The Blind Spot in Utility Law: Are Utilities Too Big to Fail?

By Jamie Van Nostrand, Policy Director

We inhabited each other

Like it was some kind of disease

I thought that I was flyin’

But I was crawling on my knees

Everybody’s got a blind spot

Brings ‘em down

Everybody’s got a blind spot

They can’t get around

-- Blind Spot, from Streets of Philadelphia Sessions
Bruce Springsteen (1995)

My last Based Rates post, Wasteful Wires-Versus-Pipes Competition, described the “blind spot in utility law” – the failure of the governing regulatory statutes enacted in the early 20^th century to anticipate the potential for wasteful competition between gas and electric utilities. Because the statutes never saw that competition coming, they built no machinery to manage it. The result is that, for 120 years, electric and gas utilities have survived side by side as separately regulated monopolies, never once being required to deal with the fact that they are increasingly fighting over the same customers to deliver what they ultimately need — energy. Worse, the current regulatory framework actually steers PUCs away from addressing growing competition proactively. This is the blind spot that we can’t get around.

This post discusses the components of the existing utility framework, and the barriers they present in managing the competition between wires and pipes utilities. It is this framework that makes it very difficult for utilities and their regulators to take the necessary action to manage the transition currently underway in the natural gas distribution business, by matching the decline in gas demand and gas utility revenues with contraction of the gas distribution system. Rather than confronting the systemic threat of competition and crafting remedies to the blind spot in utility law, the default strategy is to treat gas utilities as too big to fail, and to stumble along with incomplete solutions that ultimately will result in substantially higher energy bills for customers.

FoHI’s General Counsel and Research Director, Justin Gundlach, and Josh Lappen, a Fellow at FoHI and Postdoctoral Research Associate at the University of Notre Dame, explore these issues comprehensively in an article, Managing Wasteful Competition Between Wires and Pipes Utilities, recently published in the Energy Law Journal. This post draws extensively from their excellent research, analysis, and, in many cases, their words.

The Existing Utility Framework

As discussed in my previous Based Rates post, the PUCs that oversee gas distribution utilities’ operations and investment decisions are governed by a long-lived regulatory framework, the components of which have been adopted through PUCs’ organic statutes, statutory amendments, regulations, and PUC orders in combinations that vary across states. These components include:

Property and process rights of a “natural monopoly.” Electric and gas utilities that operate in the same territory – and thus compete for customers – are treated as separate entities with distinct rights, based on the premise that each is a distinct natural monopoly. At the local level, municipalities grant co-located electric and gas utilities separate, exclusive franchises to access public rights of way. At the state level, PUCs likewise grant them separate certificates of public convenience and necessity to build and operate their networks. In rate proceedings, PUCs also approve additions to utilities’ rate bases and recovery of costs separately for electric and gas utilities. This is true even if a single corporate parent owns both the electric and gas utility operating units in a given territory (i.e., rates for the gas division are determined separately from the electric division), although in practice, common ownership makes for a less precise boundary between co-owned operating units. Under state laws and the Fifth and Fourteenth Amendments to the United States Constitution, each utility has access to protections with respect to the regulatory process, legal process more generally, and property rights. Under these protections, determinations by the PUC must be reasonable and supported by evidence in the record, and rates cannot be set so low relative to the utility’s costs to be deemed “confiscatory.”

Obligation to serve. The governing regulatory statute in each state generally imposes on electric and gas utilities the obligation to provide safe and adequate service to any customers within the service territory who want to begin, resume, or continue receiving service. Utilities also may not cease operating in that territory without authorization. A variety of exceptions to this obligation have been established in different jurisdictions – for instance, where extending service would adversely affect existing customers, or constitute a clear financial loss to the utility, because requiring investment in such a circumstance could amount to a taking of property. The obligation to serve is generally implemented in a fuel-specific way, such that providing electric service in response to a request for gas service would not satisfy a utility’s obligation. In New York, for example, distinct obligations to utilities are assigned based on the type of fuel or energy they deliver – “gas, electricity, or steam.” In other states, however, the obligation is stated more ambiguously, and a PUC could define the obligation to be fuel-neutral, so long as the definition it adopts stays within the bounds of the relevant statutory provisions and is supported with appropriate reasoning and evidence.

