Climate Change, the Regulatory Compact, and Public Utility Rights

Climate change has prompted some states to adopt legislation and policies to reduce greenhouse gases and increase the share of energy provided by renewable sources.¹ Such trends raise many questions regarding the fate of the existing fossil fuel utility infrastructure built over decades based on an implicit regulatory compact that the utilities would have an opportunity to recover and earn a reasonable return on their investment.

The foundations for utility regulation were stated in 1877 by the U.S. Supreme Court in Munn v. Illinois. The Court upheld the power of states to regulate rates charged by certain private companies in industries “clothed with the public interest” and thereby so critical to the functioning of society that government has the right to oversee the prices charged in order to assure that these essential services are provided to the public in a reasonable manner.² The principle undergirding the regulation of utility services that benefit the public interest eventually came to be known as the “Regulatory Compact” between regulators and privately owned utility companies.

This Compact encompasses an exchange of rights and obligations: the utility is granted an exclusive franchise to operate in a service area, and, in return, it has a duty to serve all customers within that service area. Further, the utility can charge rates that cover its reasonable costs of service and afford investors the opportunity to earn a reasonable rate of return on their investment. These rates are overseen by a regulatory agency that balances protecting ratepayers from monopoly pricing and protecting the investors’ right to earn a reasonable return.³

But what happens when regulators decide that all or a significant portion of a utility’s service should be terminated due to a change in law or policy? If the assets supporting this service are no longer considered “used and useful,” may the costs incurred to acquire them, at a time when such costs were considered reasonable and necessary to provide utility service, still be recovered from ratepayers? Does the Regulatory Compact or do other principles provide any affirmative protections for such a utility? This article presents a survey of applicable law, with a focus on California, and describes the rights of public utilities in the face of regulatory action to terminate or greatly curtail operations. It also explores whether commissions will recognize loss of enterprise value in addition to the more limited concept of compensation for such “stranded assets” in a changing regulatory environment.⁴

Summary of Conclusions

The Regulatory Compact alone does not confer fixed, enforceable rights on public utilities. However, it does, especially in California, reflect a highly generalized bargain conferring a reasonable opportunity to earn an authorized return and recover reasonable costs with the concomitant obligation to provide safe, reliable service at “reasonable rates.” These are concepts that have worked during ordinary times and even in unusual situations (although often accompanied by long and contentious regulatory litigation) such as the unexpected shutdown of huge nuclear power assets or high-profile utility accidents. But the question of how they might apply to regulatory action that essentially terminates a business is without precedent.

With those caveats, the following conclusions can be drawn.

1. The Regulatory Compact is more explicitly recognized in California than in other jurisdictions we examined.
2. However, even in California, the Regulatory Compact has “evolved” or been “modified” to fit particular circumstances but provides no fixed remedies or protections for either ratepayers or shareholders.
3. The Regulatory Compact has not been cited as the sole basis for a California Public Utilities Commission (CPUC or Commission) decision but is deemed consistent with the Public Utilities Code.
4. Where assets have ceased to be used and useful before their full cost has been recovered, the CPUC has allowed recovery of costs prudently incurred, although often delayed and with no or a limited return on equity. While the CPUC has balanced utility interests by providing a limited “reasonable” return on stranded assets, the CPUC nonetheless is not required to divide benefits equally or according to a set formula between the parties, and in fact retains substantial discretion. Certain scenario-specific factors may tilt the balance in one direction or another. For instance, in situations where the CPUC’s own policies have encouraged investor-owned utility (IOU) expenditures, the CPUC is more likely to permit shareholder recovery. Conversely, if the new regime being launched provides new opportunities for investment, the CPUC has been less willing to provide as much shareholder recovery. The Regulatory Compact thus reflects a general working understanding rather than a fixed contractual relationship.
5. Shareholders have not sought or been granted compensation for the diminished or eliminated “enterprise value” of a significant line of business or the utility as a whole.

Does the “Regulatory Compact” Protect Utility Rights?

Various federal courts,⁵ as well as state utility regulators and courts, have acknowledged the Regulatory Compact as an implicit agreement between regulated utilities and the public. Analysis of the Regulatory Compact and its associated rights and responsibilities on the part of utility providers, public agencies, and ratepayers has been more robust in California than in the federal courts and other states surveyed for this article. In general, while regulators have not conceded that the Regulatory Compact requires that they act in a particular way and state law can alter the rules of the relationship embodied in the Compact, the Compact remains foundational to state policy but is not a separate enforcement mechanism.

This section provides an overview of how state utility regulators and courts discuss, and how utilities may seek to utilize, the Regulatory Compact. A review of California law, primarily through CPUC decisions, is provided, followed by a survey of decisions in three other states with active utility oversight: New York, Massachusetts, and Illinois.⁶

California

In California, the Regulatory Compact is discussed as an implicit agreement between the regulated utilities and the CPUC. The utilities are granted a franchise to operate a service monopoly in a given area in exchange for accepting regulation by the CPUC, particularly with respect to the costs a utility may charge its ratepayers.⁷

Role of the Regulatory Compact in Rate Setting

The CPUC recently offered a “neutral definition”⁸ of “Regulatory Compact” in the context of electric utilities: “[T]he regulatory approach that grants individual companies exclusive franchises to provide power within a specific geographic area as long as their rates are regulated by state regulatory commissions based on the cost of providing service, including a reasonable return on investment.”⁹

Under the Regulatory Compact, the CPUC allows the utility to recover its just and reasonable costs and expenses, and provides it an opportunity (but no guarantee) of earning a reasonable rate of return on the utility’s rate base.¹⁰ “Just and reasonable” costs are those that are necessary to provide safe and reliable service to the utility’s customers.¹¹ However, the obligation to conduct safe operations and practices is absolute and not tied to the rates approved by the CPUC.¹² The utility’s responsibility in this cost-of-service framework is to establish that its proposed costs are necessary and that it has prudently examined alternatives to ensure that the rate proposal is the most cost-effective.

The CPUC views the Regulatory Compact as being embodied in California Public Utilities Code section 451¹³ and general rate case proceedings.¹⁴ The general rate case is a proceeding by which utility rates are set, and it is governed by section 451, which requires all rates and utility rules to be “just and reasonable” and requires public utilities to “maintain such adequate, efficient, just, and reasonable service, instrumentalities, equipment, and facilities . . . as are necessary to promote the safety, health, comfort, and convenience of . . . the public.”¹⁵

In determining what rates are just and reasonable, the CPUC balances the interests of both ratepayers and the utility’s investors; each side has both rights and obligations.¹⁶ Ratepayers accept the loss of choice in a utility provider in exchange for protection from monopoly pricing. They accept the duty to pay rates that fairly compensate the utility for its costs but that are not excessive due to the utility’s monopoly (or near-monopoly) position. In return for receiving a monopoly, the utility accepts the obligation to serve all customers in its franchise territory and charge cost-based rates. The utility is entitled to recover its costs to provide service (as long as they are considered “prudent”) plus the opportunity to earn a fair return on its capital investments. The allowance of a return on investment is based on an understanding that utilities will not be able to attract investor capital unless the investors can earn what they regard as a reasonable return on their investment.¹⁷

Determination of a “Fair Rate of Return”

