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Winter 2023: The Future of the Energy Grid

Regulatory and Policy Responses for Managing the Natural Gas Industry’s Downward Spiral

James Maurice Van Nostrand


  • Focuses on local natural gas distribution companies (LDCs), which are regulated by state public utility commissions (PUCs).
  • Takes a look at similar transitions historically in the utility industry.
  • Discusses the implications for retail energy utilities.
Regulatory and Policy Responses for Managing the Natural Gas Industry’s Downward Spiral
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Many states in the United States are adopting aggressive “clean energy” goals, such as committing to a “zero carbon” economy over the next 10 to 20 years. Maryland, for example, passed the Climate Solutions Now Act in April 2022, which adopts a goal of reducing greenhouse gas (GHG) emissions by 60% from 2006 levels by 2031, and achieving carbon neutrality by 2045. These initiatives are driven by the urgent need to reduce GHG emissions to address climate change. The most recent report of the Intergovernmental Panel on Climate Change (IPCC), for example, found that limiting warming to around 1.5°C would require global GHG emissions to begin to peak no later than 2025 and be reduced by 43% by 2030; at the same time, methane (the primary component of natural gas) would also need to be reduced by about a third.

These initiatives have major implications for the financial viability of the domestic natural gas industry, at virtually all levels (production, interstate transportation, and local distribution). Natural gas is rapidly being phased out as a fuel for generating electricity (in favor of renewables), and many retail energy utilities are promoting the elimination of natural gas for space and water heating in favor of electricity. State and local governments, for their part, are enacting bans on new natural gas hookups. The winding down of the natural gas industry must be carefully and thoughtfully managed by policy makers to minimize the impact on the economy and ensure the financial viability of the regulated sectors (e.g., wholesale pipelines and local distribution companies) during the transition. This article focuses in particular on local natural gas distribution companies (LDCs), which are regulated by state public utility commissions (PUCs).

Addressing Climate Change Requires a New Regulatory Paradigm

Regulators do not typically set energy rates in a manner that reflects environmental impacts. Rather, the traditional focus of regulators when setting rates for energy utilities has been to provide for the recovery of the reasonable cost of service at the lowest practicable cost of meeting the energy demands of customers, plus a reasonable return on the investments necessary to provide such service. The statutes governing ratemaking authority for most state PUCs directs the regulators to set “just and reasonable rates.” That is a broad grant of authority, giving regulators general oversight authority over the rates and practices of their jurisdictional utilities. In the case of investor-owned utilities, regulators are charged with balancing the interests of shareholders (in earning higher profits) against ratepayers’ interests (in receiving affordable utility service). The goal is generally to set rates at the lowest reasonable level over time that still allows the utility to maintain its financial integrity in order to be able to raise the necessary capital to support utility operations.

Addressing climate change through integration of environmental factors, on the other hand, is somewhat inconsistent with the traditional ratemaking process in that it will likely result in higher rates, at least in the short term. The long-term planning process for electric utilities, known as “integrated resource planning,” is a good example of how the integration of environmental considerations can result in higher rates than would otherwise occur in the absence of such integration. Integrated resource planning involves the determination of whether a utility needs to acquire additional resources to serve its projected loads and, if so, the identification of the resource or portfolio of resources that will meet those loads reliably over time and at the lowest practicable cost to the utility (and its customers). Most utilities, under requirements imposed by PUCs, have historically used “environmental adders” as part of that process to attempt to reflect the total cost—both economic, in terms of dollars per megawatt-hour (MWh) to generate electricity, as well as environmental impacts—of a particular resource. These “adders,” such as putting a “price on carbon” for carbon-emitting resources (e.g., coal- and natural gas-fired plants), thereby burden these carbon-emitting resources with a higher total cost, which comparatively benefits carbon-free resources, such as nuclear plants and wind and solar facilities.

In other words, a utility examining the array of resource options available to it will go beyond just looking at the relative cost of generating a MWh of electricity and will also consider the environmental impacts of generating that MWh of electricity. While renewable energy resources are already cheaper than continuing to operate existing coal plants in most regions of the country, natural gas–fired generation (prior to the momentary surge in natural gas prices in 2022) continued to retain a slight price advantage over renewable resources in many parts of the country. Thus, a utility, in the absence of the inclusion of environmental adders, might choose a new natural gas–fired generating resource as the most cost-effective option for customers, based solely on economic factors. To the extent the inclusion of environmental adders pushes the utility toward a higher-cost, zero-carbon option, the integration of environmental factors in the ratemaking process may result in the utility acquiring a portfolio of resources that costs slightly more than had environmental factors not been considered. Placing ever higher prices on carbon as part of the integrated resource planning process—to reflect the urgency of addressing climate change—may result in an even greater divergence between the “lowest-cost” path and the environmentally preferable path.