Nondiscrimination. Utilities are prohibited from varying access or terms and conditions of service (including rates) across different customers in a way that is unduly preferential or discriminatory, unless authorized by statute. In other words, rates and other charges must be designed as nearly as possible to assign costs to the class of customers that creates them. Variation is permissible across customer classes, or if there is a rational basis for offering different terms of service (in which case the discriminatory treatment is not “unduly” so). The key question is whether a rate varies across customers who are “similar,” “alike,” or “similarly situated.” A residential or commercial customer located at the periphery of a utility’s network, for example, should pay the same as a customer in the same rate class who is located at the core.

Adequate service. The gas service offered to residential and small commercial customers must satisfy various standards relating to safety and “adequacy,” which generally refers to reliability and efficiency. Adequacy is typically evaluated through periodic gas forecast and supply plans filed with the PUCs. With respect to the forecasting function, gas system planning generally relies on two interconnected forecasts. The first is the annual sales forecast, which estimates expected gas consumption under typical or average conditions based on assumptions about customer growth, customer behavior, equipment adoption, building stock changes, weather, technology costs and performance, and applicable policy requirements The second is the “design day” demand forecast, which estimates the level of daily gas demand the system must be able to serve during an extremely cold day. The supply analysis examines the various strategies available to the LDC to meet the forecasted loads, including the adequacy and reasonableness of contracts that LDCs enter into to obtain the commodity (via supply contracts) and the pipeline or storage capacity to deliver gas (capacity contracts) to the utility, which then pipes the gas to its customers.

“Rate of return regulation.” As described in an earlier Based Rates post, The Hard Work of Challenging Gas Infrastructure Spending, the money that an LDC spends on pipes gets included in its “rate base” upon which it earns a return, or profit. In other words, the more an LDC spends on pipes, the more it earns – and delivery charges for customers go up. And they have: the cost of delivering natural gas to customers has nearly doubled since 2011, growing at more than twice the rate of inflation. Under rate-of-return regulation, LDCs in many respects are infrastructure companies – their earnings depend on how much undepreciated infrastructure they own and operate. This results in a strong “regulatory bias” in favor of over-investing in assets on which they are granted a rate of return. This regulatory bias is exacerbated if the profit level, or return, set by regulators in rate proceedings is higher than the LDCs’ actual costs of securing that capital. As discussed in another earlier Based Rates post, The Circle Game, recent analyses performed by cost of capital experts tend to show that allowed equity returns have been systematically set by regulators for decades at a level that far exceeds the actual cost of equity. This bias not only incentivizes LDCs to overinvest, it also strongly disincentivizes them to forego new investments or accelerate the depreciation of old ones.

The Framework in Operation

In combination, the components described above make it difficult for a PUC to interrupt the self-reinforcing pattern that emerges under the current regulatory regime. Gas utilities are bound by an obligation to serve, incentivized to make new investments in infrastructure and to preserve existing investments, required to provide similar service at non-discriminatory rates across their entire network, and enjoy strong legal protections against any revision to what they may recover from their customers to cover the costs of their rate base, including depreciation expense. As a result, LDCs will resist removing assets from service in order to continue to recover a rate of return on those assets rather than winding down the financially nonviable segments of their network. Further, where maintaining safety and reliability arguably requires it, gas utilities will seek to make further investments in such segments, primarily through the infrastructure tracking mechanisms discussed in the Based Rates post titled, Debased Rates.

To illustrate where this leads amid falling gas demand, Gundlach and Lappen include the following two simplified hypothetical situations:

The Hybrid Holdouts

In the first, customers located along a given gas network segment adopt hybrid solutions, installing heat pumps for space and water heating and to handle 90% of the heating hours in an average year, but retaining a gas stove and gas-fired furnace instead of upgrading the energy efficiency of the building envelope or installing electric resistance heating for the fraction of heating hours when the heat pump performs at a low COP [coefficient of performance]. Electrifying water heating and the bulk of space heating means radically changing the pattern and volume of gas consumption on that segment over the course of an average year. In most months, customers might consume 5% of the previous amount – just enough to cook with – and in the coldest six to twelve weeks of the year, the percentage might rise to 30% or even 50%. Notably, as the nationwide average breakdown between delivery (pipes) and supply (gas) costs is about 70-30 today, this change would mean that customers would see only a relatively small reduction in their gas bills even though they sharply reduce their consumption. From the utility’s perspective, let us posit that this change pushes the economic profile of that segment from revenue-positive to net-costly. Even so, the utility still has strong incentives to continue serving the remaining customers there because it can still recover significant revenue from those customers and can continue to increase its rate base by making capital investments in that distribution segment. At the same time, the utility arguably lacks clear authority to cease providing those customers with service. Faced with these incentives, a utility is highly likely to respond by continuing to operate the segment in question, while raising rates across its entire service territory to make up for the reduction in revenue flowing from the segment.

