Gas Utility Depreciation: Recommendations for an Uncertain Future

Introduction

For natural gas utilities, the next 50 years will likely look very different because of changing customer preferences, state-level climate and energy policy, and affordability concerns. These changes could significantly alter the gas system, potentially leading to ever-increasing rates for remaining gas customers and financial risk for utilities.¹ Although the future is clouded with uncertainty, today’s decisions on the recovery of the costs of gas utility assets like distribution mains and services will have a long-term impact.

These utility costs are recovered via depreciation expense, the portion of an asset’s original cost that utilities are authorized to collect each year over its expected service life, which can span decades. Commissions today are grappling with whether this long-term uncertainty warrants changes to traditional approaches to depreciation. In this article, we will examine utility depreciation, why commissions are considering changes to depreciation for gas utilities, and how commissions can balance near-term impacts with long-term risk.

Depreciation 101

The general depreciation process: From capital investment to cost recovery to retirement

Depreciation is the method by which a utility recovers the cost of its past capital investments from customers over time following this general process:

• A utility makes a capital investment.
  • These capital investments include a wide range of assets, from gas infrastructure to office buildings, and even software.
  • The investments are funded by a utility’s investors and creditors.
• The public utilities commission reviews these investments in a utility’s general rate case.
  • Once a commission approves the capital investment, the utility adds the assets to rate base and begins to recover the costs of the investments as depreciation expense in rates.
  • Utility depreciation studies are used as a basis for establishing the utility’s depreciation expense, such as the rate and method of depreciation, the grouping of assets, and an assessment of the service lives of assets.
• The utility recovers these costs over an asset’s service life via depreciation expense.
  • Each asset has a defined service or useful life, the period over which the asset will be in service and providing value to customers.
  • The service life of an asset (or, more commonly, a group of assets) is calculated using accounting tools and by incorporating other factors that could result in retirement of the asset.
  • The most common depreciation approach is to recover an equal portion of the asset’s cost each year over its service life, but other approaches can vary.
  • The utility’s investors and creditors will also earn a return on these capital investments over the service life of the asset.
• At the end of an asset’s service life, it is retired and removed from the utility’s books.
  • Asset retirement could include the decommissioning, removal, or even sale of the asset, the costs of which are typically included in the ongoing depreciation expense over the asset’s service life.

Policy Options to Address Depreciation for an Uncertain Future

Across the United States, commissions are reconsidering existing approaches to the depreciation of gas utility assets. This section will introduce several depreciation policies a commission could adopt that can strike a balance between utilities and their customers, both today and into the future.² These policies can be sorted into three categories:

1. Shortening the service lives of gas assets: Modifications to depreciation that could alter the timing of depreciation, specifically by shortening the service life of an asset.
2. Front-loading recovery of depreciation: Front-load recovery of depreciation to better match forecasted declines to gas consumption.
3. Consideration of retirement-related costs embedded in depreciation expense: These costs are typically embedded and recovered in depreciation expense via net salvage. The potential for shorter-lived assets and for decommissioning at a scale not seen historically has called into question the assumptions about these costs and the ability of utilities to cover these potential future costs.

Shortening the service lives of gas assets

Shortening the service lives of a group (or groups) of assets would allow utilities to recover the cost of its assets sooner. This alters the timing of depreciation and comes at the cost of increasing the depreciation expense for the remainder of that asset’s useful service life.

Consider the example in Exhibit 1 of a $1 million asset with a 50-year service life (represented by the blue line) that is shortened by 10 years, to 40 years (represented by the orange line). Shortening the service life by 10 years results in faster cost recovery, but higher expenses each year of service life. The graph in Exhibit 1 shows net plant-in-service, starting at the original $1 million cost with annual adjustments made according to the service life assumptions.

