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Perspective published on May 16, 2019

Why Electric Bills Are Becoming Just as Complicated for the Utilities Themselves

The new year has brought with it almost a dozen states debating or passing laws that materially alter how electricity will be generated. In March, Nevada passed a bill requiring that 50 percent of the state’s electricity be drawn from renewable sources.1 Just last month, New Mexico Gov. Michelle Lujan Grisham signed legislation requiring the state to get 100 percent of its energy from renewable sources by 2045.2 California’s announcement last fall that it will become 100 percent carbon-free by 2045 was followed by the District of Columbia’s announcement in January that it has increased its renewable target to 100 percent by 2040, versus a previous target of 50 percent by 2032.

The more aggressive carbon-free targets being set by states highlight rising demand for alternatives to fossil fuels, which primarily includes solar, wind and nuclear. For electric utilities, the focus on clean technology and carbon-free resources means there is a new environment for generating revenue. In the past, electric utilities could generalize customers as simply wanting the lowest-cost, most-reliable power—regardless of how it was generated. Now, there is a more-disaggregated base of customers. Most have some opinion of “clean” energy and how much should be paid for it. Some customers place a premium on renewable energy, and believe that every effort should be made to shift toward clean energy even if costs climb; others do not. As states attempt to satisfy various preferences and opinions on clean energy, they will need to determine the type of energy provided and the best ways to make electricity costs equitable among rate-payers.

In this post, we discuss how prioritizing clean energy goals can sometimes burden U.S. electricity providers and prompt more contentious relationships between utilities and their customers. States’ clean energy policies may lead to rising costs for utilities, but the traditional assumption that utilities can just keep raising rates to support higher costs may be less accurate than in the past. With utility customers now more sensitive to the cost of their service, an erosion in customers’ willingness-to-pay their power bills could become a credit issue for some power issuers. In the near term, a franchise and revenue stream may remain stable. However, in the long run, a utility’s actions could erode customers’ desire to stay fully connected to a state’s power grid. If nothing else, customers are likely to complain to state and local lawmakers.

Assessing Revenue Stability in Power Bonds

Power bond issuers are generally very stable entities in which to invest. Power bonds finance the provision of electricity, and customers’ perception that electric service may cease if a bill goes unpaid generally ensures timely payment. Power bond issuers are also generally insulated from the labor and pension issues weighing on some state and local government issuers (see Thoughts on Modern Populism and the Muni Market).

Moreover, the business of providing electricity is likely to grow in the coming decades. Electricity demand is expected to increase due to clean energy transformations in the transportation and heating sectors. The Brattle Group estimates that, as the transportation sector shifts away from fossil fuel-based travel and toward an electric vehicle (EV) future, demand will grow by 2 percent annually through 2050.3,4 This figure’s significance can be understood by appreciating that the average 200-mile EV stores twice the daily energy consumption of the average U.S. household.5 Retail electricity prices are already rising faster than inflation, per the U.S. Energy Information Administration (EIA).6

However, utilities’ ability to impose further rate increases may be tested. Where customers perceive the increases as inequitable or as only benefiting customers who place a high premium on clean energy, passing along rate hikes may prove challenging. In some cases, higher electric rates may induce customers to seek energy from sources other than traditional utilities, especially when falling battery costs make cleaner sources more feasible.

Three recent episodes illustrate how the changing electricity market may impact revenue stability in the public utility space.

South Carolina

South Carolina residents pushed back against higher electricity prices in 2017 when the state halted plans to construct two nuclear reactors. As it became clear to customers that they would be left paying for a partially built plant in the form of higher utility costs, six bills were brought before the South Carolina Assembly to relieve rate-payers and force utilities to finance unrecovered costs.

The utility companies were probably too complacent about the willingness of customers to accept higher costs, in our view. Customers were no doubt mostly upset about having to pay for an unused nuclear plant, but South Carolina residents were already paying among the highest electricity costs in the United States, partially due to clean technology (Figure 1).7 The region commonly makes uses of heat pump technology to control indoor temperature. The pumps are typically used for air conditioning and are becoming more popular across the U.S.8 They have a lower environmental footprint than other comparable uses of power and can help reduce the use of fossil fuels for heating. While this can lower overall household energy costs, for oil or natural gas, it typically raises the portion of an energy bill paid to supply electricity to the heat pump. With higher electric bills already in place due to heat pump usage, South Carolina residents were unwilling to tolerate even higher costs related to the failed nuclear reactors.

More recently, the changing demand for electricity across the nation can be seen in one case in Arizona and another in Texas


Deploying more solar power can also impact a utility’s demand profile, as Arizona ratepayers are learning. In 2017, the Salt River Project (SRP), one of Arizona’s largest electric utilities, stopped what we think of as normal, volume-based energy pricing (“per gallon” or “kWh”), and made pricing substantially fixed for its solar owners. SRP justified the change on the grounds that customers with solar panels were paying too little for the option to access to the utility’s power when they needed it. (Solar customers continue to need access to power when the sun doesn’t shine or when residential battery storage runs out.)9 Solar panel customers ended up paying non-variable charges that could have reached above $100 per month. The approach was met with backlash.10 By making solar bills substantially fixed, while charging non-solar customers a traditional monthly usage fee, SRP’s rates became arbitrary.11

Arizona’s relatively low electricity prices make grid defection unlikely. But the SRP example suggests that a more-equitable approach could have been achieved and therefore, could have provided more predictability for the overall revenue stream that supports SRP’s bonds. Other utilities are facing problems similar to SRP, as states seek to reduce financial support for solar rooftop installations while adequately compensating solar owners for the costs they save utilities.