The Partial Exodus

Under the second scenario facing this hypothetical segment, one-third of the customers electrify fully. Demand falls in this instance as well, but somewhat differently. The volume of gas demanded declines, albeit less than in the first situation, but so does the number of customers paying a delivery charge for use of the segment, which the utility must continue to operate. Indeed, even the service lines to the electrified homes will not necessarily be decommissioned, because the obligation to serve in that jurisdiction might require the utility to extend service to the same property if a future resident wants gas. Here again, the segment becomes net-costly, as its cost of maintenance remains unchanged amid a sharp decline in revenues from the customers it serves.

As noted by Gundlach and Lappen, in the event situations like these occur throughout even a fraction of an LDC’s network, they could push the utility into a financial slide without reshaping its short-term incentives or its obligations to its remaining customers. And the adverse impacts will not fall evenly across an LDC’s customer base; rather they will be felt most acutely and painfully by low- to moderate-income gas customers, for whom the investments required to electrify are out of reach.

The Regulatory Response

Given the current blind spot in utility law, there are limited options available to a PUC faced with an LDC that is experiencing uncoordinated declining demand on one or more system segments. Ideally, the segments that turn net-costly would be pruned, or decommissioned, as a means of preserving the economic viability and safe operation of the rest of the gas network. Such a pruning, however, would require coordinating the departure of the customers who remain on a given segment as a group – commonly referred to as a “managed transition” – through a local non-pipe alternative (NPA) project. Under an NPA, the local networked gas service would be decommissioned in favor of some combination of energy efficiency and electrification measures – and, potentially, delivered fuels (e.g., propane or fuel oil) that can provide viable and cost-effective substitutes for gas service.¹ But if the remaining gas customers, or just a small subset of them, refuse to go along – the “holdout” problem – they would thereby pit the utility’s assumed obligation to serve against the viability, cost-effectiveness, and long-term fiscal necessity of a particular NPA proposal as well as the ability to manage the broader transition. Moving ahead despite the presence of holdouts would require regulators to justify, on legal and policy grounds, terminating piped gas service for customers who previously had it.

The legal basis for doing so is stronger in those states with a fuel-neutral obligation to serve, as an obligation to provide “energy” would continue to be satisfied. Even in jurisdictions where the statutory basis for the obligation to serve grants a PUC discretion or special grounds to overrule a holdout’s preference, however, a regulatory decision to end gas service would still present challenges. Opponents would likely cast the PUC’s action – not the background conditions of wasteful wires-versus-pipes competition and declining demand – as the cause of disruption to the status quo. As noted by Gundlach and Lappen, “[s]uch an argument might not move a court, but it would not need to in order to resonate politically.”

Implications for The Path Forward

Regulators across the U.S. have largely failed to confront the systemic threat of competition and to remedy the blind spot in utility law that we can’t get around. The continued existence of LDCs in perpetuity is taken as a given, and a “too big to fail” approach necessarily follows. The closest most regulators have come to addressing these issues is the launch of proceedings to examine the long-term role of natural gas distribution utilities in light of state climate goals, evolving customer behavior, developments in appliances and end-use equipment. Fourteen states currently have various proceedings at various stages on the “future of gas,” “future of heat,” or “gas planning.” They differ from state to state in scope, form, process, procedure, and origin – some have been initiated by commission order, others by legislative mandate, and still others at the request of other state agencies. The issues addressed range from long term demand forecasting and infrastructure investment planning to the evaluation of alternatives to traditional pipeline replacement, and the potential for an evolution of utility business models.

For the most part, however, the scope of these proceedings does not extend to the fundamental examination necessary to fashion effective remedies to the blind spot, thereby potentially yielding incomplete solutions that fail to reign in the high costs resulting from the existing siloed utility regulatory framework. For their part, Gundlach and Lappen offer several recommended reforms to the utility regulatory framework in the final sections of their article, including deregulation of the gas distribution business, integration of co-located electric and gas operating units, and various forms of public ownership. These recommendations will be the subject of an upcoming Based Rates post.

1. It is notable also that PUCs generally have no direct authority over the companies that supply delivered fuels like propane and fuel oil to customers, nor the infrastructure involved in their operations. This is significant because, although delivered fuels could substitute quite readily for gas in many cases, a PUC would have only indirect means available to make access to such fuels part of an NPA project, and no direct means available to manage the costs involved in that substitution.