This departure from looking strictly at only economic factors in the ratemaking process is arguably within a PUC’s broad grant of authority to set “just and reasonable” rates. In those states where the ratemaking grant of authority is narrower, integrating environmental factors into the ratemaking process may require amendment of existing rate-setting authority, particularly if such integration may result in higher rates.

More recently, states with aggressive GHG-reduction goals are promoting “beneficial electrification” measures by electric utilities. Beneficial electrification seeks to phase out the use of natural gas for space and water heating in favor of electric appliances (e.g., heat pumps for space heating and electric water heaters) in the pursuit of reductions in GHG emissions. About half of American homes use natural gas, and appliances burning natural gas make up about 13% of GHG emissions in the United States, according to the Environmental Protection Agency. At least 95% of those emissions come from furnaces, water heaters, stoves, and clothes dryers powered by natural gas. The complication for policy makers is that using natural gas in many regions of the United States—particularly in colder climates in the case of space heating—is a cheaper, more efficient means of meeting the space and water heating needs of utility customers (depending upon the relative price of natural gas versus electricity in the region). This decarbonization initiative may therefore result in higher energy costs for consumers. Rather than regulators focusing on an array of utility services designed to help consumers manage their energy costs by providing utility service at the lowest cost, the focus is evolving to achieving reductions of GHG emissions associated with space and water heating, as a means of addressing climate change. This goes far beyond the traditional role of PUCs in regulating energy prices for the benefit of consumers.

Beneficial electrification efforts also involve equity issues, as lower-income ratepayers (and consumer advocates) are more interested in an affordable energy supply rather than pursuing environmental objectives in setting utility rates. And low-income customers may lack the financial resources to pay the upfront capital costs associated with switching out natural gas furnaces to electric heat pumps. As a result, beneficial electrification programs typically involve subsidies, or incentives, to assist in covering these upfront capital costs.

In addition to PUC-approved programs to promote beneficial electrification, many cities throughout the United States are adopting prohibitions on new natural gas hookups, thereby removing the option for customers to use natural gas for space or water heating. In the summer of 2019, Berkeley, California, became the first city in the nation to ban gas hookups in new buildings. Over the next three years, the gas ban trend spread rapidly: As of June 2022, 77 cities and towns, as well as the entire state of Washington, have banned or discouraged new natural gas hookups.

Apart from these initiatives by policy makers to promote GHG reductions, advances in technology and the availability of cost-effective distributed energy resources (DERs) have triggered a fundamental reevaluation of the utility business model (and, correspondingly, the regulatory model). Electric utilities, for example, are selling less energy, due to customers increasingly generating their own electricity—primarily through rooftop solar—and reducing their electricity consumption by taking advantage of energy efficiency programs. As a result, the traditional ratemaking model—the utility recovering its revenue requirement through sales of electricity—is being overhauled to compensate the utility for pursuing other initiatives that promote the broader public interest, through a suite of regulatory measures known as “performance-based ratemaking.” Through these mechanisms, the traditional method for basing revenues on kilowatt-hour (kWh) sales can be supplemented to reward utilities for successfully pursuing public policy objectives, such as GHG reductions, facilitating the integration of DERs, or implementing beneficial electrification programs. The Reforming the Energy Vision (REV) initiative in New York is a leading example of a state taking action to develop a new regulatory regime to accommodate the changing business model for electric utilities. The REV initiative, commenced by the New York Public Service Commission in 2014, envisions that electric utilities will assume the role of distribution platform operator, facilitating two-way flows of energy and communications between the utility and its customers rather than the traditional utility business model involving large, centralized generating stations and one-way power and information flows to customers.

The regulatory model for natural gas utilities will necessarily change as well, as sales decline and additional investments in natural gas distribution infrastructure are phased out. State policy makers will need to manage the transition in a manner that allows the provision of essential utility service to continue and for investors to have a reasonable opportunity to recover their investment in existing natural gas infrastructure. Just as on the electric side, PUCs will need to consider implementation of performance-based ratemaking programs, to ensure that LDCs will continue to recover their revenue requirement in the face of declining sales and a shrinking rate base upon which to earn a return. Incentives could be provided, for example, for accelerating decarbonization efforts and pursuing “non-pipe solutions,” the term for avoiding traditional investments in distribution infrastructure in favor of programs that reduce or eliminate the demand for natural gas. Non-pipe solutions are geared toward reducing gas demand, such as through targeted energy efficiency programs and weatherization, thermal storage, beneficial electrification, or clean-energy microgrids. Instead of investment in traditional gas infrastructure expansions—the business-as-usual approach—utilities identify the specific gas supply constraint or demand-reduction need and evaluate whether a combination of demand- and supply-side products and services can address the need. To encourage greater innovation, LDCs could issue competitive solicitations that would enable other energy service companies to offer non-pipe solutions. In New York, for example, Consolidated Edison has established a program that solicited proposals from third-party vendors for a variety of innovative non-pipe solutions.