In determining what constitutes a “fair rate of return,” the CPUC applies the legal standards set forth in Bluefield Water Works & Improvement Co. v. Public Service Commission of the State of Virginia (Bluefield) and Federal Power Commission v. Hope Natural Gas Company (Hope).¹⁸

The CPUC relies on Bluefield for the proposition that a fair rate of return

should be equal to that generally being made at the same time and in the same general part of the country on investments in other business undertakings attended by corresponding risks and uncertainties. That return should also be reasonably sufficient to ensure confidence in the financial soundness of the utility, and adequate, under efficient management, to maintain and support its credit and to enable it to raise the money necessary for the proper discharge of its public duties.¹⁹

The Hope decision builds on Bluefield, holding that the investors’ rate of return should be sufficient to cover the capital costs of the utility’s business, including debt service and equity dividends, and should be commensurate with the return available on other investments of comparable risk.²⁰ In applying these guidelines from Bluefield and Hope for setting a fair rate of return, the Commission also has a duty to protect ratepayers from unreasonable risks, including “imprudent management.”²¹ Further, Hope dictates that there is no single formula that a commission must use in setting the investors’ rate of return; as long as the principles set forth in Bluefield and Hope are followed, resulting in just and reasonable rates for the utility’s customers, a commission will have acted lawfully.²²

A recent CPUC decision set the test year 2020 cost of capital for the major energy utilities—Southern California Edison (SCE), Pacific Gas and Electric Company (PG&E), San Diego Gas & Electric (SDG&E), and Southern California Gas Company (SoCalGas)—in a consolidated proceeding.²³ The CPUC detailed the process of reaching a utility’s return on equity (ROE) in accordance with Bluefield and Hope. In order to determine the ROE for similar companies, as required by Bluefield, the CPUC defines “proxy groups” as companies with characteristics similar to the utility.²⁴ Next, financial models are applied to the proxy group to estimate the ROE.²⁵ Finally, the CPUC also considers “additional risk factors” before determining the ROE.²⁶ These additional risk factors include the following:

• Financial Risk: This risk is tied to the utility’s capital structure, including the debt-to-equity ratio.
• Business Risk: This risk “pertains to new uncertainties resulting from competition and the economy. An increase in business risk can be caused by a variety of events that include capital investments, electric procurement, and catastrophic events. Each of these business risks overlap into financial and regulatory risk.”²⁷ Wildfire risk is considered a business risk.²⁸
• Regulatory Risk: This risk “pertains to new risks that investors may face from future regulatory actions.”²⁹

One aspect of regulatory risk raised by the utilities in this cost-of-capital proceeding was the risk that the authorized ROE would not compensate the utility for the level of risk that investors must assume, particularly at a time when above-average capital investments are being required. The CPUC addressed this concern by stating that because the financial modeling includes the impact of increasing capital investments on similarly situated proxy companies, and the ROE is set at a level meeting the reasonableness tests in Bluefield and Hope, there is little risk of the authorized ROE being inadequate.³⁰

Additional regulatory risks identified by the parties in this proceeding included changes in government laws and regulations as well as municipalization of utilities. According to the CPUC, “to the extent that investors expect government laws and regulations to change and municipalization of regulated utilities to occur, such expectations should already be captured in the financial modeling results.”³¹

Disbursement of Utility Gains from the Sale of Assets and Third-Party Recoveries

In addition to determining how rates are set, the CPUC has considered the Regulatory Compact in the context of who should receive gains from the sale of utility assets. In a CPUC decision regarding the allocation of gains from the sale of utility assets, the Commission decided that consideration of which party bears the financial risk of an investment should determine how to allocate gains and losses upon sale.³² The CPUC determined that for depreciable assets (e.g., buildings and equipment), 100 percent of gains should go to ratepayers because they have financed the asset. For nondepreciable assets (e.g., land and water rights), gains are allocated 50 percent to ratepayers and 50 percent to shareholders. This split serves to compensate ratepayers for bearing most of the risk of purchasing such property and “as an incentive to utility management to manage its assets wisely.”³³ Ultimately, this method of assigning gains upon sale of utility assets reflects the Regulatory Compact that utilities enter into: “[b]ecause ratepayers fully compensate utilities for costs related to land, improvements and other tangible and intangible assets dedicated to utility use, ratepayers should in most cases receive an equal share of the gain (and the loss) in most routine asset sales.”³⁴

Similarly, the CPUC addressed the distribution of third-party recoveries related to the shutdown of San Onofre Nuclear Generating Station (SONGS). The utilities, SCE and SDG&E, had submitted claims on their insurance policies to recover a portion of the costs to purchase power lost from SONGS.³⁵ Additionally, there was ongoing litigation against Mitsubishi Heavy Industries relating to the failure of SONGS Units 2 and 3.³⁶ The utilities and four other parties³⁷ reached a settlement agreement resolving the issue of rate recovery as it related to the shutdown of SONGS. As to the distribution of third-party recoveries from insurance claims and litigation against Mitsubishi, the settlement agreement provided that the majority of insurance recoveries would go to ratepayers, who had paid for the insurance, and litigation recoveries were to be shared equally between ratepayers and investors.³⁸ In approving this settlement agreement, the CPUC determined that this allocation was “a reasonable policy outcome” in its consideration of both ratepayers and investors and the level of risk assumed by each.³⁹

CPUC Decisions on Evolution of the Regulatory Compact

The CPUC recently addressed the Regulatory Compact in the context of “a number of extraordinary catastrophic events involving California’s regulated energy utilities,” including the 2010 San Bruno pipeline explosion and major wildfires throughout the state.⁴⁰ The CPUC stated that its role is to independently determine the “just and reasonable” costs that should be passed on to ratepayers, not merely to approve the costs submitted by the utilities in such extraordinary events.⁴¹ Even in the face of unexpected costs borne by the utilities, the CPUC and the legislature have made it clear that the CPUC must balance the interests of both ratepayers and shareholders.

When PG&E was faced with an investigation into its liabilities due to the 2017 and 2018 wildfires in its service territory, PG&E reached a settlement with the CPUC’s Safety and Enforcement Division, the CPUC’s Office of the Safety Advocate, and the Coalition of California Utility Employees to resolve all issues concerning penalties and other remedies for PG&E’s role in the wildfires.⁴² The settlement included an agreed-upon amount of costs that PG&E would not be allowed to recover from ratepayers; in approving the settlement, the CPUC modified the settlement agreement and increased the disallowance, thereby reducing the amount that could be recovered from ratepayers by $198 million. PG&E argued that the modifications, inter alia, undermined the Regulatory Compact. The CPUC responded that it has a duty to independently review, and modify where appropriate, any settlement to ensure that it is in the public interest.⁴³ The CPUC does not consider itself constrained by the Regulatory Compact in the event of extraordinary circumstances and will balance ratepayer and investor interests while protecting the public interest. Similarly, although utilities have argued that the Regulatory Compact affirmatively protected them from competition, the Supreme Court of California has said that the public interest tempers the Regulatory Compact: “The policy as declared by the statute and applied by the Commission has never gone to the length of guaranteeing monopoly in all cases, but has at all times deemed the public interest as of paramount importance.”⁴⁴

In response to the unprecedented wildfires of recent years, the state legislature enacted Assembly Bill (A.B.) 1054 in July 2019.⁴⁵ A.B. 1054 creates the Wildfire Liability Fund (the Fund) and allows participating utilities to recover from the Fund just and reasonable costs and expenses of a covered wildfire. The utilities are entitled to a “presumption of reasonableness,” and thus recovery of costs, if they have obtained a safety certification (issued annually by the CPUC) that was valid when the wildfire ignited. But this presumption can be challenged by a party that raises “serious doubt” as to the reasonableness of the utility’s conduct. If so challenged, the CPUC must decide if the utility’s conduct related to the wildfire ignition was reasonable, i.e., if the conduct was consistent with actions that a reasonable utility would have undertaken in good faith under similar circumstances, at the relevant point in time, and based on the information available to the electrical corporation at the time.⁴⁶ While A.B. 1054 establishes a new Fund and a new procedure for utilities to recover costs associated with catastrophic wildfires, ultimately cost recovery (and therefore charges to ratepayers) is governed by the CPUC’s determination that only “reasonable costs” may be passed on to ratepayers.

