Published on August 19, 2020

By: Alexander Cochis, Project Manager and Javier Sola, Consultant

Environmental advocates are challenging whether it makes sense to continue with existing pipe replacement programs, arguing that the industry is investing in rate base that will be stranded long before it is fully depreciated.

Key Considerations

• Should a gas company continue, accelerate, or reprioritize its pipe replacement program?
• If regulators place shareholders at risk for new pipe investment, how can local gas distribution companies (LDCs) manage that risk?
• Should the company propose a change to depreciation rates for existing or new pipe?

A pipe replacement framework that incorporates uncertainty attributable to:

• Decarbonization policy
• The economics of electrification
• Customer decisions to continue to use natural gas

Will meet the challenges of a changing environment.

A New Investment Framework

The existing pipe replacement decision-making process focuses on how fast LDCs can replace at-risk pipe and how best to prioritize and execute their pipe replacement programs. These decisions are driven by federal mandates and subject to oversight by state utility regulators that are concerned about safety and cost. Environmental advocates are opposing new pipelines but also suggesting that LDCs should be at risk for future pipe replacement investments, as they increasingly focus on gas planning processes and decisions. Regulators recognize that pipeline safety is paramount. How can LDCs adjust the decision-making framework to support pipe replacement decisions? Our current assessment is that the degree of policy change, technological advances, and the costs of alternatives or substitutes to natural gas all play a role in framing a response to the challenges of decarbonization on pipe investment decisions.

For a gas company to fulfill its public service mandate, it will make ongoing maintenance, monitoring, and operating expenditures to sustain the system and comply with safe operating practices (Figure 1). The LDC can also make investments to grow. As costs increase, operators will decide how long before those outlays are completely recovered.The Pipe Replacement Decision Framework in Figure 2 depicts areas that represent varying degrees of costs, recovery time, and risk for the project types in Figure 1.

Project types in the Pipe Replacement Decision Framework present risks that are the product of both the likelihood of being unable to sufficiently recover capital and the amount of capital exposed. The further investment decisions move away from the short payback and minimum expenditure programs, the closer decisions are framed by a “risk envelope” space depicted in the Framework. Trade-offs may begin to appear between lower cost pipe segments that have longer time horizons to recover capital (new branch lines with few customers) and larger capital investments with shorter paybacks (removal and replacements of entire mains in established and densely served areas). As undepreciated investments approach economic planning horizons or any other mandated useful lives, the potential for customer rate shock as obsolete capital is recovered or loss to shareholders from stranded cost presents an opportunity to look for innovative capital investment and recovery methods.

Decarbonization policies are likely to change the risk analysis. Environmental considerations may accelerate technological improvements toward lower carbon natural gas through targeted investments and state or provincial carbon intensity limits. While mandates and subsidies are by their nature distortive, they can also spur new delivery models. Power supply renewables, for example, are following a discernible cost decline as mandated investments lead to economies of scale.

Risk introduces elements of time-sensitive paybacks to traditional decision-making metrics like net present value, rates of return, and size of rate base. This may present more realistic prospects for pipe recovery for a gas company facing more ambitious decarbonization policies. The new investment decision framework should incorporate uncertainty. Decarbonization policy, the economics of electrification, customers’ preference to continue to use natural gas, and new safety protocols all change the investment views on how long new pipe will be needed.

Responses to Some Common Questions

Should the LDC continue, accelerate, or reprioritize its pipe replacement program?

