A central theme of many articles and blogs on the future of the electrical power market is the massive amount of innovation in the types of products and services energy providers offer customers and the rapidity of changes that will introduce new products and services. The energy ecosystem is undergoing rapid transformation with diverse and creative energy technology such as residential storage, distributed energy resources, enhanced demand response, and E.V. charging control. New approaches and product offerings are continually emerging, each potentially upending previous state-of-the-art products. Flexibility and speed in responding to customer needs will be critical to success.
Parts of the market are positioned to respond to these opportunities, but others are not. An entity that can rapidly develop and implement new energy products and services has a better chance of prospering. However, most regulated utilities will struggle to move quickly enough to bring the same level of innovation to their service territories. Because of oversight necessary for the utility monopoly, this speed is seldom possible at this moment. Can innovation in the utility oversight model address this issue? This blog post will discuss a few aspects of this question.
Flexible Rates of Retail Electric Providers
Many areas in the United States have transitioned to a deregulated electric market where customers can choose their energy provider. Although an incumbent utility may own and operate the distribution and transmission systems that carry the power to the customer (the “wires company”), the customer can choose from whom to buy the actual electrons. (The charge for T&D is added to customers’ bills – this is the “wires charge.”)
The pricing for the physical power, however, is entirely up to what the Retail Electric Provider (REP) thinks can be sold in the market and can be as flexible or as rigid as needed to fit the desires and values of various customer segments. For example, one customer may wish to pay a flat rate every month; another would like the option to shift electrical use to off-peak times for a price break; still, another may want 100% renewable energy.
Because the electricity market can shift and change quickly and is susceptible to rapid changes due to technology, there is a need to shift and change offerings in response to the market changes or customer preferences. REPs have great flexibility in their offerings to customers. New pricing plans can be developed and implemented relatively quickly. Retail electric providers have experience developing these products, sourcing the wholesale power to back them up, and managing their market risks in doing so.
This flexibility is necessary because customers commit to specific plans for specified periods then are free to move to a different plan or even a different provider. The customer has choices. This method has incentivized agility by REPs in responding to market changes and positions them well for success in the future dynamic energy landscape.
Nonflexible Rates of Regulated Utilities
Electricity customers in regulated areas do not have access to a flexible rate choice. Who are these customers? According to RMI, 6% of all utilities operating in the United States are Investor Owned Utilities (IOUs), yet they serve 68% of all electricity customers. Some are vertically integrated utilities, meaning the generation, transmission, distribution, and customer service are all within one company. Other IOUs are transmission and distribution only – customers choose their energy providers.
The majority of utilities (over 60%) are municipally-owned utilities, generally owned and operated by cities just like other infrastructures like gas and water. However, only 15% of all electricity customers are served by “munis.” Electricity Cooperatives represent 25% of utilities in the U.S., with 13% of customers.
Since IOUs, munis, and co-ops are monopolies, their rates are regulated. The utility’s costs are closely tracked by their regulating entity to ensure its power is sold at a fair price. In the case of IOUs, it’s the state Public Utility Commission; with munis, it’s usually the city government; and with co-ops, it’s their elected board, generally made up of customers. The broad objective of the regulators is to review the costs of operations and capital investment incurred by the provider and approve rates (prices) for electricity that should enable the utility to recover its costs.
Looking deeper, each customer’s bill usually has a fixed component to ensure the utility covers its fixed costs and a variable component based on the customer’s electricity usage. For electricity produced by coal and natural gas, up to 90% of the costs are due to the underlying fuel cost. The bills will be lower during months of mild usage due to lower variable costs. In high electricity usage months like deep winter or the peak of summer, electricity usage is high, more fuel is used, so bills will be higher. While the variability of usage enables recovery of costs due to truly variable usage, the fuel prices themselves are subject to volatility, so most regulated utilities are allowed to add some type of fuel adjustment to the customer’s bill so that additional fuel-related costs (above a set baseline) can be recovered.
How Do Regulated Utilities Set Rates?
This mechanism of setting prices for regulated utilities, municipal utilities, and electric cooperatives is by necessity deliberate and thorough. The utility must analyze, review, and present its costs (including estimates of future costs), along with the assumptions that went into these forecasts. Capital expansion plans must be presented to include why certain alternatives are preferred instead of others. Due to this complexity, rate cases can take a year to prepare and months to gain approval. In the meantime, economic conditions may change, intervenors may file comments and disputes, and other shifts can occur. As a result, the utility may not get approval for the total amount requested; the approval may be delayed or completely rejected.
Even after approval, implementation of the new rates can still take longer. Sometimes there are challenges to new rates in court. Once officially adopted, the new rates have to be programmed into billing systems, and customers must be informed, requiring more time. In summary, the current environment for setting rates for many of these entities is slow and uncertain, and not well-suited to the future dynamic energy landscape.
Should Regulated Utilities Seek Flexible Rates?
As mentioned earlier, the energy landscape is undergoing a massive transition, from the widespread adoption of renewable (but intermittent) generation to the proliferation of demand-side options such as energy storage, E.V. charging, and distributed energy resources. One of the effects of this is changes in customer usage patterns, including decreased energy usage in some cases. This change has meant that many utilities are finding their fixed costs of providing reliable, around-the-clock service increasing, while the volume of electricity sales is not increasing at the same rate. As a result, some find that 60% of their costs are fixed, while 90% of their revenue is variable. This issue creates a disincentive for the utility to promote these very technologies and products.