An earlier period of utility regulation that involved a shift in the traditional approach to the Regulatory Compact was the electricity industry restructuring of the mid-1990s. In its order opening the rulemaking that would eventually restructure California’s electric industry, the CPUC unveiled a proposed strategy that would involve a shift in price regulation from cost-of-service to performance-based regulation and would also fundamentally alter the Regulatory Compact by introducing competition into the electricity market.⁴⁷ The changes in California followed closely the federal Energy Policy Act of 1992, which sought to increase competition and rely on market mechanisms in the electricity industry.⁴⁸ The CPUC acknowledged that circumstances around the electric industry were changing and that those changes were likely to accelerate.

California’s regulatory compact must also change if we expect the state’s consumers and California’s economy to continue to benefit from this vital industry. The compact’s tenets were never intended to be, nor have they remained, fixed. Rather they have rightly evolved to correspond to the changes any industry and economy inevitably undergo. With this proposed strategy, that evolution continues.⁴⁹

As electric restructuring was completed, the CPUC acknowledged that “changing circumstances” and the introduction of competition to the industry had rendered certain utility assets uneconomic to maintain. The CPUC recognized that utilities had incurred the costs for those assets under the previous regulatory structure and determined that a balancing of interests meant that the utility could recover those costs, but at a lower rate of return: “We have been careful to provide the utility with opportunities to profit in the competitive market. It is fair to expect shareholders to receive a lower rate of return in exchange for these future opportunities.”⁵⁰ This “evolution” of the Regulatory Compact introduced competition and changed the investors’ rate of return on certain assets, but it maintained the spirit of balancing the interests of consumers (in competition and lower electric prices) with those of shareholders (in expanded opportunities to earn a return).

The result of electric restructuring was that the incumbent IOUs (PG&E, SCE, and SDG&E), which were traditionally vertically integrated companies from electricity generation through retail sales, divested most of their generation assets (except for nuclear and hydro).⁵¹ The “stranded” costs associated with the sale of their generation assets were allowed to be recovered through a competitive transition charge assessed to ratepayers, but the IOUs were prohibited from supplying their own generation without routing such generation through the new market mechanisms.

The electric restructuring of the mid- to late 1990s provides some precedent for statutory and regulatory changes that ordered the incumbent utilities out of a portion of their historical utility functions, wholesale generation, while allowing them to continue their operations in transmission and distribution. We are unaware of any of the IOUs raising claims for compensation for “enterprise loss” after these changes to the historic breadth of their business. However, as evidence that the market saw potential deregulation as a risk to enterprise values, prior to the passage of the deregulation legislation that allowed IOUs to recover stranded costs, utility stocks plummeted by 20 percent on the uncertainty of what deregulation would mean to their enterprise values.⁵² Only after the legislation included provisions for the recovery of stranded assets did the IOU market values return.⁵³

Summary of the Regulatory Compact in California

In California, the Regulatory Compact has been discussed as the theory underlying the resulting statutory and regulatory framework: the granting of a license to operate in exchange for accepting a duty to serve, and the ability of utilities to operate a monopoly service by charging regulated rates designed to balance the interests of both ratepayers and shareholders. These principles are embodied in the state Public Utilities Code and govern how utility rates are set. The Regulatory Compact does not, however, seem to otherwise constrain the CPUC or legislature from enacting changes that may alter the Compact, such as those adopted in restructuring the electric industry.

Whether the CPUC would have the same authority to alter the Compact in situations not involving a direct statutory mandate, however, is questionable and remains to be seen. The CPUC has said that the Regulatory Compact was never meant to remain static, and, within certain limits provided by statute (e.g., section 451 of the California Public Utilities Code), the CPUC considers itself empowered to change the nature of the relationship between regulators and utilities in order to effectuate broad public policy objectives.

New York

The Regulatory Compact has historically been acknowledged by the New York courts and the New York Public Services Commission (NYPSC); however, the recent trend in the NYPSC indicates a possible repudiation of the Compact. The guiding principle in New York State court analysis is whether the end result is “just and reasonable—and fair as between the utilities’ customers and their stockholders,” the determination of which is committed to the discretion of the NYPSC.⁵⁴ The courts will only intervene if the NYPSC’s decision is arbitrary and capricious.⁵⁵

For its part, the NYPSC has described the Regulatory Compact as a “quasicontractual agreement”⁵⁶ and as “the axiomatic precept that a utility is entitled to recover from ratepayers prudently incurred costs.”⁵⁷ Historically, the NYPSC has implicitly acknowledged the existence of the Regulatory Compact, rejecting the New York State Department of Law’s argument that “there is no established regulatory compact that assures investors the full recovery of costs reasonably expended in the provision of utility service” and quoting a former NYPSC chairman who described the “essential basis of public utility regulation” as “an implicit bargain between consumers and investors that, in exchange for a monopoly franchise, the company accepts the strict legal obligation to serve all customers on reasonable terms.”⁵⁸

Reflecting the two ideas in tension—that the Compact represents an implicit agreement but that the Compact does not require regulators to act in particular ways—New York has adopted a state law that its courts have interpreted as empowering the NYPSC to deny utilities recovery of even prudent costs.⁵⁹ This idea is further reflected in principles adopted by the NYPSC in the mid-1990s out of its examination of competitive opportunities for electric service, including that “emphasis on performance-based regulation should continue” and that “[u]tilities should have a reasonable opportunity to recover prudent and verifiable expenditures and commitments made pursuant to their legal obligations.”⁶⁰

However, in more recent decisions, it appears that the NYPSC staff and administrative law judges (ALJs) may be moving away from the Compact. In a 2008 decision, the recorded position of the NYPSC staff appears to be that the Regulatory Compact does not exist outside of the state’s Public Service Law.⁶¹ In that decision, the ALJ recommended disapproval of petitioner Iberdrola’s acquisition of two incumbent utilities, NYSEG and RG&E, on the grounds that the proposed transaction did not satisfy the state’s public interest test. While Iberdrola argued that the Regulatory Compact would protect ratepayers from improper transactions between the regulated utilities and unregulated affiliates, staff feared that the proposed corporate structure could not be sufficiently regulated to protect consumers without additional safeguards. A 2012 decision goes even further, with the ALJ denying the existence of a compact outside the Public Service Law and stating that such a position has been supported by the state’s courts.⁶²

