PA Future Utility Part III: Philosophies of Change

Introduction

The “utility of the future” discussion is being examined in certain states in response to economic trends electric utilities are facing, namely an environment of increased costs and flat or declining revenues.  Increased costs are being driven in part by the need to replace old infrastructure, modernize the electric system, improve system resiliency and respond to public policy requirements (e.g. environmental regulations).  Increased penetration of distributed energy resources (DER) – like renewables, energy efficiency and demand response – and other factors are contributing to flat or declining electricity sales.  This higher cost, reduced revenue environment raises concerns for utilities that must manage investor, regulator, customer, and reliability expectations.  These challenges are prompting interest in the prospect for reexamining the utility business model status quo. Some clean energy advocates and vendors believe that current utility business models serve as a disincentive to energy efficiency and renewable energy growth, while consumer advocates may be concerned about strategies to incrementally adjust the existing utility model (e.g. increasing fixed charges and automatic capital expenditure trackers).

One thing is certain, there is no way to accurately predict the future. This fact increases the risks associated with predetermining an exact vision of the utility of the future.  Risks include making the wrong decisions about capital intensive investments, increasing customer costs, reducing economic development opportunities, increasing compliance costs, engendering public distrust, creating environmental damage, and more.  Given such high stakes, states and scholars have taken a gradient of approaches – ranging from incremental to transformative – when attempting to address utility industry challenges and opportunities.  Some of these approaches are identified below, as well as various stakeholder perspectives and questions about associated costs and benefits.

Incremental Adjustments to Cost of Service Regulation (Cost of Service Plus Model)

Some states have addressed specific challenges facing utilities and stakeholders by developing incremental adjustments to the traditional cost of service (CoS) regulatory model.  Many of these mechanisms aim to address the “revenue erosion effect” that can appear when load growth is low and DER penetration increases.  Utilities generally earn a profit by collecting revenues based primarily on volumetric ($/kilowatt hour) sales, demand ($/kilowatt) and a fixed charge to cover certain unchanging costs.  As DERs like energy efficiency and renewables increase, utilities will sell less electricity, leading to reduced utility revenue collection and profits (i.e. revenue erosion effect).  Regulatory mechanisms aiming to address the revenue erosion effect can include:

• Decoupling Revenues – This policy attempts to break the link between the amount of electricity a utility sells and the actual revenue it collects.  This is typically done through a “true-up” mechanism that aims to adjust actual revenues to amounts allowed in a rate case, therefore minimizing the revenue erosion impact of sales reducing actions (e.g. increased efficiency, renewables).  There are many policy design choices with respect to decoupling, as well as degrees or amount of decoupling that can be allowed.¹
  • Full Decoupling.  Full decoupling offers utilities the maximum amount of protection against deviations between actual sales and expected sales, ensuring that the utility’s revenue requirement established in the last rate case is achieved.
  • Limited Decoupling.  On the other end of the spectrum is limited decoupling, which only allows for revenue adjustments in specific cases.  For example, decoupling adjustments could be limited to lost revenues associated with changes in weather or in association with energy efficiency programs.
• Increasing Customer Fixed Charges – Changing retail rate design, specifically by increasing the fixed charge, can be an alternative to decoupling, according to LBNL.² Fixed charges to customers generally cover certain utility costs that do not change based on the amount of electricity sold (e.g. interest or depreciation expenses).  Typically, some fixed costs are incorporated into volumetric charges for some customer classes (i.e. residential and small commercial). Increasing fixed charges (e.g. minimum bills or straight fixed variable rate design) allow for more or all of the utilities fixed costs to be recovered through the non-volumetric charge.
• Reducing Net Metering Compensation – Net metering is a policy intended to promote distributed energy generation, which compensates these system owners for the electricity they provide to the grid. Net metering compensation can range from a very generous full retail rate to a lower rate associated with a utility’s avoided costs. All things being equal, as distributed generation system deployment increases, the amount of electricity utilities sell will decrease as will the amount of revenues the utility collects.  At certain penetrations of distributed generation, distribution utilities may experience increased costs associated with managing two-way power flows and variable generation.  In addition, net metering policies may also result in shifting a greater portion of fixed costs onto non-net metered consumers (as net metered consumers are paid by, or pay less to, the utility).  To address these issues, some states have limited net metering benefits by reducing compensation, placing fees on net metered systems or capping the amount of systems or generation that can qualify for net metering benefits.

