A Bridge Backward? The Risky Economics of New Natural Gas Infrastructure in the United States
Over the past two decades, natural gas has dramatically reshaped the US electricity industry. Domestic shale gas production has lowered gas prices and driven the expansion of the gas-fired power plant fleet, enabling natural gas to capture significant market share as the single-largest fuel source for electricity generation. Given its role in facilitating coal plant retirements, natural gas is often characterized as a “bridge fuel” to a clean energy future. Utilities and other gas investors expect this bridge to continue long into the future: as of mid-2019, planned investment in new gas power plants and pipelines totals over $100 billion.
However, the rapidly falling prices and improving capabilities of technologies that can combine to form clean energy portfolios (CEPs)—optimized combinations of wind, solar, battery storage, and demand-side management that can provide the same grid services as a gas plant—call into question the cost-effectiveness of investment in new gas infrastructure. In just the past year, leading utilities’ investment proposals have pivoted heavily to CEPs, with announced projects in Colorado, Michigan, Indiana, California, North Carolina, Oregon, and other states that underline the emerging cost advantage that CEPs now enjoy over new gas-fired generation.
In two new reports released today by Rocky Mountain Institute (RMI), we examine this growing trend by analyzing the economics of new natural gas-fired power plants and interstate gas pipelines in the context of the rapidly falling costs of clean energy resources. We find that the natural gas bridge is likely already behind us, and that continued investment in announced gas projects risks creating tens of billions of dollars in stranded costs by the mid-2030s, when new gas plants and pipelines will rapidly become uneconomic as clean energy costs continue to fall.
A tipping point for the economics of clean energy portfolios
In 2018, RMI published The Economics of Clean Energy Portfolios and found, across four diverse case studies from around the United States, that CEPs can provide the same energy, capacity, and flexibility as new gas plants, often at significantly lower costs. Our update to the 2018 report examines all 88 cases where utilities or independent power producers have proposed to build new gas-fired generation in the United States, with most of these projects slated to come online between 2020 and 2025.
Our study finds that 2019 represents a tipping point in the relative costs of CEPs and gas-fired power plants. Figure 1, below, shows the comparison between the costs for a typical new-build combined-cycle gas generator, and an equivalent CEP. Since 2010, CEP costs (blue line) have fallen by 80 percent and are now at the point where they undercut the costs to build and run a new gas-fired power plant (solid orange line). Furthermore, by the mid-2030s, as the costs of clean energy technologies continue to fall, the costs to build a new CEP are likely to undercut just the costs to operate a gas-fired power plant (dashed orange line).
Figure 1: 2019 represents a tipping point for CEP economics versus new gas-fired power plants
This result is already playing out in the market, with final investment decisions for new gas plants in the United States declining each year since 2014. Our study finds that 90 percent of new gas-fired capacity proposed for construction in the next five years could be cost-effectively avoided with CEPs. Prioritizing clean energy investment in these cases would unlock $29 billion in net customer savings and avoid 100 million tons of CO2 emissions each year—equivalent to 5 percent of current US electricity-sector emissions.
Stranded investment risk for new gas-fired power plants
Just as persistently low natural gas prices have contributed to the early retirement of dozens of coal plants across the United States in the past decade, the declining costs of clean energy are poised to have the same effect on gas-fired generators being proposed for construction today.
Our study finds that, by 2035, over 90 percent of proposed combined-cycle gas plants, if built, would be uneconomic to run compared to the cost of building a new clean energy portfolio. Figure 2 illustrates this result, showing the percentage of proposed combined-cycle gas projects that would be more expensive to operate than a new CEP would be to build for each year from 2020 to 2040. Investors in these projects will likely face a significant risk of stranded investments, with tens of billions of dollars in book value remaining on assets without a clear source of future revenues given competition from clean energy. There is already evidence that this is happening to gas plants today, with falling capacity factors among combined-cycle plants less than 20 years old, due in part to competition from clean energy.
Figure 2: 90 percent of proposed combined-cycle gas plants, if built, will face stranded investment risk by 2035
Gas pipeline investments are at risk as gas power plants are outcompeted
Building on our analysis of clean energy portfolio economics, our companion report on gas pipeline economics shows how the growth in US gas use in the past 20 years has been driven almost exclusively by gas-fired power plants. Power-sector use of gas has increased by 160 percent since 1997, versus just 4 percent growth in gas use across all other sectors. At the same time, interstate gas pipeline transmission capacity has increased by over 60 percent, and gas-fired power plants are now among the largest sources of demand for gas shipped over interstate pipelines.
But as our study shows, this growth in the power sector’s gas use is set to stop within the near future. Our study assesses the impacts of the pending slowdown in gas power on the economic viability of new gas pipelines that, in part, are being proposed to meet presumed growing demand in the power sector. We find that across five regions covering most of the eastern United States, throughput on new gas pipelines will fall 20–60 percent below presumed levels by 2035, depending on the share of pipeline capacity presumed to serve new power plants in each region. This decline in throughput will lead to rising costs for delivered gas borne, in most cases, by captive utility customers.
Figure 3: Utilization of new gas pipelines in five US regions will likely fall by 20–60 percent from assumed levels by 2035 due to competition from CEPs
Near-term priorities to seize opportunities and avoid risks
Our research highlights, on the one hand, the incredible opportunity present to prioritize investment in clean energy and unlock customer savings and lower carbon emissions. On the other hand, our research highlights a significant risk that continued natural gas infrastructure investment will turn into a bridge to bankruptcy for investors and stranded investments that captive customers will have to pay for. Our reports offer several recommendations to industry stakeholders to help navigate the rapidly changing market and support investment decisions compatible with emerging market trends.
- Update resource planning and procurement processes. Leading utilities use best-in-class planning tools and approaches that fully capture the ability of clean energy technologies to provide grid services, and then go directly to the market with all-source, technology-neutral procurements to find least-cost solutions.
- Leverage the demand side. Incorporating demand flexibility and efficiency into resource planning allows for far more cost-effective resource portfolios and grows the market for CEPs.
For utility regulators:
- Carefully consider stranded cost risk. Regulators should carefully weigh near-term proposals for cost recovery associated with new gas power plants and pipelines, given the continuing cost declines of clean energy technologies, to avoid placing risk of uneconomic investments on captive customers.
- Incentivize equal competition among resources: Many utilities earn profits only through return on capital invested and have no earnings incentives for pass-through costs incurred by means of power purchase agreements or other procurement approaches for CEPs. Regulators have an opportunity to adjust earnings mechanisms to provide utilities an incentive to procure nontraditional technologies and grow the market for CEPs.
For pipeline regulators:
- Carefully assess project need. Our analysis shows that presumed demand growth from gas power plants will likely fail to materialize, and new pipelines that rely on delivery to power plants will be underutilized by the mid-2030s. Regulators have an opportunity to holistically assess future demand over the full lifetime of proposed pipeline investments, and allocate risk accordingly in project certificates or cost-recovery approvals.