Massachusetts

While the Massachusetts Department of Public Utilities (MDPU) has not mentioned the Regulatory Compact in an order since 1995, the MDPU has recognized the Compact as “implicit in the public utility laws that have developed in the commonwealth.”⁶³ The MDPU further described “the service obligation, regulatory price control, and the support obligation” as “the essential components that underlie the regulatory compact which public law and policy have created between consumers and utility investors.”⁶⁴ Against this backdrop, the MDPU described its role as ensuring that “the purposes of the regulatory compact . . . are achieved.”⁶⁵

More recently, however, the MDPU has adopted an approach to the Regulatory Compact more analogous to the emerging view of the NYPSC—that is, that the Regulatory Compact may not exist, at least not in a way that would require compensation in connection with stranded assets.⁶⁶ In this particular order, the MDPU’s reasoning appeared to turn on whether utilities in Massachusetts had exclusive franchises; and if not, “it is not clear whether they would be legally due compensation for any part of a non-exclusive franchise in the event of electric industry restructuring.”⁶⁷ Despite taking this position, the MDPU expressed that “responsible policy must provide” for recovery of “net, non-mitigatable stranded costs during the transition period,” which suggests alignment with the idea that regulators may still recognize the Regulatory Compact as an underlying theory of utility regulation, although not determinative of specific actions or obligations on their part.⁶⁸

Illinois

Unlike the NYPSC and MDPU, the Illinois Commerce Commission (ICC) seems to have continued to acknowledge the existence of the Regulatory Compact.⁶⁹ In a 2014 order, the ICC mentioned in passing that, “[i]n the context of a power generation industry increasingly devoid of regulatory compacts because States like Illinois have legislated greater reliance on competitive forces, Staff believes the Commission need not ensure the profitability of suppliers in either the short-run or the long-run.”⁷⁰ Despite this view expressed by the ICC staff, as recently as 2018, the ICC has indicated that the Regulatory Compact continues to operate in Illinois, albeit largely as codified by the state legislature in the Public Utilities Act.⁷¹

How the Regulatory Compact Doctrine Informs Stranded Asset Questions in California

Overview of Stranded Assets in California

In California, the Regulatory Compact informs a related doctrine that allows utilities to recover costs of “stranded assets” that are no longer “used or useful,” especially when these assets are made noneconomic as the result of a regulatory change or CPUC action. Several CPUC decisions have addressed the circumstances under which utilities may include in their rate base facilities that are no longer operating or have become uneconomic due to market pressures. As demonstrated below, the CPUC has assumed considerable discretion in determining when costs for these stranded assets may be recovered, the amount of costs utilities may be entitled to, and the method by which recovery is made. While the CPUC has balanced utility interests by providing a limited “reasonable” return on stranded assets, the CPUC nonetheless is not bound in any strict transactional sense to dividing benefits equally or through a preexisting formula between the parties. In this way, the Regulatory Compact again is more of a working understanding than a binding contractual relationship.

As a general rule, an asset becomes stranded when it is no longer “used or useful.” According to the CPUC, determining whether an asset is used or useful involves a consideration of whether the asset is actually serving customers and whether the utility acted prudently in constructing the asset to begin with.

The used and useful standard has a twofold meaning. At the preliminary level it implies that the facility is built and provides service to customers. In addition the principle requires an examination of the utility’s prudence in deciding to construct or purchase the utility plant. In other words according to the used and useful standard to be included in the rate base the new asset must be required and operate in an effective and efficient manner.⁷²

In California, the CPUC has held that “a utility is not allowed to recover the costs of plant (asset) which is not used and useful.”⁷³ Likewise, when the CPUC establishes rates for public utilities, the Public Utilities Code authorizes but does not require the CPUC to “eliminate consideration of the value of any portion of any electric, gas, heat, or water generation or production facility which, after having been placed in service, remains out of service for nine or more consecutive months, and may disallow any expenses related to that facility.”⁷⁴ However, the CPUC has emphasized “the necessity of examining each case on an individual basis,” and it exercises considerable discretion when determining an equitable distribution of cost sharing between ratepayers and utilities’ shareholders for stranded assets.⁷⁵

Exception for Periods of Uncertainty

The CPUC has developed some exceptions to the general rule that utilities may not recover costs from stranded assets, and these exceptions reflect the principles of the Regulatory Compact. However, the CPUC is not bound by an explicit formula when allocating costs under these exceptions. Generally, “when assets are retired prematurely, for reasons other than imprudence, assets would be excluded from the rate base, which means the utility would not be permitted to earn a rate of return on assets, but the remaining book value of the asset will be amortized in customer rates.”⁷⁶ More specifically, the CPUC has carved out an exception for projects that are prudently pursued and abandoned during a period of “great uncertainty.”⁷⁷ This exception “is the product of the period of dramatic and unanticipated change, initiated most notably for utility planners by the oil embargo of 1973,” which “was characterized by great uncertainty in the energy industry, both as to demand growth and availability of supply.”⁷⁸ During these periods of uncertainty, the CPUC has determined that “the ratepayer should participate in the increased risk confronting the utility,” though how this is achieved varies on a case-by-case basis.⁷⁹ As discussed in greater detail below, this principle has been relied on more recently during the electrical industry restructuring of the late 1990s and the decommissioning of elements of the SONGS.

One 2011 CPUC decision demonstrates the significant latitude the CPUC is given when determining the costs that may be recovered from stranded assets, including allowing utilities to earn a rate of return on assets that are no longer used and useful. In D.11-05-018, the CPUC considered whether PG&E could recover a rate of return on the undepreciated plant balance associated with “stranded” electric meters that had been replaced by more efficient “SmartMeters.”⁸⁰ The CPUC ultimately decided to “grant rate of return treatment for the retired meters, despite the fact that they are no longer used and useful,” emphasizing the fact that the new meters would be more “cost-effective for customers” and that the CPUC had specifically encouraged deployment of these meters.⁸¹ In its reasoning, the CPUC highlighted that “[it did] not wish to discourage utilities from replacing their existing assets with new technologies under these circumstances, especially when [it has] found the replacement to be cost-effective for customers.”⁸² This decision does not specifically guarantee utilities a rate of return for stranded assets that are made uneconomic by CPUC action or more cost-efficient technology; however, the CPUC did indicate that “[i]n the cases where return on rate base was denied, the impetus for the non-used and useful status was utility actions rather than Commission desires or actions.”⁸³

Stranded Assets During Electric Reorganization

In the late 1990s, the electric power industry was restructured to allow competition in the supply of electric power. Because electrical utilities had previously made investments and incurred obligations under a framework where they were required to serve their entire service territories’ generation needs, many of these assets became uneconomic or stranded under this reorganization. Under the legislation that implemented the industry’s restructuring, it was determined that utility customers should pay a “competition transition charge” to the shareholder-owned public utilities in order to meet their prior obligations.