These policies enable regulators to address specific challenges in an incremental approach, avoiding the risks and complexities of broader-scale changes.  However, these policies are not without their pitfalls.  Some consumer and efficiency advocates assert that if designed improperly, decoupling surcharges can increase rates and can reduce the consumer cost savings associated with participating in energy efficiency programs.  This concern may be especially true if aggressive energy efficiency programs are pursued that reduce utility sales growth, resulting in decoupling policies adding more surcharges to customers than refunds.³ Critics of high fixed charges maintain that these policies reduce customer incentives to pursue energy conservation and efficiency.  This is because a large portion of the customer’s bill is fixed, leaving a smaller portion (the volumetric charges) that can be lowered through efficiency and conservation.  Opponents of net metering reform argue that distributed energy systems provide valuable benefits to the grid and the environment, which warrant attractive compensation.  They point to the public policies that established net metering benefits as a reflection of a societal view point that values renewable energy generation and sought to promote compensation beyond the avoided cost construct afforded in the PURPA qualified facility program.⁴

The policies listed above chiefly aim to address the revenue erosion effect challenge.  There are additional incremental policies regulators have used to mitigate the “lost earnings opportunity effect.”  The lost earnings opportunity effect can occur when DERs reduce the utility’s opportunity to invest in assets, such as generation, transmission, or distribution systems.  Utilities earn a return of and on investments in capital intensive assets.  Investments in assets can be driven by growth (e.g. by increases in demand or number of customers) and by replacing aging equipment.  DERs like renewables, storage, and efficiency reduce utility opportunities for growth related capital investments, by reducing load and peak demand.  Some policies available to address the lost earning opportunity effect include:

• Shareholder Incentive Mechanisms.  These ratemaking mechanisms aim to provide shareholders with earnings opportunities if specific outcomes are achieved. Most of these programs have been used in association with energy efficiency programs, but could be applied to DER programs.⁵
  • Shared Savings Mechanisms – This mechanism allows the utility to enjoy a portion of the net ratepayer benefit achieved through a specific program.
  • Performance-Based Incentives – This policy provides bonuses if certain program metrics are achieved.  For example, if 90% of an efficiency target is reached, then a bonus of x% of program costs is awarded.
  • Cost-Capitalization – This policy allows utilities to include efficiency program costs in their rate base, and may also allow for a higher rate of return.
• Performance-Based Ratemaking.  This is a type of shareholder incentive mechanism, but it is more broad-based as it is a new approach to ratemaking, rather than a program-based incentive. In this scenario, the regulator defines the desired outcomes and goals that matter to stakeholders.  Utilities are rewarded based on achieving or exceeding these goals and penalized for underperformance.  This type of ratemaking may promote utility innovation and upside potential, but may also expose utilities to greater risk.
• Infrastructure Replacement Riders. These policies generally focus on replacement of existing equipment and enable utilities to more timely recover (i.e. outside of a rate case) costs associated with addressing safety, reliability, and other critical system concerns. This policy enables utilities to make asset investments and enjoy returns, as long as specific criteria are met.

Critics of shareholder incentive mechanisms argue that these policies only promote utility value for new utility investments and do not create incentives to maximize the value of both new (including non-utility) and existing assets.  Some contend that the performance-base ratemaking can be easily gamed if performance metrics are not chosen carefully, and measured and reported accurately. Critics of infrastructure replacement riders argue that these policies amount to automatic rate increases that lack public transparency and traditional regulatory oversight.

More broadly, it is unknown whether or not the cost of service plus model will lead to long term economic viability for utilities.  Many suggest these incremental adjustments are stopgap measures aimed at either curtailing losses or making utilities neutral towards DERs.  It is unclear if these strategies are sufficient to promote greater utility interest in DERs or facilitate utility innovation in these sectors.  On the other hand, critics of fundament transformation approaches – to be discussed in the next section – fear that the costs of rapid, broad-based changes to utility business models are unknown and benefits are unproven

Fundamental Transition

Some jurisdictions may conclude that incremental changes to the existing utility regulatory model are insufficient to achieve certain goals and that more fundamental changes are required.  There are a wide range of concepts and theories about what fundamental utility business model transformation could look like, all of which are relatively untested in the United States.  Below is an overview of a few of these transformational concepts that range from minimum to maximum utility involvement in the transition to a next generation energy system.