While there may not be direct retail electric competition inside the utility’s service territory, customers in these areas can easily find out what prices are being charged in neighboring competitive regions. They also can see what kinds of products and services are available elsewhere, but they have no access to the competition. New businesses could seek locations that provide electric choice, away from the regulated utility’s service territory, leading to economic consequences.
Utilities need the ability to change rate structures to keep up with changes in the industry and provide choices to their customers. They also need to ensure they are recovering their costs with just and reasonable prices, with little cross-subsidization across customer classes. What approaches are useful in resolving these concerns?
What Can Be Done to Update the Electric Rate Regulatory Model?
Reduce Regulatory Lag
As mentioned previously, the immense effort and time involved in gaining approval of new rates are a barrier to introducing new and innovative product offerings. A possible approach to speed this up would be to establish limited tariffs that allow regulated utilities and municipals to adopt and offer pricing schemes that are not tied to the cost basis of the company’s last rate case but tied to the pricing available in nearby deregulated areas. The notion is that the regulated utility is operating in the same environment and market as the surrounding areas and will experience the same economic pressures (inflation, fuel prices, etc.) and that prevailing prices could substitute for the total cost study-based pricing.
This approach would have two significant effects:
1. Rates charged by the regulated utility would keep up with the competition within the same region, helping to ensure the utility is not disadvantaged by competitors in the wholesale market or suffer economic development losses.
2. It would enforce discipline on the regulated utility to contain costs to maintain profitability under competitive pricing. While this may disrupt the current financing advantages of monopoly utilities (guaranteed return on capital), it would address many customers’ concerns about higher prices on this side of the highway versus the other side.
Even if this approach could not be implemented comprehensively, it could be allowed for a certain fraction of the customer base or a certain fraction of the utility’s expected revenue target. To address concerns about whether costs are covered and adequately allocated, a periodic cost/revenue review with the regulator would serve to assure compliance to pre-negotiated metrics, targets, and goals. The utility or municipal must satisfy the regulator that the prices were just and fair based on market conditions and the costs required to serve that customer segment.
This “market-comparison” based rate-making for regulated entities could evolve into a flexible, innovative suite of products and pricing that could unlock the potential of demand-side resources in helping balance the grid of the future.
Refine Capital Investment Decision Models Using Incentives
One of the issues in standard cost-of-service models is the disincentive to invest in energy efficiency or distributed energy solutions. These activities drive down consumption, and revenue, without decreasing infrastructure investment by the utility.
Further, since IOUs are allowed to recover capital costs plus a reasonable return, their incentives are to grow their base of capital assets. For example, the shareholders benefit from more investments in power plants than measures to reduce energy consumption, such as demand response programs.
One way to untangle this knot is to create an incentive model where the utility is made whole to not invest in a given asset and is financially agnostic to choosing a “traditional” solution and a solution that advances energy efficiency. For example, right now, a utility that plans to invest $10 million in improved distribution infrastructure has all the incentive to do so. The utility will fund the investment with debt, and the debt service will be recovered from the customers, plus enough to ensure the shareholders will gain a return on this capital.
What if the utility could invest in distributed energy resources (solar, storage, etc.) and offer energy efficiency incentives to customers to reduce usage at a lower cost? Currently, this is disincentivized: shareholders miss out on the opportunity to gain a return on the $10 million capital. If the utility’s regulator, however, allowed the utility to recover a small return on the avoided investment, then the entire package of DER, energy efficiency incentives and this small return could be less expensive than the original $10 million proposition. The financial alternatives are equal, but the benefits of the DER/EE choice could win out.
Periodic Readjustment of Fixed Versus Variable Charges
As mentioned earlier, the mismatch between fixed costs and variable revenue has placed many utilities in a financial bind. Rate increases on the variable component, ignoring the fixed charge, push the problem down the road. Addressing the rate structure is essential to the sustainability of the company’s business. For example, large infrastructure investments will be necessary to enable distributed energy, residential solar/storage, and distribution-based solar/storage to become a larger and larger portion of the utility’s power supply. These investments will incur fixed costs of operations, whereas the energy cost component will be comparatively smaller since many customers will be self-generators or only need the utility for backup.
A regulatory regime wherein the utility calculates an annual fixed cost factor to recover, which is then automatically introduced into the rate, will help balance revenue type with cost type. Just as the fuel adjustment factor passes fuel costs through, the fixed cost factor process could do the same. It would require new business practices and regulatory approval procedures, but it could be a start.
Future of the U.S. Electricity Market
In many parts of the U.S. electricity market, regulated utilities, municipals, and co-ops comprise a significant if not a dominant presence. Business-as-usual in setting prices these entities can charge will not be well suited to the dynamic, quickly changing future of energy supply. Innovation must be made in this area for significant progress to evolve those markets into the future. New regulatory approaches, cost recovery techniques, and products and services are needed in this vital industry area.
If you’re interested in reading more about energy rates, check out “What is Driving Your Electric Bills Higher” on the PCI blog.