Exhibit 1. Comparison of cumulative net plant-in-service between the base, straight-line depreciation method and a scenario where the service life is shortened by 10 years

Utilities base service life determinations on a variety of factors. The National Association of Regulatory Utility Commissioners (NARUC) Depreciation Manual, a frequently cited reference on depreciation, lists three categories of factors that can cause an asset to be retired: physical factors (wear and tear or deterioration); functional factors (obsolescence, technological or demand changes, regulatory decisions), or contingent factors (disasters or extraordinary obsolescence).³

Today, utilities often emphasize the physical factors of a pipe, informed by accounting survivor curves and discussions with utility management, to determine service lives. Consideration of functional factors, such as changes to technology, customer demand, and regulation, could provide a basis for commissions to shorten service lives.⁴ Importantly, increased emphasis on functional factors would complement, not replace, traditional consideration of physical factors.

State approaches to shortening service lives

The New York Public Service Commission (NY PSC) ordered gas utilities to study the shortening of service lives and recognized that “the role of natural gas infrastructure in a low-carbon future has yet to be determined. . . . [But] failure to fully depreciate assets in a timely fashion while [local distribution companies (LDCs)] still have robust customer bases may lead to stranded costs.”⁵

Some commissions have explored more nuanced ways to account for the likelihood of shorter service lives for future gas assets. In a 2022 rate case, the Colorado Public Utilities Commission (CO PUC) considered two approaches modeled by the utility: requiring new assets to use a 30-year depreciation life (instead of approximately 60 years), or adopting an equal life group (ELG) method of grouping assets. According to the utility, moving to a 30-year depreciation life for new assets would increase depreciation expenses by about $36 million and changing to the ELG method would result in a $15.8 million increase in depreciation.

These approaches followed the CO PUC’s growing concern that, “the continued use of what can be viewed as a 57-year weighted average depreciation life on future capital plant investments is no longer reasonable given the uncertainty about the future trajectory of the gas utility business.”⁶ The commission ultimately required the utility to adopt the ELG method, which “fosters the gradualism we seek to accomplish during the time when the impacts of various potential factors related to the useful lives of facilities become better understood.”⁷ The commission concluded that, “Taking no action now causes there to be less opportunity to apply gradualism later.”⁸

A deeper dive into the ELG method of grouping assets is beyond the scope of this article, but a recent report suggests that its adoption could help address the growing uncertainty on the gas system because “it initiates the return of capital sooner for shorter-lived asset cohorts without necessitating a fundamental departure from the group depreciation framework.”⁹ In other words, the ELG method adopts a more granular approach to depreciation that can more closely match the recovery of depreciation expense to align with both shorter- and longer-lived assets within a group. ELG, however, comes at a cost, increasing the near-term depreciation expense. The report compared the ELG method with the average life group (ALG) method, which is a simplified method whereby “every dollar of investment within a group is depreciated at a uniform rate, irrespective of when the individual assets in a group are expected to retire.”¹⁰ ALG is best suited to “conditions of stable and predictable asset lives.”¹¹

Recommendations

• Consideration of functional factors, such as changes to technology, customer demand, and regulation, could provide a basis for commissions to take reasonable, gradual approaches to align depreciation approaches with forecasted changes to the gas system.
• Commissions can balance long-term risk reduction with near-term impacts by considering shortening the service lives of a subset of assets (such as new assets) and/or by exploring approaches like ELG.

Front-loading recovery of depreciation

The units of production depreciation method recovers depreciation expenses across an asset’s service life according to metrics like gas forecasted consumption. This method contrasts with straight-line depreciation, which assumes that depreciation expenses are spread equally across the service life of an asset. If a utility expects gas volume to decrease over time, and assuming that usage is a proxy for system costs, front-loading cost recovery via the units of production method may result in a closer match between costs and revenue from depreciation.

Exhibit 2 uses the same example as above (the baseline scenario) as well as depreciation expense using the units of production method, assuming a 2% annual decrease in gas usage over the 50-year life of the asset. This shows how straight-line depreciation results in a constant annual depreciation expense, depicted as a horizontal line, and how units of production acts to front-load depreciation expenses in line with a forecasted decline in gas consumption.

