TODAY’S STUDY: Will Performance-Based Ratemaking Work In Hawaii?
Evaluation of Utility Ownership and Regulatory Models for Hawaii
June 2019 (London Economics International, et. al.)
The Hawaii Department of Business, Economic Development and Tourism (“DBEDT”), through House Bill 1700 (Act 124), was directed by the legislature to conduct a “study to evaluate the alternative utility and regulatory models,”1 (the “Study”) and “the ability of each model to: achieve state energy goals; maximize customer cost savings; enable a competitive distribution system in which independent agents can trade and combine evolving services to meet customer needs; and eliminate or reduce conflicts of interest in energy resource planning, delivery, and regulation.”2Through a competitive procurement process,3 London Economics International LLC (“LEI”) was awarded the contract for the conduct of the Study in March 2017.
The goal of the Study was to review and perform a thorough assessment of alternative models, laying out the pros and cons of each with respect to State policy objectives so that it could be used as a guide. As there is no single model that is best suited to achieve all objectives, the Study findings can help the legislature and stakeholders weigh alternatives as opposed to prescribe specific utility ownership and regulatory models to be implemented. The detailed discussions of analyses provided in individual task reports, which are summarized in this final report, are intended to provide enough information to assess how changes in assumptions and market conditions could impact the Study’s analyses and assessments.
The scope of work is divided into four parts, namely: (i) ownership models; (ii) regulatory models; (iii) additional analyses; and (iv) final report (Figure 1). The evaluation of potential utility ownership and regulatory models was performed through separate analyses but using a similar process and methodology. The Project Team additionally examined whether changes in the rate design could provide the same benefits as changes in the ownership or regulatory models and assessed the advantages and disadvantages of managing the State’s electricity sector with each county operating independently versus having a multi-county model.
1.1 Initial evaluation of ownership and regulatory models The Project Team initially performed a review of eight utility ownership structures (Figure 2) and six regulatory models (Figure 3). Sections 4.1 and 5.1 provide a more detailed discussion of these models. The Project Team conducted high-level analyses to evaluate each model’s pros and cons, financial, legal, and operational feasibility, the achievement of the state’s policy objectives, and potential stranded costs with the change in the model. It is emphasized that there can be wide variations even within ownership and regulatory structures.
The Project Team has described the models in the Study in a way that encompasses the most common forms. However, each model can be further customized to meet the needs of the State of Hawaii or the individual Hawaiian Islands.
Input from participants to the community dialogues was also taken into account. Three separate trips to each island (Hawaii, Maui, Lanai, Molokai, Oahu, and Kauai islands) were conducted to solicit stakeholders’ inputs on the Study: June 2017 (to discuss ownership models); July 2018 (to discuss regulatory models); and November 2018 (to present the preliminary findings). The Project Team also met with various stakeholders including representatives from the utilities, the Division of Consumer Advocate, commissioners, legislators, industry players, and non-government organizations. Moreover, an e-mail address4 was set up to collect feedback throughout the Study. All comments that were received were read, reviewed, and considered in the Study. Based on the conversations with the participants in these community discussions and one-on-one meetings, lowering electricity rates is the main (but not only) priority of stakeholders.
The Project Team selected six criteria with which to evaluate the chosen ownership and regulatory models, based on the four policy objectives established by House Bill 1700 (Act 124 of 2016). Figure 4 lists the state policy objectives and the evaluation criteria used to rank the different models.
The Project Team then performed a qualitative evaluation of the eight ownership models described previously with respect to each of the six ranking criteria, assessing how each potential ownership model would help achieve the state policy objectives absent any changes to the regulatory model. The high-level results of this assessment are presented in Figure 5 below and discussed in Section 4.4. The results were used to identify a subset of ownership models for detailed analysis, as further discussed in the next section.
Similarly, the Project Team performed a qualitative evaluation of the six regulatory models described previously with respect to each of the six ranking criteria, again assessing how each potential regulatory model would help achieve the state policy objectives. The high-level results of this assessment are presented in Figure 6 and discussed in detail in Section 5.5. Once again, the results of the analysis were used to identify a subset of regulatory models for detailed analysis, as further discussed in the next section.
1.2 Ownership and regulatory models selected for further study
Based on the high-level analyses, comments received from the community dialogues, one-on-one meetings, and the qualitative evaluation, four ownership models were selected for further analyses in all counties:
• Investor-Owned Utility (“IOU”);
• Cooperative (“co-op”);
• Single Buyer (“SB”) (inside the utility); and
• Single Buyer (“SB”) (outside the utility).
