In the wake of the implementation of the 2017 Tax Cuts and Jobs Act (TCJA), many utilities and their holding companies are experiencing increasing pressure on cash flow due to the elimination of bonus depreciation, the flow-through of the reduction in federal income tax rates, and potential limitations in the deductibility of interest expense.
Implications for the Utility Ratemaking Model
The longstanding utility ratemaking model provides regulated utilities with the ongoing recovery of a return on and of capital investments up to a certain point. That point being the maintenance of rate base at the level approved in the last general rate case. Generally speaking, if capital expenditures are equal to or less than depreciation expense, or can be funded through sales growth, a utility can work within this model without a need for constant general rate cases.
However, current business demands typically result in capital investment needs far in excess of those amounts funded by depreciation expense. And for many utilities, sales growth is constrained as a meaningful source of capital program funding due to energy efficiency and demand reduction programs. Funding for capital programs is further reduced through the elimination of bonus depreciation as part of the 2017 tax act.
For some utilities, regulatory mechanisms facilitating the recovery of the return on and of rate base growth outside of a general rate case provide an opportunity for utility management to improve cash flows and mitigate regulatory lag. For regulators, adjustment mechanisms can lower the administrative burden of a perpetual rate case.
A number of utility regulatory jurisdictions already have such mechanisms in place to address the need to fund inter-rate case rate base growth while mitigating regulatory burdens on both the regulator and utility that result from a cycle of perpetual rate cases. A few examples of these mechanisms are discussed below.
In Illinois, the Energy Infrastructure Modernization Act (EIMA) provides for recovery of certain types of capital investments outside of general rate cases. For Chicago-based Exelon, capital recovery mechanisms, including those authorized by EIMA, cover the bulk of the company’s rate base growth, as noted in Exelon’s April 2018 Investor Meeting presentation.
For transmission and distribution utilities in the Electric Reliability Council of Texas region, the state offers both transmission and distribution cost recovery mechanisms. While not directly linked to the recovery of all intra-rate case investments in utility plants, the Alabama Public Service Commission offers the Alabama Rate Stabilization and Equalization Plan as an alternative regulatory mechanism. For Alabama Power, a subsidiary of Atlanta-based Southern Company, for example, the mechanism adjusts the company’s base revenues and rates to keep the expected return on equity within the authorized range. To mitigate rate shock, annual rate increases may not exceed 5% and the average annual rate increase over any two-year period may not exceed 4%.
In Massachusetts, Eversource’s 2017 rate order in Department of Public Utilities D.P.U. 17-05 accepted the company’s proposal to implement a performance-based ratemaking (PBR) mechanism that would allow each Massachusetts operating company to adjust its distribution rates on an annual basis through the application of a revenue-cap formula. Within the PBR mechanism, the companies proposed to undertake $400 million in incremental capital investments over the next five years on projects the companies state are designed to integrate distributed energy resources and improve service reliability, including projects to develop electric vehicle infrastructure and electric storage capabilities.
In several jurisdictions including California and New York, commissions use multi-year rate plans as a means to recognize inter-period capital expenditure needs. However, these plans do not provide a blank check, but instead include certain accountability requirements. Other states, for example Indiana and Pennsylvania, provide distribution system improvement charge mechanisms. In the case of Indiana, electric and natural gas utilities must submit seven-year infrastructure improvement plans for the Indiana Utility Regulatory Commission (IURC) to approve. Once a seven-year plan receives IURC approval, the utility may request incremental rate increases every six months to pay for up to 80% of project costs limited to no more than 2% of a utility’s total retail revenues. The remaining costs are deferred until the utility’s next base rate case, which must be filed before the end of the seven-year period.
In some cases, these types of mechanisms support specific programs such as the replacement of low-pressure gas mains and services with outcomes in line with regulatory objectives.
Capital Investment Recovery Strategies Key
Looking ahead, utilities can position themselves for success by utilizing a variety of capital investment recovery strategies to improve cash flow. Capital investment recovery mechanisms provide utilities with opportunities to improve both cash flow and earnings to mitigate the impact of declining cash flow resulting from the TCJA.
Utilities in states with no current cost recovery or alternative regulatory mechanisms in place will benefit from pursuing these options and there are a variety of models in place to consider. Most mechanisms require accountability or incentive components. Utility managers are forewarned, however, that advocating for these mechanisms may also require demonstrating that investment category programs or major projects are incremental to capital expenses funded through depreciation and increased sales. ■
—Joel Jeanson is an energy and utilities expert at PA Consulting.