Under the Pipe Replacement Decision Framework, the degree of decarbonization will be a significant driver of the answer to this question, with “net zero carbon” scenarios presenting the greatest risk, as will the timeline for phasing in the program. Pipe system integrity is regulated by the states, and federally by the Pipeline and Hazardous Materials Safety Administration (PHMSA) under the Distribution Integrity Management Program (DIMP). Given the duty to maintain a safe system, any decarbonization policy would need to support system safety to the extent the system or certain segments or subsystems remain in service. While an argument might be made for repairing, rather than replacing, the classes of leak-prone pipe (LPP) currently targeted under DIMPs, the trade-off would require careful risk analysis of the LPP in order to ensure that leaks are maintained on the system at a manageable level. Pipe replacement is usually triggered by integrity concerns or capacity needs. These investment decisions could be broadened to reflect decarbonization policies. Depending on the type of decarbonization policy adopted by the state, pipe programs may be reconfigured to include the consideration of the use of new technologies, including, for example, the use of geothermal district heating as an alternative to replacement of LPP lines.

If regulators place shareholders at risk for new pipe by ruling against stranded cost recovery, how can local LDCs manage that risk? 

A significant driver of the answer to this question will depend on the carbon scenarios mandated. Investment strategy will reflect the level of increased risk and the pace of decarbonization. Asset management and portfolios, market position, and performance metrics will shift in the LDC company space. Pipe investment moves from a series of cost of service approval exercises to a dynamic consideration of available alternatives, where market forces truncate useful lives, and the probabilities change once large investments are made.

For example, changes in public policy resulting in stranded costs would raise the business risk of the company and likely merit a higher allowed return. The degree of the decarbonization under new mandates would drive whether system investment strategy would change. To the extent that gas will still be needed for generation to balance higher levels of renewables that support decarbonization, for example, investment decisions may shift to supporting new generation rather than expanding residential service. If the decarbonization policy allows offsets, then investments could be made to support the offsets (e.g., reforestation programs) to maintain a status quo business plan in regulated operations. Should renewable natural gas (RNG) be available and competitive at scale and fall within the decarbonization policies, then a company could make investments to transition to RNG supplies.

Should the company propose a change to depreciation rates for existing or new pipe? 

Near-term increases in depreciation rates present ways to balance investment recovery with policy goals in an incremental manner and can be adjusted through a rate case, with due consideration to rate impacts. Future earnings levels could be relatively lower if decarbonization policy reduces rate base. For this reason, any change to depreciation or capital recovery must be made in concert with other variables such as rates of return, salvage costs, capital budgeting, or risk management. Higher depreciation rates would present a way to hedge some of the risk associated with the underutilization or early retirement of pipe. Should the type of decarbonization policy adopted lead to an early abandonment of pipe, then increasing the rate of depreciation would allow for the accelerated recovery of the investment, mitigating the risk of stranded assets.

All views expressed by the authors are solely the authors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The authors’ views are based upon information the authors consider reliable. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.

Published on June 26, 2020 

By: Team Concentric

This article is the second in a series addressing the changing environment for regulated utility pricing given advances in Distributed Energy Resource technology, data availability, and customer preferences. Part One, Renewable Distributed Generation and Pricing Challenges, addressed the issue of Net Energy Metering.

Demand charges have been a component of electric utility pricing design for many decades. The original arguments for demand charges were developed by John Hopkinson[1] and further summarized by James Bonbright:

“The full rationale of this Hopkinson, two-part rate is far from simple. But the rationale usually given (although it will serve only as a first approximation) is that the two-part rate distinguishes between the two most important cost functions of an electric-utility system: between those costs that vary with changes in the system’s output of energy, and those costs that vary with plant capacity and hence with the maximum demands on the system (and subsystems) that the company must be prepared to meet in planning its construction program.”[2]

However, industry experts are now debating whether demand charges are an appropriate pricing mechanism, in particular for smaller customers (e.g., residential customers). Some compelling arguments against demand charges to consider:

·         Demand charges do not send proper price signals to customers.

·         Demand charges are expensive to implement.

·         Customers do not understand demand charges.

·         Customers cannot react and/or respond to demand charges.

·         No cost support exists for demand charges; they do not reflect the incremental cost to use the distribution system.

·         Distribution investments should be recovered by some form of energy charge.