Texas’ deregulated market also illustrates how changing demand profiles can impact revenue stability. In Texas, there is a large wholesale power market where wholesalers need to stay price-competitive. However, today, there is also a growing recognition that a wholesaler can lose customers over more than price. Like their corporate counterparts that are seeing cities and towns shift business to renewable Community Choice Aggregators,12 wholesale municipal utilities can see unsatisfied customers defect. In 2011, the Lower Colorado River Authority (LCRA), a public wholesaler in Texas, lost nine customers (cities). The utility offered a mix of mostly fossil-fueled power at prices more expensive than were available on the state’s power exchange. Some customers left LCRA both because its prices were too high and because some of its customers were interested in cleaner sources of power.13

Georgetown, Texas was one of LCRA’s customers. After leaving LCRA, Georgetown pursued 100 percent renewable energy. Incidentally, that choice was met with difficulty. The utility sought to maintain a reliable source of power while shifting to renewable energy. In order to meet both goals, the city purchased excess renewable energy to offset any amount of non-renewable power automatically tapped whenever the wind and sun fall short. For Georgetown, these timing differences were brokered by risky participation in the power markets, leaving it less financially stable (see callout below).14,15

Georgetown’s choice to pursue renewable energy ended up costing the city more than it expected. In order to ensure a reliable supply of power, the city purchased excess renewable energy to offset any amount of non-renewable power; the non-renewable power would automatically be tapped when wind and sun power fell short. The city entered into some risky contracts that made it beholden to often volatile spot energy prices in the power markets, which left it less financially stable.

LCRA and Georgetown’s experiences underscore a tension among utilities’ rate-paying customers. Today there is a subset of communities and rate-payers placing a premium on clean power. Other communities are seemingly less concerned with the source of energy, and may stop doing business with wholesalers who choose more expensive 100 percent renewable, or carbon-free, power.16 The issue for investors may be less about which choice a utility makes, than whether it creates friction – and therefore instability – in the utility’s rate base.


In the coming years, we expect that more stakeholders will engage utilities over the costs and rate design for electric power. This could pressure power issuers’ ability to recover costs. Rate-payers will want more services for higher fees. They may desire to recover their own costs if they invest in technologies that they—and the grid—can benefit from (e.g., batteries). Lastly, communities’ views on the proper mix of electric power will inevitably lead to debate.

Breckinridge holds discussions with municipal leaders to help us gain a deeper understanding of an issuer’s risks and opportunities, particularly those that may not be evident from traditional financial statements (see Municipal Engagement Yields Additional Insights). Much of our recent engagement with utilities has involved evaluating how utilities engage with their own rate-payers. Higher costs and unique service demands have often created the customer friction that impacts credit quality.


[1] Steve Sisolak, , “Governor Sisolak Signs Bill to Raise Nevada’s Renewable Portfolio Standard to 50% By 2030,”, April 22, 2019.

[2] Breanna Goth, “Utilities to Go Carbon Free by 2045 Under Law in New Mexico,” Bloomberg Environment, March 22, 2019. Also,

[3] The Brattle Group, “Electrification: Emerging Opportunities for Utility Growth,” p1, January 2017.

[4] NREL shows TWh growth, to 2050, of up to 3,500, from a base EIA report as 4,014, as of 2017.

[5] Based on all-electric vehicles, with greater than 200 miles of EPA, with rated range meeting or exceeding 60KWh onboard storage. Taken from: The EIA recognizes average monthly electricity consumption of 897KWh, or 29.5KWh per day, taken from:

[6] EIA residential average retail electricity prices have risen 2.87%, versus the 2.07% rise in the CPI, from 2002-2017.

[7] U.S. Energy Information Administration, “Electricity prices are highest in Hawaii but expenditures are highest in South Carolina,” February 18, 2013.

[8] U.S. Energy Information Administration, May 1, 2019, data taken from

[9] The fixed monthly base charge was in addition to other easily-triggered residential demand charges to solar customers. 12KW of momentary seasonal demand would eclipse $100, leaving behind a $126 bill before the assessment of any additional “Per kWh” chargers. SRP’s E-27 customer generation plan, features demand charge breakpoints of 3KW and 7KW.

[10] Ryan Randazzo, “SolarCity sues SRP for antitrust violations,” The Republic, March 3, 2015.

[11] Owners of few panels can move from SRP’s standard rate-plan to a more economical solar plan; however, within it are prices low enough ($.036-.062/KWh) to challenge the payback of system expansion.

[12] Community choice aggregation (CCA), also known as municipal aggregation, are programs that allow local governments to procure power on behalf of their residents, businesses, and municipal accounts from an alternative supplier while still receiving transmission and distribution service from their existing utility provider. Source: EPA.

[13] See Georgetown information on the termination of its relationship with LCRA, located at

[14] Georgetown, Texas, website,

[15] Melanie Barden, “Georgetown electric bills could increase as city faces budget shortfall,” CBS Austin, January 18, 2019.

[16] Herman Tabish, “As 100% renewables goals proliferate, what role for utilities?”, April 2, 2019.

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