TODAY’S STUDY: Rewarding Utilities For Giving Customers What Customers Want
Utility Earnings In A Service-Oriented World; Optimizing Incentives for Capital- and Service-Based Solutions
Danny Waggoner, Thomas D’Ambrosia, Kent Bond, et. al., January 30, 2018 (Advanced Energy Economy)
Throughout the economy, companies are finding efficiencies and operational benefits by meeting their needs through services provided by third parties rather than investing in physical assets that they own and manage.1 Utilities are no different. However, the trend toward services has faced some unique barriers in the investor-owned utility industry, as utilities have an issue in their underlying business model, imposed by regulation, that most other businesses do not.
In the current cost-of-service regulatory model, which has served the sector and customers well for many years, capital investments are a large driver of returns to utility shareholders. Utility investors are allowed to earn a rate of return on net invested capital (gross capital minus accumulated depreciation). In contrast, operating costs (such as fuel, labor, maintenance, and service expenses)2 are generally passed through to customers in electric rates without the utility making any direct profits on them, although utilities remain incented to manage operating costs to reduce overall cost to customers, and also to manage profits between regulatory rate reviews.
Over the long term, however, services that can improve the utilization of, defer, or replace capital investments may have the effect of reducing opportunities for utilities to generate earnings. Because many new technologies are offered only as a service, utilities may be discouraged from using them. Realizing that both customers and utilities stand to benefit from equalizing the earnings opportunities between traditional capital solutions and service solutions that reduce capital investment needs, several state commissions have explored or implemented mechanisms to compensate for the bias toward capital investments that is inherent in cost-of-service regulation.
Regulated utilities spend billions of dollars each year on infrastructure to meet their obligation to deliver safe, reliable, affordable service to customers in an environmentally acceptable manner. The majority of capital investments in the power grid today are related to reliability, replacement of aging equipment, accessing renewable energy, and the installation of environmental controls. A smaller portion, primarily capital investments related to capacity expansion and IT systems, presents an opportunity for deferral or replacement by a service solution.
We identified several different regulatory treatments that states are using or piloting for services that replace capital investments. Some of these mechanisms, such as capitalization of a service contract or the use of regulatory assets,4 are available today without the need for changes in regulation. These mechanisms allow utilities to place “service assets” in their rate base and amortize them like capital investments. Other regulatory mechanisms require changes in regulations and are designed to provide financial incentives to utilities that better align their earnings with their ability to generate cost savings.
This paper utilizes financial models to explore the impacts of several different regulatory mechanisms for encouraging utilities to pursue service-based solutions. Based on this exploration, the paper makes some general recommendations for implementation.
The specific service-based solutions assessed in this paper are very different in type: cloud computing services, which take the place of utility investments in on-site computers, servers, and software; and distributed energy resources5 (DER), which defer or avoid utility investments in distribution equipment and infrastructure by contracting for the services provided by customer- or third party-owned assets such as solar installations, battery torage, or demand response. Additional use cases exist that this paper does not model, such as energy efficiency programs or Power Purchase Agreements that replace utilityowned generation, but the same regulatory concepts generally apply.
For these two service-based solutions, we looked at five alternative regulatory mechanisms in comparison to two status quo mechanisms that represent common regulatory practice. The first mechanism, which we refer to as the Reference Case, reflects standard practice for recovering the cost of a capital investment by depreciating the asset in a utility rate base over a period of years (often 20 to 40). The second status quo mechanism, Service as O&M, reflects common practice for accounting for a service solution (in lieu of a capital investment) in which there is minimal opportunity for earning a return on the service expenditure. The other five alternative mechanisms are new options that aim to provide better outcomes through providing earnings opportunities on services. The five alternative mechanisms considered are as follows:
DER Incentive Adder (“DER Adder”) – This option functions similarly to the Service as O&M option, except that the utility receives 4% of the total cost of the periodic payments for the service solution as an incentive to compensate for the utility’s avoided earnings.
Capitalization of a prepaid contract (“Prepaid Option” or “Prepaid Contract”) – This option employs a prepaid asset, a commonly used form of cost recovery for utilities, which treats an expense similar to a physical asset by placing it into the rate base, amortizing it, and recovering it over time. In this case, a service payment would be pre-paid for a number of years and would be amortized over the length of the contract. The utility would collect its yearly carrying costs, including return for the investors’ equity, based on any unamortized balances.
Non-Wires Alternative Shared Savings (“NWA Option”) – The NWA Option functions similarly to the Prepaid Contract because it is based on a prepaid service that the utility recovers as a regulatory asset. However, an additional earnings incentive is provided on top of earnings from capitalizing the prepaid contract to compensate for lower earnings when the service costs less than the Reference Case. The utility shares in 30% of the present value of the total savings when compared to the Reference Case. The shared savings are applied in equivalent increments on a yearly basis for the length of the service prepayment.
Modified Clawback Mechanism (“Modified Clawback”) – This option is an adjustment to the net capital plant reconciliation, or “clawback,” mechanism, which is used in some states to reclaim the unspent portion of a capital budget, plus the associated earnings, in the event that a utility does not spend its full capital budget. The Modified Clawback Mechanism leaves intact any portion of the capital budget that goes unspent because the associated investment was replaced with a service expenditure. Any positive difference between the original amount in the capital budget and the service cost paid through O&M is retained as profit. In the next rate case, the capital costs associated with the avoided project are removed from the capital budget and the O&M budget is increased to provide rate recovery for the service expenditure.
Pay-as-you-Go (“PayGo”) – This option combines a number of features from the mechanisms outlined above. Under PayGo, the utility prepays a service expenditure for one year at a time and places the prepayment into the rate base as a regulatory asset. With authorization from the state utility commission, the utility would amortize these regulatory assets over a period greater than one year. In our model, the amortization rate, based on one-third the life of the service contract, is applied to the prepayments as a group. Thus, the regulatory asset would build year-on-year while simultaneously being amortized. In addition to these earnings from rate base, the utility receives a variable shared savings incentive proportional to the cost savings provided by the service option. For example, if the all-in costs of the service solution are 25% less than the Reference Case, the utility would take 25% of the total savings.
We also examined these regulatory mechanisms under three different scenarios: short-term replacement of a capital investment expected to last for five years; short-term deferral of a capital investment for five years; and long-term replacement of a capital investment expected to last for 40 years. We further evaluated the regulatory mechanisms in two different cost scenarios, or cost cases. The first, the Equivalent Cost Case, assumes that the service solution costs are approximately the same7 as the Reference Case capital investment in order to test how efficiently the mechanisms render costs to customers and provide earnings for the utility. The second, Lower-Cost Case assumes that the service solution costs 25% less than the Reference Case capital investment to measure the impact of the shared savings functions in some of the mechanisms. 7 Utility capital investments and third-party service solutions have different underlying costs, taxes, and other factors that make a direct comparison of total solution costs complicated. We explain this in more detail on page 40 in the section titled “Making an Accurate Comparison.”
The findings are encouraging. As the figures below show, when a service solution is available at equal or lower cost to customers than in the Reference Case (in net present value terms), the five alternative mechanisms in many cases also provide equivalent or greater earnings8 to the utility – a win-win for consumers and utility shareholders. In the figures below, a “win-win” is when an option is both above and to the left of the Reference Case.