In this article, we limit the debate to electric distribution systems. We will assess the arguments for and against demand charges and determine if demand charges are an appropriate mechanism in an electricity pricing design.

The Economics of an Electric Distribution System

One of the traditional arguments for the regulation of utilities is the existence of natural monopolies. A natural monopoly is defined as an industry with economies of scale, which results in the long-run marginal cost below the average cost for a single producer. Given the economies of scale associated with electric distribution systems, it is only economically efficient for a single system to exist within a given geographic area.

Unlike competitive markets, where prices are established at the marginal cost of production, a natural monopoly must set prices above the marginal cost. The revenues generated by marginal cost prices are insufficient to financially support the system. Therefore, the challenge for a natural monopoly is to determine how to recover the additional needed revenue in a manner that is considered equitable and sends a proper price signal to the customer.

In the energy industry, experts have argued that distribution systems are not constructed to serve demand and that their cost structure is fixed. To address such arguments, the authors consulted on the design of electric distribution systems with Anthony (Tony) Hurley. Mr. Hurley is an electric distribution system expert with over 30 years of experience. He is currently a Consultant at Critical Preparedness, LLC and previously held a leadership role in Electric Distribution at FirstEnergy as Vice President of Operations at Jersey Central Power & Light. Mr. Hurley stated:

Every customer on a distribution circuit, whether residential, commercial, or industrial, has a load profile that mirrors their load usage and peak demands, with the data being captured by the utility. From this demand information, distribution engineers are able to make investment decisions and reconfigure circuits if loads may exceed equipment ratings, and forecast the need for capital projects, including equipment upgrades and possibly new substations to address peak loads. To accept the premise that demand information is not used in Distribution Planning is incorrect.

Ultimately, the planning function for a distribution system is based upon expectations of demand growth within that system. For a system operator to send the correct price signal to customers, the distribution system should be priced at the long-run marginal cost.

Definition – What is Demand?

Traditional definitions of demand, (e.g., the maximum level of consumption by a customer averaged over a time period such as a one-hour or 15-minute interval), imply a one-way flow of power from the utility to the customer. However, the traditional definition of demand is no longer applicable in a world with Distributed Energy Resources (DER). The growth of DER means that a utility is now required to plan not only for an inflow of electricity to the customer, but an outflow from that same customer to the distribution system if their DER output exceeds consumption at a given point in time. A specific example of this is a customer with a small residential solar array who draws energy at night when the panels are not generating power, but during the day may produce more than they consume. Therefore, a pricing mechanism designed for demand could be characterized as an “option.” Customers would purchase an option designed to allow them to use a system up to a certain quantity of demand, either received or injected into the distribution system. This behavior would provide proper production signals to the utility, guiding better-informed investment.

Arguments Commonly Made Against Demand Charges

Argument 1: “Demand Charges Do Not Reflect the Incremental Cost of Using the Grid”

An argument is often made that demand charges do not reflect the incremental cost to serve customers, but instead are based upon average embedded costs. As a result, they would send a false price signal to customers. Some truth can be ascribed to this statement if the pricing design follows an embedded cost of service approach.

However, the development of long-run marginal cost of service is possible; such studies have been performed by many utilities in the last several decades. A traditional approach to developing demand charges based upon average embedded costs can be problematic. Still, recent innovations have included a more detailed analysis of the distribution cost structure and the impact of DER.

Argument 2: “Demand Meters are Expensive to Implement”

To create and implement a demand charge, the customer premises must be outfitted with metering equipment, which is capable of measuring that customer’s demand in real-time. A traditional argument against implementing demand charges for residential and small commercial customers is that the incremental cost of this metering technology is expensive, and it is not cost-beneficial to install the metering technology on a system-wide basis.  Although this may have been true in the past, it is no longer accurate.

