This is the first of a five-part series exploring oversupply in the power sector and the factors driving a glut of natural gas-fired power plants.

When the Inland Empire Energy Center was announced in 2005, it was touted as a breakthrough power plant that would fill a critical shortfall in California's electricity supply for decades to come. Located in Riverside, Calif., and based on a vaunted new gas turbine technology from General Electric Co., the 730-MW, $500 million power plant came online in 2009.

Only eight years later, however, in March 2017, GE shut down one of the plant's two operating units. And in June 2019, the company said it would close the plant for good, only 10 years after starting it up.

Inland Empire was powered by a legacy technology that is "uneconomical to support further," a GE spokesperson said.

The ill-fated project represented a pair of badly misjudged bets by GE — that California would need new baseload electricity supplies and that the relatively inflexible H-class turbine, which takes hours to ramp up to full production, would be an industry standard for years to come.

Inland Empire also epitomizes a trend seen across much of the U.S. power grid. Utilities, faced with a steady stream of coal plant retirements and the allure of historically low natural gas prices, have continued to build new gas plants despite flat electricity demand and rapidly falling prices for energy from renewable sources.

That building spree has led to a glut of generation capacity in many regions. And it continues today, because natural gas is cheap and because business models and regulatory structures reward many U.S. utilities for building new infrastructure, whether it is economically viable or not. And ratepayers and investors will likely have to foot the bill. Between 2008 and Aug. 1, 2019, a period of essentially flat demand, the U.S. added 120,498 MW of natural gas-fired capacity to its generation fleet, including nearly 26,000 MW in 2018 and 2019 alone. At least 200 new gas plants are planned or in development across the U.S., totaling nearly 70,200 MW of additional capacity — nearly equal to total generation capacity in Texas.

The rush

Over the same period, utility capital expenditures have risen steadily, from just over $60 billion in 2008 to more than $110 billion, an all-time record, in 2018. Spending is expected to surpass $120 billion in 2019.

Touted as a low-cost "bridge fuel" to a clean-energy future, natural gas burns cleaner than coal and is better able to adjust to shifts in demand throughout the day. Many utility executives and policymakers see it as a necessary complement to intermittent solar and wind generation. As many states from Maine to California seek to eliminate fossil fuels completely from their power sectors by midcentury, the industry continues to invest billions in plants that have projected lifespans well beyond that point.

But many experts believe that these plants are likely to become stranded assets well before their planned lifetimes are over. And if the boom continues, it will eliminate any possibility that the U.S. will meet the targets set out by the Paris Agreement on climate change.

"Existing gas-fired power plants and pipelines often operate for 40 years or longer," the Sierra Club wrote in a January 2017 report titled "The Gas Rush," "meaning that should the proposed gas infrastructure be constructed, America won't be building a bridge, but rather a superhighway to climate disaster."

By 2023, all but three regions in North America will have more power generating capacity — in some cases far more — than needed to maintain reliability, according to a recent assessment from the North American Electric Reliability Corp., the power industry's official reliability coordinator. Reserve margins — the cushion of available electricity generation over expected peak demand — routinely exceed their targets, in many areas by thousands of megawatts each year, NERC found.

The resulting glut has started to push down capacity factors, a measure of a plant's usage compared to its potential output. Nearly one in seven U.S. combined-cycle natural gas power plants younger than 20 years old are little-used, according to an S&P Global Market Intelligence analysis. Totaling more than 33,000 MW of generating capacity, these plants have capacity factors of below 40%, meaning that a large number of quite new facilities that cost hundreds of millions of dollars each to build are being used a little over one-third of the time.

At the same time, natural gas's price edge over renewable energy technologies is eroding fast. By 2035, it will be more expensive to continue operating approximately 90% of the country's planned new gas generation capacity than to build equivalent clean energy portfolios, according to a pair of reports from the Rocky Mountain Institute, or RMI, an advocate for low-carbon energy resources. With about $90 billion worth of new gas plants and $30 billion of pipelines proposed or planned for construction, the risk of stranded assets is "significant," the group said.

RMI's findings are in line with an analysis by BloombergNEF, which said that by the late 2020s, it will be cheaper to build wind and solar plants than to continue operating standard combined-cycle gas turbines.