Exhibit 2. Comparison of annual depreciation expense between the base, straight-line depreciation method and the units of production method, assuming a 2% annual decrease in gas consumption

Exhibits 3 and 4 compare annual depreciation expense under three scenarios: a baseline case, a 10-year reduction in service life, and under the units of production method. Exhibit 3 shows the year-by-year expense impact of the modifications; this illustrates the difficult decision for commissions given the near-term rate impact of both shortening the service lives and units of production. Exhibit 4 shows net plant-in-service for these three approaches.

Exhibit 3. Comparison of annual depreciation expense between the base, straight-line depreciation method, shortening the service life by 10 years, and the units of production method, assuming a 2% annual decrease in gas consumption

Exhibit 4. Comparison of cumulative net plant-in-service between the base, straight-line depreciation method, shortening the service life by 10 years, and the units of production method, assuming a 2% annual decrease in gas consumption

State consideration of units of production depreciation

A utility in Washington proposed adopting the units of production method, arguing that it “provides a way to protect future customers from exponentially increasing bills as customers leave the system.”¹² According to the utility the approach would align depreciation with the forecasted decline in gas demand to “mitigate future customer rates, thereby not only protecting future customers but also resulting in a fairer and more equitable approach” in line with intergenerational equity.¹³ The Washington Utilities and Transportation Commission (WA UTC) found the proposals “persuasive in part,” but declined to adopt the utility’s proposal due to the utility’s impending integrated system plan and the opposition of several key parties.¹⁴

The California Public Utilities Commission (CPUC) is considering whether to adopt alternative depreciation methods like the units of production method, a variation of which is referred to as proportional depreciation in the state’s long-term gas proceeding.¹⁵ Several parties in that proceeding have advocated for gas and electric utilities to propose proportional depreciation, which “will allow for the downward pressure on electric rates from increased demand to potentially offset the upward pressure on gas rates from decreased demand.”¹⁶ The CPUC had not made a determination at the time of writing on proportional depreciation.

And in Colorado, the CO PUC considered and declined to adopt the units of production method in a utility’s depreciation docket, but it noted that “this methodology should not be disregarded in future depreciation studies.”¹⁷ The CO PUC went on to say that forecasts showing declining sales in the record raised “significant concerns about rates and stranded assets” and that “it is possible if not likely that a change in strategy to further accelerate depreciation expenses . . . by better matching the depreciation expense temporarily with anticipated usage will be important to continue to consider.”¹⁸

Recommendations

• The units of production method can better match depreciation expense with system costs and gas usage when gas usage is expected to decline in the future.
• Care should be taken to consider gas usage forecasts that underpin a units of production analysis given the near-term rate impact and equity concerns that units of production could cause if an overly aggressive decline in gas usage is forecasted but does not materialize.
• As discussed above, consideration of the ELG method can have the effect of front-loading depreciation without the added uncertainty of relying on gas consumption forecasts if implemented.¹⁹

Consideration of retirement costs embedded in depreciation expense

The costs associated with retirement of gas assets — specifically early retirement — are often recovered in depreciation expense today via net salvage. How utilities calculate and report these costs is under increasing scrutiny as commissions require utilities to assess unprecedented gas system scenarios within depreciation pathways studies. This section will describe these challenges in greater detail and will provide recommendations for how to improve data collection and the calculation of these costs.

A brief note on terminology. We refer to retirement costs as a broad category that includes removal and decommissioning costs. Removal costs are often associated with removal and replacement of an old asset, with some comingling of those costs. Decommissioning costs are defined here as costs associated with taking an asset out of service with no corresponding replacement of the asset.

