power plants, the gas-fired electricity would cost $48 -$78 per MWh (Lazard) or $53.40-$67.40 (EIA).

None of this makes economic sense.

Draining the Swamp

To their credit, the regional transmission organizations (RTOs), which operate the grid and manage the markets, and the states and the Federal Energy Regulatory Commission (FERC), which oversees the RTOs, all recognize there’s a problem.

For a federal government agency, the classic first response to an incipient crisis is to commission reports from its staff and convene workshops and conferences on the issue. The FERC did that in 2013 and, three-plus years later, there’s not much to show for it. The agency has taken a few small, necessary and appropriate steps — to ensure that market prices actually reflect real-time supply-demand conditions, for example — but nothing that could be characterized as particularly bold or innovative.

PJM has changed its market practices to provide additional compensation to some power plants — like nuclear power plants or gas-fired power plants with firm gas delivery contracts — capable of sustained, predictable operation. These resources are expected to be available and capable of providing energy when needed, and face substantial penalties if they are not. That was an important, necessary and appropriate step that should be replicated nationwide.

Several of the regional transmission organizations — including ISO-New England and PJM — recognize the distortions occurring in the energy markets due to federal and state subsidies and mandates. Both are considering various options to address this market defect, but they’re compelled to use a cumbersome stakeholder consultation process that is virtually guaranteed to arrive at stalemate.

Time to Reboot: Back to First Principles

The preponderance of the evidence suggests that the merchant power generation business is flat on its back. That’s certainly not healthy and probably not sustainable.

Does all this mean that competitive electricity markets are fatally compromised? Not necessarily. But it’s unlikely that band-aids applied here and there will fix systemic maladies.

Step one is to admit there’s a problem and, sadly, there’s still a lot of denial out there. In a whopping unintended irony, PJM published a white paper last year that declared: “No evidence suggests the PJM markets inadequately compensate legacy units and thus are forcing a premature retirement of economically viable generators.” Exactly one day later, Exelon announced that it would be forced to close its Clinton and Quad Cities nuclear stations — two reliable, low-cost generating stations in western PJM — because the markets did not recognize their value.

Step two is to return to basics and first principles, rediscover the attributes necessary for a robust, reliable, sustainable market, then design a market structure that provides and preserves those attributes.

Absent major reform, this story ends with the United States shackled to an electric supply system that’s subject to chronic, punishing volatility in prices. New England is already there.

Lowest possible short-run cost is an important attribute, to be sure, but it is not the only important metric. (In fact, in an industry that builds and operates infrastructure with 40-to-60-year lifespans, lowest-possible short-run cost may not even be the most important characteristic of a successful market.)

What are the other necessary attributes of a sustainable power supply system?

Long-term price stability is important. So are environmental factors. So is the ability to operate when needed, regardless of weather, whether or not the wind is blowing or the sun shining, whether or not natural gas arrives just in time via pipeline.

Portfolio value is particularly critical. A diverse portfolio of fuels and technologies is a prudent necessity in power supply — just as a diverse portfolio of debt and equity, short-term instruments and longer-dated ones, is a prudent necessity in a financial portfolio. Fuel and technology diversity is a hedge against supply disruptions or price volatility in any part of the portfolio.

So there we have five attributes of a successful market. As currently designed, America’s competitive electricity markets have one attribute out of the five.

Defenders of the status quo insist that the competitive markets are just doing what they’re designed to do — deliver power at the lowest possible short-run cost. They insist that these markets were not designed to provide long-term price stability, or a diverse portfolio of fuels and technologies.

Yes … that’s precisely the point. Comments like that are an excuse, not a solution.

Will the Lights Go Out?

Will the lights go out if the status quo prevails? Of course not.

In what appears to be a triumph of hope over experience, there’s apparently an endless supply of companies willing to build even more gas-fired power plants. And, as in any industry, there are always bottom-feeders willing to snatch up distressed assets for pennies on the dollar.

Absent major reform, however, this story ends with the United States shackled to an electric supply system that’s subject to chronic, punishing volatility in prices. New England is already there.

In its 2016 Regional Electricity Outlook, published in January 2016, the New England grid operator notes:

“[W]intertime access to natural gas has grown tight over recent years because the regional fuel transportation network has not kept up with demand from both generation and heating sectors. These natural gas constraints have led to grid reliability challenges, emission increases during winter, and spikes in wholesale electricity prices. The situation is exacerbated by other market dynamics: low gas prices during most of the year except winter are putting economic pressure on coal, oil, and nuclear resources. By 2020, resources representing about 30% of regional capacity have committed to cease operation or are at risk of retirement. Taking their place are even more natural-gas-fired units — currently, more than 60% of new generation being proposed by private investors across the six states will be primarily or exclusively fueled by natural gas ….

The region’s growing dependence on natural gas for power generation exposes consumers of electricity to increasing price volatility:

“Because so much of the region’s generating capacity runs on natural gas, the price of this single fuel source sets the price for wholesale electricity about 70% of the time. Both electricity and gas prices have seen dramatic swings in recent years. Between February and June 2015, for example, the region’s average monthly wholesale electricity price plummeted from the third-highest price to the lowest price since 2003, the year that competitive markets in their current form were introduced in New England.” (Emphasis added.)

One final thought: it’s true that electricity represents only 2–3% of America’s GDP. Not such a big deal perhaps.

But that 2–3% drives the other 97–98%.

So this is serious stuff. Best we get it right.

Richard Myers is a free-lance journalist based in Washington, D.C.. He worked almost 30 years at the Nuclear Energy Institute, the U.S. nuclear industry’s D.C.-based policy organization, the last 10 years as vice president for policy and planning. Before that, he spent almost 15 years as a reporter and editor with The Energy Daily, now published by IHS Markit.

Go to the profile of Richard Myers

Richard Myers

Free-lance journalist. Former head of policy and planning for a major energy trade association. Before that, a reporter and editor at “The Energy Daily.”

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