In D.95-12-063, the CPUC assessed the different proposed policies regarding the restructuring of California’s electric services industry and determined that recovery for remaining net investment should be at a reduced rate of return, after recognizing that “some utility plants will no longer be used and useful in the future restructured energy marketplace.”⁸⁴ The CPUC concluded that it would “adopt 90% of the embedded cost of debt as a reasonable rate of return on the equity portion of the net book value” of the stranded costs resulting from this change and would “set the return on the debt portion of net book value at the embedded cost of debt.”⁸⁵ In “allowing the recovery of generation plant–related transition costs,” the CPUC has admitted that it has, “in effect, allowed the utilities to recover costs of plants that may no longer be used and useful in the new competitive marketplace.”⁸⁶

Stranded Assets in Connection with Nuclear Facilities

The issue of rate recovery for stranded assets has also arisen due to the premature SONGS shutdown. Here, the CPUC has authorized reductions in return on equity for prematurely decommissioned nuclear facilities through the approval of settlement agreements. For example, in D.92-08-036, the CPUC adopted a settlement between SCE, SDG&E, and the Division of Ratepayer Advocates that allowed a 48-month amortization of remaining investment in SONGS Unit 1 during its remaining period of operation; and following its shutdown, the remaining unamortized investment was allowed to earn a rate of return, which, after taxes, was fixed at the then-current authorized embedded cost of debt.⁸⁷

More recently, the CPUC has addressed stranded costs arising from the shutdown of SONGS Units 2 and 3, following a steam generator tube leak in 2012. In D.14-11-040, the CPUC approved a settlement agreement between several parties, including SCE and SDG&E, requiring ratepayers to pay approximately $3.3 billion in costs over 10 years for the newly decommissioned SONGS units, which included recovery of the undepreciated net investment in SONGS assets.⁸⁸ However, as the CPUC noted, “instead of the usual authorized rate of return, the settlement reduces shareholders [sic] return on SONGS investments to less than 3%. The effect is ratepayers save approximately $420 million over the ten-year depreciation.”⁸⁹ In D.18-07-037, following revelations of improper ex parte communications between SCE and the CPUC president regarding the first settlement, the CPUC considered a new settlement agreement, which modified portions of the 2014 settlement agreement described above.⁹⁰ This revised agreement required the utilities to “cease collecting in rates the revenue requirement associated with all costs and amounts authorized to be recovered under the existing 2014 Agreement” once the combined remaining balance of the SONGS regulatory assets equaled a certain amount.⁹¹ In approving the settlement agreement, the CPUC once again described its wide latitude in determining cost recovery for stranded assets, stressing the avoidance of litigation and reducing economic burdens on ratepayers.

We also note that the Commission decisions vary widely as to what investment cost recovery is or is not authorized once a plant is no longer used and useful. The proposed settlement agreement with the proposed modification reflects a reasonable resolution to this long, complex, and controversial proceeding. A resolution that avoids continued litigation and provides a significant economic benefit to ratepayers is in the public interest.⁹²

Comparative Analysis: Federal Natural Gas Deregulation

The issue of stranded assets also arose at the federal level during the deregulation of the natural gas industry, offering a useful comparison to the way CPUC handled stranded assets in light of major regulatory sea changes. Unlike the CPUC stranded assets decisions discussed above, here the allocation of stranded assets was determined, at least in principle, by the role responsible parties (i.e., utilities and customers) played in causing certain assets to become uneconomic.

Beginning in the mid-1980s and continuing through the 1990s, the Federal Energy Regulatory Commission (FERC) issued a series of orders to establish a competitive natural gas market by voiding the minimum bills that gas customers were required to pay even when they did not purchase gas, requiring pipelines to open their lines to competing gas companies, and unbundling that cost of gas services.⁹³ As a result of this deregulation, pipelines that had traditionally entered into expensive and long-term “take-or-pay” contracts found that these assets were now “stranded” in the new, competitive market.⁹⁴ Initially, FERC imposed the cost of the natural gas industry’s inefficient market practices, including the costs of the stranded take-or-pay contracts, on the gas pipelines and refused to allow recovery from customers.⁹⁵ Ultimately, a series of decisions from the U.S. Court of Appeals for the District of Columbia criticized FERC’s decision to require pipelines to shoulder the entire cost of stranded take-or-pay contracts and vacated prior FERC orders that failed to address these issues.⁹⁶

In response to these decisions, FERC issued Order No. 500, which allocated the costs of the take-or-pay contracts between pipelines and customers under a theory that all parties bore some responsibility for the structure of these contracts in the first place. In Order No. 500, FERC stated:

The causes of the pipelines’ take-or-pay problems are many and complex. It is undoubtedly true that some pipelines independently entered into contracts incorporating both high prices and high take-or-pay levels. At the same time, pipelines entered into contracts, which were based on the anticipated demands of their customers, and whose terms reflected those which producers were able to obtain under the then prevailing market conditions. . . . The Commission recognizes that it is difficult to assign blame for the pipeline industry’s take-or-pay problems. In brief, no one segment of the natural gas industry or particular circumstance appears wholly responsible for the pipelines’ excess inventories of gas. As a result, all segments should shoulder some of the burden of resolving the problem.⁹⁷

Under this principle—that all parties bore some responsibility for the stranded assets—FERC adopted a flexible cost-sharing model. Pipelines shouldered 25 percent to 50 percent of the costs of the stranded assets; however, they could bill an equal amount, from 25 percent to 50 percent, to their customers in a fixed charge.⁹⁸ Any of the remaining costs could then be included in the ordinary rate, provided customers would be willing to buy this expensive gas.

Determining Recovery in Stranded Assets Cases

In both the electric reorganization and nuclear decommissioning decisions, utilities were able to recover investment costs of stranded assets while also earning a reduced rate of return, as determined by the CPUC. In D.95-12-063, where the CPUC examined the different proposed policies for the reorganization of the state’s electric power industry, the CPUC stated the principles that justified its decision to allow utilities to recover costs of assets that were no longer used or useful, while also applying a lower rate of return on these “transition costs.”⁹⁹ First, the CPUC stated, “ratepayers should benefit” from the allocation of costs, and “it would be inappropriate to require ratepayers to bear the same costs they would have borne in the absence” of the regulatory changes that made these assets uneconomic.¹⁰⁰ Second, “shareholders should recover somewhat lower revenues as transition costs” than they otherwise would.¹⁰¹ The CPUC explained that although utilities are typically given the opportunity to recover “the amount of the original construction cost of a plant over the plant’s expected useful life, plus a reasonable return tied to risk,” allowing this level of recovery in the context of stranded assets could create adverse incentives for utilities.¹⁰² For example, if utilities were entitled to the full reasonable rate of return on stranded assets, there would be no incentive for utilities to minimize these costs.

Finally, in explaining why electric utilities were entitled to stranded costs with a reduced rate of return, the CPUC explicitly rejected the argument that the Regulatory Compact entitled utilities to “full revenue recovery” because the underlying costs were incurred under a regulated industry structure as compared to a competitive industry structure.