Net salvage and its role in depreciation

Net salvage is the shorthand for the component of depreciation expense related to asset retirement. Net salvage is composed of two elements: the salvage value of the asset and the costs associated with the retirement of an asset. For gas infrastructure, the estimated retirement costs are commonly greater than the salvage value (often zero), so net salvage is usually negative. Net salvage is added to depreciation expense in a logical, but slightly confusing manner. Negative net salvage, meaning retirement costs are greater than the salvage value, increases depreciation expense, while positive net salvage (again, much rarer in the gas asset context) decreases depreciation expense. Net salvage is also updated with recent, current costs of retirement, whereas the cost of the asset is its original, nominal cost.

The example below illustrates how net salvage is calculated and how it affects depreciation expense. The example also shows net salvage as a percent of the original cost of the asset, which is often how net salvage is calculated by utilities:

Salvage Value (−) Retirement Costs = Net Salvage

Original Cost (−) Net Salvage = Depreciation Expense

$10 Original Cost (−) −$5 Net Salvage = $15 Depreciation Expense

−$5 Net Salvage / $10 Original Cost = −50% Net Salvage

Net salvage “can be the most critical component of the depreciation rate,” especially for older gas distribution assets or when the early retirement of gas assets is considered.²⁰ The following sections describe why.

Early retirement/decommissioning scenarios could require changes to the calculation of net salvage

The early retirement of gas assets could result in the decommissioning of relatively younger pipe. If this were to occur, changes to calculations of net-salvage costs may be required. Applying the same percentages of net salvage used by utilities to calculate the cost of retirement under business-as-usual scenarios to an early retirement scenario could result in unnecessarily high depreciation costs (and therefore rates):

($10 asset installed in 1960) x (−50% net salvage) = $5 net-salvage costs

(Same asset is $58 if installed in 2000) x (−50% net salvage) = $29 net-salvage costs

In the example above, if estimated retirement costs were $5 in today’s dollars and the underlying asset was $10 when it was installed in 1960, then the utility could apply a −50% net-salvage rate to recover $5 in retirement costs. But for a newer asset, such as one installed in 2000 at a nominal cost of $58, then the utility would be over-collecting retirement costs if the same −50% net salvage was used for the newer asset. It would recover $29 in net-salvage costs compared with the $5 it “should” collect. The percentage of net salvage for the vintage assets installed in 2000 should be closer to −8% (not −50%) to collect the $5 in net-salvage costs. Like many examples in this article, the actual mechanics of utility depreciation and how assets are grouped are more complicated, but the example demonstrates how analysis of early retirement requires careful scrutiny to avoid potential overcollection.

Advocates in Massachusetts raised this concern in a Massachusetts Department of Public Utilities (MA DPU) proceeding regarding gas utilities’ Climate Compliance Plans, arguing that the utilities’ approach of using net-salvage percentages in the context of early retirements could balloon depreciation costs, far exceeding other retirement cost projections used by the same utilities in other contexts.²¹ This could occur, according to the expert testimony, if the utility continued to apply a percentage of net salvage to the original cost of the asset, “if pipe retired is significantly newer than historical precedent, such as in a decarbonization scenario with large-scale early retirements — then the net-salvage percentage should be lower than projected based on historical data.”²²

For future depreciation studies, the increased scrutiny of net-salvage calculations and assumptions, and the incorporation of appropriate changes, should help to mitigate the impact of net-salvage costs for early retirement scenarios. Commissions and other parties can also convert net salvage into more tangible metrics such as cost per foot (or mile) for retirement costs as a reasonableness check for the underlying assumptions.

A lack of decommissioning data drives uncertainty

A lack of data regarding decommissioning costs has also generated debate in recent depreciation proceedings. Current utility approaches to estimating these costs are largely based on historical utility practices where old pipe was often retired in place and replacement activity (and costs) such as permitting or labor costs got comingled with removal activity. According to one utility’s testimony in Washington, future decommissioning may require additional costs such as the physical removal of gas infrastructure or the incurring of costs not commonly incurred in the past, which could result in significantly higher retirement costs — although there was disagreement in the proceeding about whether this is accurate.²³