• Dissolving the Utility Monopoly (Minimal Utility Involvement). This extreme conceptual approach asserts that innovation cannot occur in the regulated monopoly utility structure and that true innovation can only come in the face of competition.  The theory suggests that existing utility lines of business can effectively be opened to market forces and deliver greater benefits to consumers.  This, of course, challenges the economic principles underpinning the distribution utility’s long-standing natural monopoly status.  Supporters point to the telecommunications industry where new technologies (like mobile phones) drove the erosion of the telephone company industry’s regulated monopoly and draw parallels with the evolution of electricity industry technologies. Some preliminary questions with this model include: Given the capital intensive nature of energy system investments (from large to small scale), will multiple entities in competitive markets be able to cost effectively provide similar or better service?  Are consumer-based technologies in the telecommunications industry an appropriate parallel to energy system technologies, both in function, costs, services, and externalities?  How will capital be amassed and deployed for long horizon investments in energy system improvements?
• Smart Integrator⁶ or Independent Distribution System Operator (Medium Utility Involvement). This concept would emphasize the distribution utility’s role as a regulated smart grid network operator and minimize its role in commodity sales.  The primary function of the utility would be to integrate and balance supply (local and upstream), storage, and demand to ensure reliability and technology integration, much like an independent systems operator (ISO). The utility could also offer energy and other services (e.g. information, customer grid management) at regulated prices.  This model enhances the importance of data sharing and the role of competitive network users in delivering services to customers and the network. Some preliminary questions with this model include: Does this model create sufficient value proposition for utilities or does it erode their growth potential by greatly limiting allowable activities? Do the benefits of this model outweigh the costs associated with the degree of restructuring required to enable this model?  Will some customer classes be underserved by these new competitive markets? Will suboptimal, anticompetitive behavior result due to reduced regulatory oversight of competitive business segments?
• Energy Services Utility⁷ or Integrated Electricity Services Provider (High Utility Involvement). This concept would develop a customer service-centric business model, where the utility is strongly incentivized to get in the business of delivering energy efficiency and distributed generation, as well as providing other services that customers may want.  This scenario assumes the utility is engaging in many of the activities of the Smart Integrator, as well as expanding its service offerings.  As a provider of end-use electricity services, the utility could charge a monthly subscription fee in exchange for bundled energy services.  These utility services could be customized to user needs based on peak capacity, reliability guarantee, on-site customer generators, capacity aggregators, etc.  In addition, market access could be opened to other entities to allow non-utility vendors to compete to offer similar services. Some preliminary questions with this model include: Will regulated utilities be able to deliver the product innovation and differentiation needed to make this model function? How will regulators ensure utilities do not abuse market power and shut out competitors or preferentially treat affiliated services? What regulatory mechanisms will be used to ensure performance and ratepayer value?
• Financial Intermediary Company or FinanceCo Model. This model may be compatible with, or an aspect of, the models listed above.  This concept involves the utility leveraging its access to low cost capital and existing billing systems to provide financing services to customers and non-utilities for DER and other energy system investments.  This model also leverages the customer and vendor relationships of the utility. Some preliminary questions with this model include: Does the utility offer enough benefit or value in this model to develop a viable growth strategy around? Does this model create systemic value for the utility or enhance the position of its competitors? Given historic utility bond rating declines and increased risks (non-payment or non-performance risk) associated with these financing activities, will utilities maintain their low cost capital advantage?

To complicate matters, all of these conceptual new visions for utility business models would need to be complimented by new market and regulatory structures to ensure effective implementation.  Simply asking the question of, “what should the utility business model look like in the future?” is not enough.  One must also consider how the utility will be regulated and if that system of regulation is compatible with achieving the new vision. Developing the utility of the future will be complicated, risky, and highly specific to each state or jurisdiction. In Part IV of the digest series, we will examine how some states are choosing to approach the future utility issue.

Christina Simeone

Kleinman Center Senior Fellow

Christina Simeone is a senior fellow at the Kleinman Center for Energy Policy and a doctoral student in advanced energy systems at the Colorado School of Mines and the National Renewable Energy Laboratory, a joint program. 

Additional Sources

Interstate Renewable Energy Council, Inc, “Connecting to the Grid: 6^th Edition,” 2009, available at  http://www.irecusa.org/connecting-to-the-grid-guide-6th-edition/

Lehr, Ronald, “New Utility Business Models: Utility and Regulatory Models for the Modern Era,” American’s Power Plan, 2013, available at http://americaspowerplan.com/wp-content/uploads/2013/10/APP-UTILITIES.pdf

Massachusetts Institute of Technology, “The MIT Utility of the Future Study, White Paper,” December 2013, available at https://mitei.mit.edu/system/files/UOF_WhitePaper_December2013.pdf

1. Lazar, Jim, Weston, Frederick, and Shirley, Wayne, “Revenue Regulation and Decoupling: A Guide to Theory and Application,” Regulatory Assistance Project, June 2011, available at www.raponline.org [↩]
2. Satchwell, Andrew, Cappers, Peter, Schwartz, Lia and Fadrhonc, Emily, “A Framework for Organizing Current and Future Electric Utility Regulatory and Business Models”, Lawrence Berkeley National Laboratory, June 2015, p.19, located at http://emp.lbl.gov/publications/framework-organizing-curr (Herein Satchwell et al) [↩]
3. Satchwell et al, p. 18 [↩]
4. Prior to net metering policies, distributed generation systems would get certification as a qualified facility (QF) under the federal Public Utility Regulatory Policies Act (PURPA) and would receive compensation for energy exported to the grid at the utility’s avoided cost rate.  Some maintained that the avoided cost rate was insufficient to incent customers to invest in the excess generation capacity needed to deliver exports, resulting in customers sizing systems to meet minimum on-site demand. [↩]
5. Satchwell et al, p. 20 [↩]
6. Fox-Penner, P. (2010) Smart Power: Climate Change, the Smart Grid, and the Future of Electric Utilities. Island Press. [↩]
7. Fox-Penner, P. Smart Power [↩]