'The new coal'

The message comes not just from wind and solar advocates but also from Wall Street analysts, lawmakers, state regulators and academics. They argue that U.S. utilities are locking themselves into a generation of gas plants that are likely to become uneconomic and shut down long before their planned retirements. Or they will continue to produce power at greatly reduced capacity factors, supported by ratepayer charges.

"Utilities are caught between a rock and a hard place," said Nick Goodman, the CEO of CYRQ Energy, an owner/operator of geothermal power generation facilities in the western U.S. "They have an obligation to serve, and the intermittency issues with wind and solar are real."

On the other hand, as of November, seven states, including California and New York, plus the District of Columbia had implemented laws that call for 100% of the electricity sold in the state to come from renewable or zero-carbon resources by 2050 or before. Achieving those goals will saddle utilities with billions of dollars of stranded investment in gas plants built in the last 10 years.

"Gas is the new coal, and that's not a good thing," said Mark Dyson, a principal in RMI's electricity practice.

Today, the gas power boom is being driven largely by historically low fuel prices brought about by the shale gas revolution. That revolution, more than any government policy, has helped drive down U.S. greenhouse gas emissions over the last decade, mostly by replacing coal-fired generation with gas. The transition from coal to gas has been astonishingly rapid by the standards of historical energy transitions, and it has produced benefits both environmental and economic. But U.S. emissions crept upward again in 2018, and according to projections from the U.S. Energy Information Administration, gas will continue to be the dominant source of electricity in the U.S. for the foreseeable future, accounting for nearly 40% of U.S. power by midcentury. Renewables' share will increase but will still be less than one-third in 2050.

Coupled with an estimated 17% share from coal plants by 2050, that means a majority of U.S. power will still come from fossil fuels, and greenhouse gas emissions from the U.S. power sector will hardly budge, topping 5 billion metric tons of carbon dioxide per year by 2050 and putting the targets set by state laws and the Paris Agreement on climate change far out of reach.

Origins of overbuild

Cheap natural gas, though, is not the only factor driving this construction spree.

Many U.S. utilities' business models reward them for building new infrastructure, whether it is economically viable, or truly essential, or not. Overburdened regulators often lack the resources and the expertise to thoroughly examine utility generation planning, and they sometimes lack the institutional clout to turn back utilities' ambitious building plans. State legislators, accustomed to generous financial support from big utility companies, tend to be pliant in the face of those companies' demands. In unregulated markets, investors are shielded from long-term downside risk by capital structures that ensure payback even if the power those plants produce becomes uneconomic to sell. Forecasts of energy demand are based on outdated models that foresee electricity use climbing inexorably, far into the future. Reserve margins that are too high to begin with are routinely exceeded. And prices for renewable energy have dropped faster than anticipated, drastically changing power markets.

Utility executives, faced with an uncertain future and demanding new state renewable energy mandates, often fall back on doing what they have always done: installing more capacity.

Based on dozens of interviews with regulators, utility executives, developers and investors, along with public information requests and data from S&P Global Market Intelligence, this series will explore the root causes of the power supply glut and the future of electricity generation in the U.S. as it unfolds across several regions and multiple companies.

In PJM Interconnection, the nation's largest grid operator, more than 29,000 MW of new gas plants have been added since 2008, despite slack demand, and nearly 30,000 MW of gas capacity are planned by 2027, at a cost that will almost certainly surpass $30 billion. In Virginia, where Dominion Energy Inc.'s Virginia subsidiary has long wielded immense political power and consistently over-forecast electricity demand, regulators and politicians are finally pushing back in order to hasten a transition to renewable energy. NextEra Energy Inc., which has long positioned itself as a leading champion of renewable energy, has continued a decade-long spending spree on natural gas in Florida, where its utility subsidiary Florida Power & Light Co. has added thousands of megawatts of new gas capacity even as company executives heralded the cost-effectiveness of cleaner alternatives. And in California, the state's ambitious zero-emissions energy policy is running up against the challenges of legacy gas plants and intermittent solar power supplies.

How this all sorts out will determine the prospects for decarbonizing the U.S. electric grid and will shape the future of the U.S. power sector for decades to come.