This issue also arose in the MA DPU proceeding described above, where concerns regarding the availability of decommissioning cost data from utilities further clouded advocates’ ability to assess forecasted retirement costs, as well as projections for future utility capital spending, which could make the net-salvage issue even more significant if the relatively younger infrastructure is to be decommissioned. Advocates in that proceeding recommended that the MA DPU require utilities to track and report costs in a more granular manner, investigate cost containment strategies in a widespread decommissioning scenario, and investigate alternative methods of recovering these costs, such as recovering them as expenses rather than incorporating them into depreciation.²⁴

A decommissioning trust fund approach

As described above, utilities recover estimated retirement costs alongside depreciation expenses across an asset’s entire service life. The revenue generated from this “serves as free cash flow for the company, with no restrictions as to its use.”²⁵ Although this is generally true for any revenue received by a utility, the CO PUC became concerned with the implications of this practice in a series of recent gas rate and depreciation cases.

In particular, the CO PUC was concerned that the utility’s approach to recovering decommissioning costs in rates, but not reserving the funds for future use, created a “significant and problematic financial risk.”²⁶ This risk was rooted in the interplay between the aforementioned accounting approach and the long-term trajectory of the gas utility given the projection of lower future gas sales, the potential for customer defection, and the commission’s efforts to promote electrification programs.²⁷

As a result, the commission required the utility to establish a decommissioning trust fund, funded by an initial $15 million deposit with annual $15 million contributions by the utility. The funds in the trust “are to be held for future asset retirement obligations” that are only triggered when actual retirement expenses exceed the level of retirement costs recovered via depreciation expense.²⁸

Retirement cost recommendations

It is clear from the examples above that the costs associated with retirement and potential decommissioning play a major role in depreciation outcomes, with more information and data needed to help commissions plan for the future. Commissions can therefore examine the assumptions contained in net-salvage estimates and take appropriate action. Asking the following questions would get to the root of the issue, but could require utilities to collect new types of data:

• What are the utility’s costs of decommissioning today, broken down by asset types and by dollar per foot (or mile)?
• How could the utility’s cost of retirement change in the future, if an asset is expected to be fully decommissioned with no replacement?
• Should net-salvage costs be estimated (or even recovered) differently in the context of early retirement?

Summary of policy options to address depreciation

This section described depreciation policy options that fall under three broad categories: shortening the service lives of assets, front-loading recovery of depreciation, and consideration of retirement costs embedded in depreciation expense. These recommendations are summarized below:

• Shortening the service lives of assets
  • Commissions’ consideration of functional factors, such as changes to technology, customer demand, and regulation, could provide a basis for reasonable, gradual approaches that align depreciation approaches with forecasted changes to the gas system.
  • Commissions can balance long-term risk reduction with near-term impacts by considering shortening the service lives of a subset of assets (such as new assets) and/or by exploring approaches like ELG.
• Front-loading recovery of depreciation expense
  • The units of production method can better match depreciation expense with system costs and gas usage when gas usage is expected to decline in the future.
  • Care should be taken to consider gas usage forecasts that underpin a units of production analysis given the near-term rate impact that units of production can have if an overly aggressive decline in gas usage is forecasted but does not occur.
  • Consideration of the ELG method can have the effect of front-loading depreciation without the added uncertainty of relying on gas consumption forecasts.²⁹
• Consideration of retirement costs embedded in depreciation expense
  • Commissions should examine assumptions contained in net-salvage estimates and collect additional data that answers the following questions:
    • What are the utility’s costs of decommissioning today, broken down by asset types and by dollar per foot (or mile)?
    • How could the utility’s cost of retirement change in the future, if an asset is expected to be fully decommissioned with no replacement?
    • Should net-salvage costs be estimated (or even recovered) differently in the context of early retirement?