Metering technology costs have dropped dramatically in the last several decades.  The replacement of electromechanical technology with today’s Advanced Metering Infrastructure (AMI) equipment has reduced costs and increased reliability in many instances. Further, the cost of data management has decreased, allowing for more complex billing structures to be easily processed and delivered to customers. Modern metering equipment associated with AMI generally has the capabilities to provide revenue quality demand charges as well as other, more advanced pricing designs.

Argument 3: “Customers Do Not Understand Demand Charges”

Many parties have argued that customers, especially residential customers, are unable to understand the complexities of demand charges. They claim that traditional utility tariffs for smaller customers, based solely on two-part pricing designs (i.e., a fixed charge and an energy charge), remain appropriate.

We believe a discerning customer is able to navigate demand charges for the following reasons:

• If smaller customers are incapable of understanding complex pricing design, that would render all efforts towards more advanced price design too complex. If utilities can successfully implement programs such as Time-of-Use Pricing, Real-Time Pricing, Critical Peak Period Pricing, and Demand Response, which are far more complex than the concept of a demand charge, the latter should not be an issue for customers to understand.
• Residential customers face several complex pricing designs outside of electric utility tariffs. For example, most residential customers make decisions involving automobile and health insurance, mobile telephones, and cable television/internet offering service and pricing options, including multi-part pricing, which are as complex or more complex than a utility tariff with a demand charge.
• The use of demand charges and demand limiters for smaller customers have been successfully implemented in other countries such as Italy [3] and Pakistan,[4] showing that customers around the globe are able to participate in such programs.

Underestimating the ability of customers to understand electric tariff designs is a mistake that simply reduces the number of service and pricing options available to residential customers. Given that such options are in many cases feasible, the result is fewer choices for residential customers, increased cross-subsidization, and potential increases in the utility revenue requirement, which could be avoided.

We agree that the introduction of new tariff designs, including demand charges, should include an education process for customers, but advanced pricing concepts should not be written off solely due to the perception that customers will not understand them.

Argument 4: Customers are Unable to React to Demand Charges

Some parties argue that customers cannot react to demand charges given the tariff design.  We reject this argument because:

• While at one time energy management systems were expensive and only available to large commercial and industrial customers, advances in technology have made energy control systems accessible to all customers. New strategies for customer engagement that are currently being deployed by utilities include load control technology, which is often necessary for the effective implementation of Real-Time Pricing.
• The lack of flexibility to react to a price signal, such as a demand charge, in the short run should not be an argument to ignore the price signal. Although the ability to react to a demand charge in the short-run may not be as great as the ability to react in the long-run (i.e., due to equipment choices and other capital investments), it does not dilute the importance of sending a price signal to the customer.
• The cost to react to a demand charge may exceed its value to a customer. The customer may have the ability to react to a demand charge but choose not to react due to competition for their resources and attention.

Argument 5: Distribution Investments Should be Recovered by an Energy Charge

The last argument proposes to recover the costs of the distribution system through an energy charge.  Recovering distribution costs through an energy charge is deficient on several fronts and should be rejected for the following reasons:

• Energy charges have nothing to do with the cost causation of distribution systems. The long-run marginal cost price signal associated with the distribution system is not communicated to customers through an energy charge. As a result, the system will be used inefficiently, increasing costs and potentially triggering non-economic investments.
• Customers with DER and net-metering have an artificially low load factor because the demand they place on the system is typically not reduced. Still, the measured consumption is decreased by the output of the DER. The costs of the distribution system are thus shifted to non-DER customers triggering cross-subsidies.

 How Should the Non-Incremental Cost of the Distribution System be Recovered?

A question that has challenged the utility industry for many years is how to recover costs which exceed the long-run marginal costs to operate the distribution, or “Residual Costs.” That question will be addressed in the next paper in our series “The Application of Access Charges.”

For more information on the topics discussed in this article, please contact Tom O’Neill.

More From Concentric:

Renewable Distributed Generation and Pricing Challenges

All views expressed by the authors are solely the authors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The authors’ views are based upon information the authors consider reliable. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.