We disagree with this position. Changing circumstances have conspired to render some plants and other obligations uneconomic. This decision, as a response to those circumstances, introduces a competitive market structure to the electric industry. We recognize that utilities have incurred costs under the regulated industry structure that they will not be able to recover in a competitive market, and we have determined not to require utilities to bear those costs. However, we do not conclude that ratepayers should be required to pay utilities all of the revenues they would have recovered in the absence of this reform effort. We have been careful to provide the utility with opportunities to profit in the competitive market. It is fair to expect shareholders to receive a lower rate of return in exchange for these future opportunities.¹⁰³

Although the CPUC affirmed that ratepayers were not required to produce the same revenues under the new regulatory structure, the CPUC was nevertheless “required” to create “a rate structure the total impact of which provides the utilities with the opportunity to earn a fair return on their investment.”¹⁰⁴

Although there is no fixed formula for determining a reasonable rate of return in these cases, the CPUC generally determines whether the rate “reflects the reduced risk associated with these [stranded] assets.”¹⁰⁵ In the case of electric industry restructuring, reducing the rate of return to 10 percent below the long-term cost of debt reflected the reduced risk in the stranded assets because the accelerated return of their net book value would be facilitated through a transition cost recovery regime.¹⁰⁶ In the nuclear decommissioning cases, the CPUC was not setting a rate of return for stranded assets outright, but rather approving settlement agreements that distributed these costs. With respect to SONGS 1, the CPUC concluded that “[s]etting the return for the post-shutdown amortization at the utilities’ embedded cost of debt seems logical and appropriate,” recognizing that shareholders and ratepayers both had an “interest in avoiding the extreme adverse outcome” should the issues in dispute be decided on their merits.¹⁰⁷

Apart from this general principle that the rate of return for stranded assets, if recoverable in the first place, should reflect the reduced risk associated with the assets, there is no rigid requirement as to how much, or how little, a utility is able to recover. To the extent that the stranded assets doctrine operates as an outgrowth or corollary to the Regulatory Compact, these decisions support the conclusion that utilities have reasonable grounds to recover prudently incurred costs when assets become uneconomic due to outside forces. However, utilities are not entitled to any specific form of recovery.

Conclusion

Even in the face of regulation that would fundamentally alter a regulated utility’s business, the Regulatory Compact alone would not likely confer fixed, enforceable rights to protect the utility. If the regulator’s own policies encouraged past utility expenditures, the regulator is more likely to permit shareholder recovery at least for stranded assets pursuant to the general framework of the Regulatory Compact. Conversely, if the new regime being launched provides new opportunities for utility investment, the regulator would not likely see the Regulatory Compact as an impediment when balancing ratepayer and investor interests while protecting the public interest.

Reliance on the Regulatory Compact to recover enterprise value in the case of a mandated termination of utility service may be problematic. The Compact has most often been cited as a guide for balancing the interests of ratepayers and shareholders in situations of changed operational circumstances, including regulatory innovation. Thus, if regulators seek only to curtail or limit service, both the utility and affected customers may be able to invoke the Regulatory Compact in support of reasonable rates and equitable cost recovery. But if a regulatory directive terminates utility service altogether, the utility may have to look at other doctrines for compensation beyond recovery of its undepreciated assets. These could include protections offered by state administrative procedure acts if applicable, takings claims, or denial of regulatory due process.

Endnotes

1. See, e.g., Cal. Pub. Util. Code § 454.53(a) (establishing a policy of 100 percent renewable electricity by 2045); Colo. Rev. Stat. Ann. § 40-2-125.5 (West) (setting a target of 100 percent electricity from clean energy resources); Nat’l Conf. of State Legislatures, State Renewable Portfolio Standards and Goals (Jan. 4, 2021), https://www.ncsl.org/research/energy/renewable-portfolio-standards.aspx (providing a state-by-state overview of Renewable Portfolio Standards).

2. Munn v. Illinois, 94 U.S. 113, 126 (1877):

Property does become clothed with a public interest when used in a manner to make it of public consequence, and affect the community at large. When, therefore, one devotes his property to a use in which the public has an interest, he, in effect, grants to the public an interest in that use, and must submit to be controlled by the public for the common good, to the extent of the interest he has thus created.

3. Fed. Power Comm’n v. Hope Nat. Gas Co., 320 U.S. 591, 603 (1944) (“The rate-making process . . . involves a balancing of the investor and the consumer interests.”); see also id. at 605 (upholding the rates allowed by the Commission as “just and reasonable” where they “enabled the company to operate successfully, to maintain its financial integrity, to attract capital, and to compensate its investors for the risks assumed”). In a number of sectors, competition has arisen that has allowed regulatory commissions to greatly reduce or altogether eliminate the supervision of rates. See, e.g., Market-Based Rates for Wholesale Sales of Electric Energy, Capacity, and Ancillary Services by Public Utilities, 119 FERC ¶ 61,295 (June 21, 2007) (Order No. 697) (granting utilities market-based rate authorization as long as they can demonstrate they lack horizontal and vertical market power). However, even in these cases, utility commissions have retained a great deal of regulatory oversight. See, e.g., Fed. Commc’ns Comm’n, Enforcement Overview (Apr. 2020), https://www.fcc.gov/sites/default/files/public_enforcement_overview.pdf (describing the areas still regulated by the Federal Communications Commission (FCC), including consumer protection, market disputes, etc., and enforcement authority).

4. The scope of this article includes a discussion of the Regulatory Compact primarily through the lens of state law, court decisions, and public utility commission decisions, for California and a selection of other states known for active utility oversight. While there is some federal jurisdiction over utilities in interstate commerce, the majority of utility regulation is at the state level, and thus the primary focus of this article is on the states.

5. See, e.g., Transmission Access Pol’y Study Grp. v. FERC, 225 F.3d 667, 699–700 (D.C. Cir. 2000), aff’d sub nom., New York v. FERC, 535 U.S. 1 (2002) (noting that utility companies “rel[ied] on the ‘regulatory compact’” when investing in power transmission infrastructure); Allegheny Energy v. DQE, Inc., 74 F. Supp. 2d 482 (W.D. Pa. 1999) (describing the Regulatory Compact as utility companies’ “investments in generation assets, in return for the assurance . . . that they would have an opportunity to recover such costs under regulation in the future”). Federal case law discussing the Regulatory Compact is relatively sparse, likely due to the majority of utility regulation falling under the states’ police powers.

6. We surveyed three state PUCs in other regions (Illinois, New York, and Massachusetts) that have active utility oversight to provide a sample of how the Regulatory Compact has been applied in other parts of the United States.

7. See Hartwell Corp. v. Superior Ct., 27 Cal. 4th 256, 281–82 (2002) (“Endowed by the state with a legally enforceable monopoly and authorized by the state to charge rates that guarantee it a reasonable rate of return, a public utility, in turn, must comply with the comprehensive regulation of its rates, services, and facilities as specified in the Public Utilities Code.” (citations omitted)).

8. D.19-05-020, Decision on Test Year 2018 General Rate Case for S. Cal. Edison Co., at *8 (Cal. Pub. Utils. Comm’n May 16, 2019).

9. Id.

10. Id. at *9. Rate base is the value of a utility’s property used in providing service on which the utility is permitted to earn a specified rate of return.

11. Id. at *10.

12. D.15-04-023, Order Instituting Investigation on the Commission’s Own Motion into the Operations and Practices of PG&E to Determine Violations in Connection with the San Bruno Explosion and Fire on Sept. 9, 2010 at *16 (Cal. Pub. Utils. Comm’n Apr. 9, 2015) (hereinafter “PG&E San Bruno OII”) (“To be clear, public utilities are not permitted to adopt anything other than safe operations and practices, even if they believe that rates approved by the Commission are inadequate.”).

13. See Cal. Pub. Util. Code § 451 and its use of “just and reasonable” as an all-purpose standard.

All charges demanded or received by any public utility, or by any two or more public utilities, for any product or commodity furnished or to be furnished or any service rendered or to be rendered shall be just and reasonable. Every unjust or unreasonable charge demanded or received for such product or commodity or service is unlawful.