Implications for Retail Energy Utilities

LDCs have invested billions of dollars in infrastructure (e.g., gas mains and distribution lines) pursuant to a “regulatory compact.” Under this regulatory compact, energy utilities have an obligation to serve customers requesting service within an exclusive service territory. In return, utilities make the necessary investments in infrastructure to fulfill that obligation, and their rates are set by regulators at a level that gives utilities an opportunity to recover, and earn a reasonable return on, their investment in this infrastructure. So long as the infrastructure investments are prudent, utilities (and their investors) have an expectation that the costs of those investments will be recoverable in rates over time. Denial of that recovery by regulators will result in claims of confiscatory rates, in violation of the Fifth and Fourteenth Amendments to the U.S. Constitution. The “just and reasonable” standard in setting rates incorporates the constitutional protections for investors that they are entitled to earn a reasonable return on the assets devoted to providing utility service. Managing the transition for LDCs thus raises constitutional issues, as investors in LDCs have a reasonable expectation that regulators will fulfill their statutory obligation in setting “just and reasonable” rates to allow utilities to maintain their financial integrity. Regulators must be mindful of the implications of failing to provide for rate recovery of investments by LDCs in infrastructure.

It should be noted that there are situations where the regulator may be precluded from setting compensatory rates due to market forces. A 1945 U.S. Supreme Court case, Market Street Railway v. Railroad Commission of California, 324 U.S. 548 (1945), involved declining ridership on a combination streetcar/bus system in San Francisco due to competition from a municipal street railway line. When the system owner, Market Street Railway, requested a hike in fare to seven cents to increase its revenue in an effort to earn a reasonable profit and restore its financial integrity, the Railroad Commission determined that any fare above six cents would have resulted in fewer passengers, due to competition from other forms of transportation. It therefore denied any rate relief, resulting in the Railway continuing to operate at a loss. When the Railway challenged the order as confiscatory, the Supreme Court held that the protection of the Due Process clause “has not and cannot be applied to insure values or to restore values that have been lost by the operation of market forces.” Id. at 780. Under these circumstances, investors were not entitled under the constitution to an opportunity to earn a reasonable return on their investment. Where public policy favoring the reduction of GHG emissions, and not market forces, is the driver, however, the Market Street Railway decision may be inapposite, and regulators will continue to be obliged to provide a reasonable opportunity for LDCs to recover their investments in infrastructure.

The implications are twofold. First, going forward, regulators need to adopt policies that discourage LDCs from making any additional investment in expansion of natural gas distribution infrastructure. This investment will potentially become “stranded”—meaning it will cease to be “used and useful” in providing utility service, and thus be excluded from the rate base upon which the utility earns a return—as natural gas usage is phased out. Recovering the investment in rates will prove to be problematic, as gas sales—and, correspondingly, the revenues collected by LDCs—decline. One way to discourage new investment is to phase out line extension allowances for new connections; these allowances currently cover a portion of the upfront costs incurred by customers when they initiate gas service. Another tool, as discussed above, is the consideration of non-pipe solutions.

Second, apart from reducing or eliminating new investment in infrastructure, regulators will need to address the rate recovery of existing investment, which can have a lifespan of 65 years. Some utilities (“combination utilities”) provide both electric and natural gas service to a given area, while others provide only gas (“straight gas utilities”). Combination utilities are well-positioned to promote beneficial electrification. Customers seeking a new gas hookup, for example, can be accommodated by having their energy needs met through electric appliances rather than using natural gas appliances. Existing natural gas customers can be provided incentives to convert their gas appliances to electric ones. For combination utilities, phasing out of the natural gas distribution business can to a large extent be offset by expansion of electric operations. These companies may experience lower profits as a result of decline in investment in natural gas infrastructure as compared to the “business-as-usual” path. But they can be held harmless for those losses through ratemaking adjustments. An incentive mechanism could be implemented, for example, that would reward the combination utility for accelerating the decarbonization effort.

For straight gas utilities, the analysis is much more complicated, as their core business is being eliminated over time. Some LDCs are proposing development of renewable natural gas (derived from inedible food waste, manure, municipal solid waste, and wastewater) to replace methane. And there is also the possibility of serving retail customers with a blend of natural gas and hydrogen. But these alternatives are not likely to be developed on a sufficient scale to preserve the existing business model for straight gas utilities. The challenge for policy makers is to manage the transition—essentially the decommissioning of existing natural gas infrastructure—while ensuring the financial integrity of these straight gas utilities during the process to enable them to safely and affordably meet essential customer needs.