Depreciation Pathways Studies Can Shed Light on Long-Term Trends

Many of the depreciation studies that commissions have recently required of utilities look different than traditional studies given the inclusion of policy-driven scenarios and forecasts. These requirements are similar to decarbonization pathways studies that are often conducted within future of gas and/or gas planning proceedings. For that reason, we call this type of depreciation study a depreciation pathways study. These studies are planning tools that can help commissions evaluate how different futures for the gas system could affect depreciation policy, customer bills, and long-term financial risk. By modeling a range of scenarios such as declining gas demand, electrification, or different capital investment trajectories, these studies help regulators understand the implications of alternative depreciation approaches.

Depreciation pathways contain the following components:

• Time horizon: This horizon is often longer than 20 years.
• Scenarios: These are forecasts of gas customer count, usage, and capital spending based on different levels of electrification, often with a scenario tied to achievement of a state’s climate goals and compared with a business-as-usual scenario.
• Depreciation: This involves consideration of different approaches to depreciation, such as shortening service lives or applying the ELG procedure or the units of production method, for the different scenarios.
• Inputs: These are forecasts of gas customer count, gas usage, capital spending, and retirement costs.
• Outputs: These include utility revenue requirement, depreciation expense, depreciation expense per customer, and bill impact per customer.
• Other: Alternate forms of long-term risk reduction, such as trust funds or expensing decommissioning costs, must also be considered.

Emerging lessons for commissions considering depreciation pathways studies

Depreciation pathways studies should be an integral part of broader gas planning efforts because they can help commissions see the depreciation-related impacts of different gas utility scenarios and consider depreciation policy changes alongside other policy changes. This means, at the very least, that depreciation pathways studies should integrate assumptions and scenarios regarding future gas usage, utility capital spending, and achievement of climate goals from gas planning proceedings into depreciation pathways studies. Even better, commissions can require depreciation pathways studies within gas planning proceedings, which can help commissions craft consistent policy decisions across a number of topics, including depreciation.

Integrating depreciation pathways studies into planning proceedings, where they exist, can help improve the record upon which commissions make decisions. For example, the CO PUC has been able to evolve its approach to depreciation for the state’s largest gas utility over several rate cases and depreciation proceedings by requiring depreciation pathways studies that incorporate the state’s gas policy goals.

This integration into planning can also help commissions grapple with the mismatch between aggressive, policy-driven scenarios that show dramatic declines in gas usage and customers versus current utility trends, which often show a different trajectory regarding customers and capital spending. This mismatch drives opposition to accelerated depreciation. For example, in the MA DPU proceeding one party argued that “the LDCs’ approach to accelerating depreciation now ignores the reality that the companies are, in fact, projecting growth in their systems, not contraction to the level that might increase the risk of stranded costs.”³⁰ In other contexts, however, utilities have adopted this rationale to oppose commission action on issues like line extension allowances.

One way to cut through this uncertainty is to require that depreciation pathways studies include a scenario that is more ambitious than business as usual, but also is grounded in near-term trends and existing policy and programs. Such a scenario could incorporate the existing, long-term trend of reduced gas use per customer and incorporate existing trends regarding heat pump adoption and spending on customer electrification programs beyond what a utility projects in a business-as-usual forecast.

Over time, this middle ground forecast could (and arguably, should) converge with a policy-driven forecast and the commission could adjust depreciation practices accordingly. But in the meantime, it encourages proactive risk management while balancing near-term rate impacts. Commissions could use this forecast as a basis to adopt gradual changes to depreciation policy, including many of the policies described herein, while also building a record and expertise to scale the changes where appropriate.

Other policy levers and considerations

Although depreciation is the focus of this article, it is not the only tool to address long-term risk and uncertainty in the gas system and it should not be considered in isolation, especially given the near-term rate impact of accelerating depreciation and utility de-risking.

This article suggests that depreciation pathways studies should be an integral part of gas planning for this very reason. Consideration of depreciation within a gas planning proceeding enables commissions to consider related factors such as the utility’s projected system growth and capital spending. Depreciation should be used to harmonize a commission’s long-term policy goals with utility and customer trends and should therefore not be considered in a policy vacuum.