Every public utility shall furnish and maintain such adequate, efficient, just, and reasonable service, instrumentalities, equipment, and facilities, including telephone facilities, as defined in Section 54.1 of the Civil Code, as are necessary to promote the safety, health, comfort, and convenience of its patrons, employees, and the public.

All rules made by public utility affecting or pertaining to its charges or service to the public shall be just and reasonable.

See also PG&E San Bruno OII at 16.

14. D.20-01-002, Order Instituting Rulemaking to Develop a Risk-Based Decision-Making Framework to Evaluate Safety and Reliability Improvements and Revise the General Rate Case Plan for Energy Utilities, at *6 (Cal. Pub. Utils. Comm’n Jan. 16, 2020) [hereinafter GRC OIR].

15. Cal. Pub. Util. Code § 451.

16. GRC OIR, supra note 14, at *6.

17. Id. at *7.

18. Bluefield Water Works & Improvement Co. v. Public Service Commission of the State of Virginia (Bluefield), 262 U.S. 679 (1923); Federal Power Commission v. Hope Natural Gas Co. (Hope), 320 U.S. 591 (1944); D.19-12-056, Application of S. Cal. Edison Co. (U338e) for Authority to Establish Its Authorized Cost of Capital for Utility Operations for 2020 and to Partially Reset the Annual Cost of Capital Adjustment Mechanism and Related Matters, No. 19-04-014, 2019 WL 7403622 (Cal. Pub. Utils. Comm’n Dec. 19, 2019) [hereinafter Application of SCE]; D.16-06-053, In re Application of Kerman Tel. Co. (U1012c), to Review Intrastate Rates and Charges and Rate of Return for Telephone Service Furnished Within the State of California, and to Modify Selected Rates, No. 11-12-011, 2016 WL 3653733 (Cal. Pub. Utils. Comm’n June 23, 2016); D.11-09-040, In Re Alco Water Serv., No. A. 10-02-006, 2011 WL 4941709 (Cal. Pub. Utils. Comm’n Sept. 22, 2011) [hereinafter Alco Decision].

19. Application of SCE, supra note 18, at *9.

20. Id.

21. Id.

22. Alco Decision, supra note 18, at *12 (deciding that the CPUC had followed the principles in Bluefield and Hope, and despite the utility’s belief that the allowed rate of return was unreasonably low, the CPUC had acted lawfully).

23. Application of SCE, supra note 18.

24. Id. at *9–12.

25. Id. at *12–15.

26. Id. at *15–23.

27. Id. at *15.

28. A.B .1054 and the treatment of costs associated with wildfires are discussed infra.

29. Application of SCE, supra note 18, at *22.

30. Id. at *23.

31. Id.

32. D.06-05-041, In re Allocation of Gains from Sales of Energy, Telecomms., Water Util. Assets, 249 PUR 4th 478, at *39 (Cal. Pub. Utils. Comm’n May 25, 2006).

33. Id. at *5.

34. Id. at *14.

35. D.14-11-040, Order Instituting Investigation on the Commission’s Own Motion into the Rates, Operations, Practices, Services & Facilities of S. Cal. Edison Co. & San Diego Gas & Elec. Co. Associated with the San Onofre Nuclear Generating Station Units 2 & 3, and Related Matters, No. 13-01-016, 2014 WL 6791600, at *6 (Cal. Pub. Utils. Comm’n Nov. 20, 2014) [hereinafter SONGS OII].

36. Id. at *1.

37. The other four parties are Office of Ratepayer Advocates, The Utility Reform Network (TURN), Friends of the Earth, and Coalition of California Utility Employees.

38. SONGS OII, supra note 35, at *61–62.

39. Id.

40. GRC OIR, supra note 14, at *6.

41. Id.

42. D.20-05-019, OII into Maintenance, Operations and Practices of PG&E; and Order to Show Cause re: PG&E Role in Wildfires in 2017 (Cal. Pub. Utils. Comm’n May 7, 2020).

43. Id. at *19.

44. San Diego & Coronado Ferry Co., 210 Cal. 504, 512–13 (1930).

45. A.B. 1054, Public Utilities: Wildfires and Employee Protection, 2019–20 Reg. Sess.(Cal., July 12, 2019).

46. Cal. Pub. Util. Code § 451.1(b).

47. D.94-04-032, In re Proposed Policies Governing Restructuring of California’s Electric Services Industry and Reforming Regulation, 151 PUR 4th 73, at *1 (Cal. Pub. Utils. Comm’n Apr. 2, 1994).

48. Id. at *2.

49. Id. at *21.

50. D.95-12-063, In re Proposed Policies Governing Restructuring California’s Electric Services Industry and Reforming Regulation, 166 PUR 4th 141 (Cal. Pub. Utils. Comm’n Jan. 10, 1996).

51. Technically, the IOUs were only encouraged, not required, to divest their generation; but all generated electricity was required to be sold into the new power exchange and repurchased at the spot market prices in order to be sold to retail customers. See Joel B. Eisen et al., Energy, Economics and the Environment 710–12 (4th ed. 2015).

52. See Benjamin A. Holden, California Electric Utility Stocks Recover from Jolt—As Worry over Deregulation Eases, Outlook for the Industry Brightens, Wall St. J., Feb. 19, 1997, at B6.

53. Id.

54. Energy Ass’n of N.Y. State v. Pub. Serv. Comm’n of State of N.Y., 169 Misc. 2d 924, 941 (Sup. Ct. 1996), aff’d, 273 A.D.2d 708, 710 N.Y.S.2d 662 (2000).

55. Id.

56. In re Cent. Hudson Gas & Elec. Corp., No. 00-E-1273, 2001 WL 34659504, at *1 (Apr. 24, 2001).

57. Proceeding on Motion of the Commission to Commence a Review and Evaluation of the Treatment of the State’s Regulated Utilities’ Site Investigation and Remediation (SIR) Costs, No. 11-M-0034, 2011 WL 6764478, at *24 (N.Y. Pub. Servs. Comm’n Nov. 3, 2011) [hereinafter SIR Proceeding].

58. In re Nine Mile Point 2, No. 29124, 1986 WL 292831, at *60 (Oct. 3, 1986).

59. Energy Ass’n of N.Y. State, 169 Misc. 2d at 938 (citing N.Y. Pub. Serv. Law § 72); Abrams v. Pub. Serv. Comm’n, 67 N.Y.2d 205, 212 (1986); see also SIR Proceeding, supra note 57.

60. In re Competitive Opportunities Regarding Elec. Serv., 162 PUR 4th 1, at *8 (June 7, 1995).

61. Joint Petition of Iberdrola, S.A., Energy E. Corp., RGS Energy Grp., Inc., Green Acquisition Cap., Inc., N.Y. State Elec. & Gas Corp. & Rochester Gas & Elec. Corp. for Approval of the Acquisition of Energy E. Corp. by Iberdrola, S.A., No. 07-M-0906, 2008 WL 2486831, at *46 (June 16, 2008).

62. Proceeding to Examine Issues Related to a Universal Service Fund, No. 09-M-0527, 2012 WL 681886, at *31 (Jan. 4, 2012). While disapproving of the incumbent local exchange carriers’ (ILECs) argument that the Regulatory Compact required a “State Universal Service High-Cost Fund” to ensure they were compensated for falling revenues, the ALJ did ultimately recommend the establishment of such fund, albeit for other reasons related to the utilities’ ability to serve their customers.