Decommissioning will require strong direction from regulators, and rigorous planning and communication with customers. Customers currently using gas appliances, for example, will need ample warning, time, and financial resources to convert these appliances to electric power. Decommissioning gas infrastructure will ultimately require productive assets to be retired early, resulting in potential losses to utilities. These losses can be minimized through a strategy referred to as “securitization,” which essentially allows the stranded infrastructure investment to be refinanced at a lower capital cost and thus reduce the impact on ratepayers associated with paying off investments in stranded utility assets. Roughly half of the states currently have statutes in place that authorize securitization, in many cases in response to the transition away from coal-fired power generation and the premature retirement of existing coal plants.

Historical Precedent for Similar Transitions in Utility Industry

While the rapid decarbonization of the energy industry will result in significant impacts on the continued operation and long-term prospects for LDCs, this is not the first time that regulated industries have been forced to respond to fundamental transformations in the business. It is helpful to examine the circumstances of, and response to, similar transitions that have arisen in the utility industry.

One such example is the evolution that occurred in the telecommunication industry during the first decade of the 21st century. Telecommunications utilities were traditionally regulated in the manner as energy utilities, with PUCs engaging in the same sort of ratemaking process to determine the prices to be charged for telephone services, primarily landline, or wired, service in the case of retail customers. PUCs would determine how much revenue the telecommunications providers were authorized to collect and would prescribe the “rate design”—the various elements in the utility customer’s bill—that would produce that revenue, such as how much your local telephone company would be able to collect as a “basic charge” for telephone service. Due to technological advances in the telecommunications industry, the services exclusively provided by landline-based telephone companies came to be provided as well through wireless or cellular providers and broadband service offered by cable operators. The introduction of effective competition to telephone companies not only lessened the need for regulation of their rates—customers could respond to higher prices by simply terminating their landline phone service in favor of cellular—but also imperiled the ability of traditional landline telephone companies to recover the costs of their existing network. In other words, technological innovation was quickly eroding the business model of the traditional telephone company.

Regulators generally responded by adjusting the depreciation schedules—depreciation reflects the diminution in the value of an asset over time due in particular to wear and tear, and is included in rates as part of the utility’s cost of service—to depreciate the assets over a shorter useful life. Shortening the useful life reflected that telecommunications assets were becoming obsolete more quickly due to technological advances. By allowing the recovery of the investment in network infrastructure to occur more rapidly, investors in telecommunications companies were largely “made whole” for their prudent investments. This result was achieved because the pace of the transformation of the industry—over a period of nearly a decade—enabled the investment to be recovered while the industry remained sufficiently viable financially. The upward pressure on rates caused by accelerating the depreciation charges had the corresponding effect of accelerating the transition away from landline phone services. But regulators fulfilled their obligations under the regulatory compact of setting “just and reasonable” rates in a manner that allowed telecommunications companies to have an opportunity to recover their investment.

The transformation being imposed upon LDCs is different in a material respect from the circumstances in the telecommunications industry, and also those presented in the Market Street Railway decision discussed earlier. The threatened demise of the LDC business model is due not to technological advances—as in the case of the telecommunications industry—or to market forces—as in the case of Market Street Railway—but rather to integration of environmental factors into the ratemaking process. Specifically, the business prospects for LDCs are gravely impaired due to the urgent need to reduce GHG emissions by decarbonizing the energy sector. While the obligation owed to investors in such a situation is not entirely clear, in the absence of imprudent investments by LDCs, the regulatory compact (and constitutional due process) would suggest that investors are entitled to recover their investment. Regulators are thus faced with the challenges of managing the orderly wind down of the LDC business while fashioning creative ratemaking mechanisms and regulatory policies that allow recovery of the prudently incurred unamortized investments in natural gas distribution infrastructure.

The Path Forward

Policy makers and regulators face a daunting challenge in managing the transition in the natural gas industry triggered by ambitious decarbonization goals. In order for the United States to meet its GHG reduction goals, this transition must occur fairly rapidly, and regulated retail utilities are unaccustomed to moving so quickly. The delivery of energy is an essential service that is capital-intensive, so preserving the financial viability of LDCs during the transition is critical. Policy makers will need to be creative in developing ratemaking mechanisms to respond to these challenges, such as the use of performance-based ratemaking to provide LDCs with additional sources of revenue to offset, at least in part, the inevitable decline in sales of natural gas. Policy makers will also need to be mindful of the constitutional and statutory requirements that apply to regulated entities (and to their investors who committed billions of dollars in reliance on the regulatory compact). Broader economic implications come into play as well, as policy makers will be faced with the impacts on communities dependent upon fossil fuel industries and ensuring a “just transition” for the workforce currently employed in the natural gas industry.