Commissions may also wish to consider how changes to depreciation policy lower the risk profile of the utility itself, which is a key consideration for the establishment of a utility’s authorized return on equity (ROE).³¹ If a commission decides to adopt changes to depreciation for a subset of assets, it could consider whether application of a lower ROE for those assets (a concept called differentiated ROE) or for the overall utility given the risk reduction impact of accelerating depreciation. This is just one example of complementary policies a commission could consider when making changes to a utility’s depreciation policy.

Conclusion

Utility depreciation is a relatively straightforward concept — calculating the recovery of a utility’s costs over time. But a myriad of factors complicates the path forward for many commissions. The most significant factor is the underlying and increasingly uncertain long-term future of the gas system. Changing depreciation approaches now in anticipation of these changes, in whatever form they may take, is a challenge. This challenge is magnified by the near-term affordability implications of modifying depreciation approaches and by concerns regarding current trends and policies regarding the expansion of the gas system.

To paraphrase one commission that has taken action on depreciation: Delaying action now means that future actions may need to be more drastic.

Endnotes

[1] This financial risk is often expressed as stranded asset risk, which describes a scenario where a utility asset is retired before it is fully depreciated, thus “stranding” its costs. In these scenarios, which have occurred in the electric sector when a power plant is retired before its costs are recovered, for example, the question then becomes whether the utility is entitled to recover these stranded costs and, if so, who bears the responsibility to pay for these costs? A deeper examination of stranded asset policy for gas utilities in the event of customer defection and asset retirement at scale is outside of the scope of this article, but we present the risk broadly here as financial risk.

[2] Although the focus of this article is on depreciation, depreciation is just one tool in a commission’s toolbox that can align utility and customer interests heading into an uncertain future.

[3] National Association of Regulatory Utility Commissioners (NARUC), Public Utility Depreciation Practices at 14–15 (1996).

[4] See, e.g., Washington Utilities and Transportation Commission v. Puget Sound Energy, Inc., WA UTC Dockets UE-240004 & UG-240005, Prefiled Direct Testimony of Ned W. Allis, 2023 Depreciation Study at III-2 to III-3 (describing how the utility’s depreciation study took into account Washington state’s greenhouse gas emissions goals when determining service lives).

[5] Proceeding on Motion of the Commission in Regard to Gas Planning Procedures, NY PSC Dockets 20-G-0131 and 12-G-0297, Order Adopting Gas System Planning Process at 61 (May 12, 2022).

[6] In the Matter of Advice Letter No. 993-Gas of Public Service Company of Colorado […], CO PUC Proceeding 22AL-0046G, Decision C22-0642 at 50 (October 25, 2022).

[7] In the Matter of Advice Letter No. 993-Gas of Public Service Company of Colorado […], CO PUC Proceeding 22AL-0046G, Decision C22-0642 at 51 (October 25, 2022).

[8] In the Matter of Advice Letter No. 993-Gas of Public Service Company of Colorado […], CO PUC Proceeding 22AL-0046G, Decision C22-0642 at 51 (October 25, 2022).

[9] Amanda Nori, Concentric Energy Advisors, Reassessing Depreciation Methodology: The Case for Equal Life Group Depreciation at 8 (July 2026).

[10] Amanda Nori, Concentric Energy Advisors, Reassessing Depreciation Methodology: The Case for Equal Life Group Depreciation at 4 (July 2026).

[11] Amanda Nori, Concentric Energy Advisors, Reassessing Depreciation Methodology: The Case for Equal Life Group Depreciation at 4 (July 2026).

[12] Washington Utilities and Transportation Commission v. Puget Sound Energy, Inc., WA UTC Dockets UE-240004 & UG-240005, Prefiled Direct Testimony of Ned W. Allis at 26 (February 15, 2024).

[13] Washington Utilities and Transportation Commission v. Puget Sound Energy, Inc., WA UTC Dockets UE-240004 & UG-240005, Prefiled Direct Testimony of Ned W. Allis at 27 (February 15, 2024).