63. In re Bos. Edison Co., 46 PUR 4th 431 (Apr. 30, 1982) (finding that Boston Edison’s service obligation was the reason that at least some part of the utility’s loss from a canceled nuclear plant was recoverable).

64. Id.

65. Id.

66. In re Elec. Indus. Restructuring, 163 PUR 4th 96 (Aug. 16, 1995). As discussed in more detail infra, stranded assets refers to assets that, due to some change in policy, technology, or other circumstance, no longer are economical.

67. Id.

68. Id.

69. Twenty ICC decisions referenced the Regulatory Compact, but only those few discussed here substantively addressed the Compact.

70. Ill. Power Agency, 2014 WL 2925379 (Ill. Comm. Comm’n June 17, 2014) (citing the Staff Initial Brief at 15–16).

71. Commonwealth Edison Co., 2018 WL 6437868 (Ill. Comm. Comm’n Dec. 4, 2018).

72. CPUC, Utility General Rate Case—A Manual for Regulatory Analysts (Nov. 13, 2017).

73. D.89-12-057, Application of Pac. Gas & Elec. Co. for Authority, Among Other Things, to Increase Its Rates and Charges for Electric and Gas Service 34 CPUC 2d 199, at *230 (Cal. Pub. Utils. Comm’n Dec. 20, 1989).

74. Cal. Pub. Util. Code § 455.5(a) (emphasis added).

75. See D.92-4-97, Re S. California Gas Co, No. 59316, 1980 WL 101144, at *44 (Cal. Pub. Utils. Comm’n Dec. 5, 1980) (SoCal Gas Co. authorized to increase gas rates by $142,726,200 in 1981 and an additional $45 million in 1982.) Here, SoCal Gas Co. was forced to abandon the work done on a coal gasification plant due to inability to secure funding and obtain necessary approvals. The CPUC was not only “concerned with the increasing magnitude of abandoned project costs and the frequency of abandonments, the cost of which we are routinely being asked to place on the ratepayers’ shoulders,” but also “concerned with the increasing burden being placed on the stockholders who in the past have invested in utility stocks as a reliable income stock with some growth possibilities and with very little risk.” Ultimately, the CPUC allowed SoCal Gas Co. to recover over $8 million of prudently incurred costs, with ratepayers responsible for 74.22 percent and shareholders responsible for 25.78 percent.

76. CPUC, supra note 72 (emphasis added).

77. D.84-09-089, In re S. Cal. Gas Co., 16 CPUC 2d 205 at *56–58 (Cal. Pub. Utils. Comm’n Sept. 6, 1984) (quoting D.83-12-068, In re Pac. Gas & Elec. Co., as modified by D.84-05-100, at 48–49, 57–58).

78. Id.

79. Id.

80. D.11-05-018, Application of Pacific Gas and Electric Company for Authority, Among Other Things, to Increase Rates and Charges for Electric and Gas Service Effective on January 1, 2011, 290 P.U.R.4th 1 (Cal. Pub. Utils. Comm’n May 5, 2011).

81. Id. at *28.

82. Id. at *31.

83. Id. at *28 (emphasis added).

84. D.95-12-063, In re Proposed Policies Governing Restructuring California’s Electric Services Industry and Reforming Regulation, 1995 Cal. PUC LEXIS 1034, at *213 (Cal. Pub. Utils. Comm’n Dec. 12, 1995).

85. Id.

86. D.97-11-074, Application of Pac. Gas & Elec. Co. for Approval of Valuation and Categorization of Non-Nuclear Generation-Related Sunk Costs Eligible for Recovery in the Competition Transition Charge, 1997 Cal. PUC LEXIS 1093, at *328 (Cal. Pub. Utils. Comm’n Nov. 19, 1997).

87. D.92-08-036, Order Instituting Investigation on the Commission’s Own Motion to Implement the Biennial Resource Plan Update Following the California Energy Commission’s Seventh Electricity Report, and Related Matters; In re Application of S. Cal. Edison Co. for Authority to Increase Its Authorized Level of Base Rate Revenue Under the Electric Revenue Adjustment Mechanism for Service Rendered Beginning January 1, 1992, and to Reflect this Increase in Rates, and Related Matters, 45 CPUC 2d 274 (Cal. Pub. Utils. Comm’n Aug. 11, 1992).

88. D.14-11-040, Order Instituting Investigation on the Commission’s Own Motion into the Rates, Operations, Practices, Services and Facilities of S. Cal. Edison Co. and San Diego Gas & Elec. Co. Associated with the San Onofre Nuclear Generating Station Units 2 and 3, 2014 WL 6791600 (Cal. Pub. Utils. Comm’n Nov. 20, 2014).

89. Id. at *2–3.

90. D.18-07-037, Order Instituting Investigation on the Commission’s Own Motion into the Rates, Operations, Practices, Services and Facilities of S. Cal. Edison Co. and San Diego Gas & Elec. Co. Associated with the San Onofre Nuclear Generating Station Units 2 and 3, 2018 WL 3753857 (Cal. Pub. Utils. Comm’n July 26, 2018).

91. Id. at *11.

92. Id. at *35 (emphasis added).

93. John Burritt McArthur, The Irreconcilable Differences Between FERC’s Natural Gas and Electricity Stranded Costs Treatments, 46 Buff. L. Rev. 1, 72 (1998) (discussing Order No. 380, Elimination of Variable Costs from Certain Natural Gas Pipeline Minimum Commodity Bill Provisions, 49 Fed. Reg. 22,778 (1984); Order No. 436, Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, 50 Fed. Reg. 42,408 (1985); and Order No. 636, Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation; and Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, 57 Fed. Reg. 13,267 (1992)).

94. John Burritt McArthur, Cost Responsibility or Regulatory Indulgence for Electricity’s Stranded Costs?, 47 Am. U. L. Rev. 775, 807 (1998).

95. Id. at 807–09.

96. Id. (discussing Associated Gas Distrib. v. FERC, 824 F.2d 981, 1024 (D.C. Cir. 1987), and Am. Gas Ass’n v. FERC, 888 F.2d 136, 142 (D.C. Cir. 1989)).

97. Order No. 500-H, Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, 54 Fed. Reg. 52,344, 52,357 (1989).

98. McArthur, supra note 94, at 810.

99. D.95-12-063, In re Proposed Policies Governing Restructuring California’s Electric Services Industry and Reforming Regulation, 1995 Cal. PUC LEXIS 1034 (Cal. Pub. Utils. Comm’n Dec. 20, 1995).

100. Id. at *538–39.

101. Id. at *539.

102. Id.

103. Id. at *541–42 (emphasis added).

104. Id. at *542 (emphasis added).

105. Id. at *196.

106. Id.

107. D.92-08-036, Order Instituting Investigation on the Commission’s Own Motion to Implement the Biennial Resource Plan Update Following the Cal. Energy Comm’n’s Seventh Electricity Report, and Related Matters; In re Application of S. Cal. Edison Co. for Authority to Increase Its Authorized Level of Base Rate Revenue Under the Electric Revenue Adjustment Mechanism for Service Rendered Beginning January 1, 1992, and to Reflect This Increase in Rates, and Related Matters, 1992 Cal. PUC LEXIS 561, at *29 (Cal. Pub. Utils. Comm’n Aug. 11, 1992).