[14] Washington Utilities and Transportation Commission v. Puget Sound Energy, Inc., WA UTC Dockets UE-240004 & UG-240005, Final Order at 107–108 (January 15, 2025).

[15] Order Instituting Rulemaking to Establish Policies, Processes, and Rules to Ensure Safe and Reliable Gas Systems in California and Perform Long-Term Gas System Planning, CPUC Rulemaking 24-09-012, ALJs’ Ruling Seeking Comment Regarding Interim Actions 1 (November 13, 2024).

[16] Order Instituting Rulemaking to Establish Policies, Processes, and Rules to Ensure Safe and Reliable Gas Systems in California and Perform Long-Term Gas System Planning, CPUC Rulemaking 24-09-012, Sierra Club and NRDC comments at 14 (March 15, 2025).

[17] In the Matter of the Application of Public Service Company of Colorado for Authorization to Revise the Depreciation Rates for Gas Utility Plan Assets, CO PUC Docket No. 25A-0165G, Decision C25-0921 at 16 (December 19, 2025).

[18] In the Matter of the Application of Public Service Company of Colorado for Authorization to Revise the Depreciation Rates for Gas Utility Plan Assets, CO PUC Docket No. 25A-0165G, Decision C25-0921 at 16 (December 19, 2025).

[19] See Amanda Nori, Concentric Energy Advisors, Reassessing Depreciation Methodology: The Case for Equal Life Group Depreciation at 9 (July 2026).

[20] National Association of Regulatory Utility Commissioners (NARUC), Public Utility Depreciation Practices at 18–19 (1996).

[21] 2025 Climate Compliance Plans, MA DPU Dockets 25-41 to 45, Surrebuttal Testimony of Bradley Cebulko & Meera Fickling at 30-31 (February 13, 2026).

[22] 2025 Climate Compliance Plans, MA DPU Dockets 25-41 to 45, Direct Testimony of Bradley Cebulko & Meera Fickling at 70–71 (November 17, 2025).

[23] See, e.g., Washington Utilities and Transportation Commission v. Puget Sound Energy, Inc., WA UTC Dockets UE-260005 & UG-260006, Prefiled Direct Testimony of Ned W. Allis at 34 (February 27, 2026). But see Response Testimony of Bradley Cebulko at 63–69 (July 28, 2026).

[24] 2025 Climate Compliance Plans, MA DPU Dockets 25-41 to 45, Surrebuttal Testimony of Bradley Cebulko & Meera Fickling at 44–45 (February 13, 2026).

[25] In the Matter of Advice Letter No. 1029 — Gas Filed by Public Service Company of Colorado […], CO PUC Proceeding 24AL-0049G, Decision C24-0778 at 54 (October 25, 2024).

[26] In the Matter of Advice Letter No. 1029 — Gas Filed by Public Service Company of Colorado […], CO PUC Proceeding 24AL-0049G, Decision C24-0778 at 54 (October 25, 2024).

[27] In the Matter of Advice Letter No. 1029 — Gas Filed by Public Service Company of Colorado […], CO PUC Proceeding 24AL-0049G, Decision C24-0778 at 54 (October 25, 2024).

[28] In the Matter of Advice Letter No. 1029 — Gas Filed by Public Service Company of Colorado […], CO PUC Proceeding 24AL-0049G, Decision C24-0778 at 55 (October 25, 2024).

[29] See Amanda Nori, Concentric Energy Advisors, Reassessing Depreciation Methodology: The Case for Equal Life Group Depreciation at 9 (July 2026).

[30] 2025 Climate Compliance Plans, MA DPU Dockets 25-41 to 45, Initial Brief of the Office of the Attorney General at 63 (April 21, 2026).

[31] See 2025 Climate Compliance Plans, MA DPU Dockets 25-41 to 45, Rebuttal Testimony of Ned Allis at 48 (December 19, 2025), noting that changes to depreciation will reduce the cost of capital “because investors will have lower stranded-cost and regulatory risk.”