For Hawaii, Honolulu, and Maui counties, the Project Team selected four regulatory models for additional review, namely:
• Status Quo;
• Outcomes-Based Performance-Based Regulation (“PBR”);
• Conventional PBR; and
For Kauai County, the four regulatory models selected for additional review were:
• Status Quo;
• Hawaii Electricity Reliability Administrator (“HERA”);
• Independent Grid Operator (“IGO”); and
• Lighter Public Utilities Commission (“PUC”) Regulation.
The Project Team then conducted a more in-depth review of the selected models. The additional review involved determining the steps, timeline, and legal changes needed to transition to the selected models; the impact of the transition on the revenue requirements of the utilities, relative staffing needs of the Commission, ability to help Distributed Energy Resource (“DER”) integration, and ultimately, average costs to the customers; and understanding the funding mechanisms to transition or establish the models. Figure 8 summarizes the timeline, legal changes, and costs required to implement alternative models in moving to another model and Sections 4.10 to 4.12 (for ownership models) and Sections 5.12 to 5.14 provide a more detailed discussion of these analyses.
Based on the analyses, a regulatory or legal change is needed in most of these models, especially those that require the creation of an independent entity (SB, IGO, and DSPP). Transitioning to a different model also creates additional costs, including acquisition costs,5 regulatory costs, and set up costs.
The Project Team’s analysis results show that a change in ownership model does not necessarily address the first priority or concern of stakeholders, also a core objective of House Bill 1700 (Act 124), which is to lower electricity rates. In fact, a change in ownership model, either to the co-op model or the IOU model in the case of KIUC, would likely raise the average electricity rates relative to Status Quo in all the counties, except in Maui County. A key takeaway is that transitioning ownership models has a cost, regardless of the model, notably because of the cost for the new owner in acquiring assets from the incumbent utility. Figure 9 summarizes the impact on rates from the various ownership and regulatory models in all the counties.
More specifically, for Honolulu and Hawaii counties, a change to the co-op model is projected to increase average rates between 2018 and 2045 by an average of 5% and 8% per year, respectively. This increase is driven primarily by the cost of the purchase of assets of the incumbent utility, assumed to be undertaken through 100% debt financing. As a result, the co-op model is expected to lead to significantly higher debt burden, which would include interest payments. The higher costs of servicing the debt incurred for acquisition coupled with the additional financing needed for planned capital expenditure are expected to outweigh some of the cost reductions from the move to a co-op model in Honolulu and Hawaii counties. On the other hand, for Maui County, a move to the co-op model is projected to decrease electricity rates by an average of 2% per year. The projected decline in electricity rates would be primarily caused by the lower expected acquisition cost relative to the number of customers and forecasted sales, especially compared to Hawaii County.
For Kauai County, a change to the IOU model is projected to increase average rates between 2018 and 2045 by an average of almost 7% per year. Notably, a transition to an IOU model would increase the financing costs since IOUs have a higher weighted average cost of capital than coops based on their cost of debt and their cost of equity.
On the other hand, the analyses showed that regulatory changes are likely to have a more significant impact when it comes to reducing electricity rates. For example, the electricity rates are projected to decrease between an average of 0.5% and 9% per year as a result of regulatory changes, depending on the county (Figure 9). This is primarily driven by strong incentives, such as those typically provided in PBR. PBR models can be designed to incentivize the utility to lower different categories of costs through targeted measures. In addition, it was observed that the benefits of the move to any of the PBR options generally outweigh the costs.
For Kauai County, the Lighter PUC Regulation model results in lowest rates (average of 0.8% per year) because of lower anticipated regulatory costs for the utility. In contrast, the HERA model would increase the electricity rates slightly because it adds incremental expenses without direct financial benefits to the ratepayers. The benefits of HERA are more oriented towards the quality and reliability of service than cost reductions. Meanwhile, the Project Team expected some efficiencies in the IGO model, especially from the transfer of grid operations to a specialized independent entity that manages both utility-scale and distribution level supply resources. However, the overhead costs associated with setting up and operating an additional entity do partially offset cost savings associated with power procurement, especially in a smaller system such as operated by the Kauai Island Utility Cooperative (“KIUC”).
The potential ownership and regulatory models were also evaluated in terms of their impact on DERs, risks to the utility, staffing requirements for the Commission, and potential stranded costs. While these factors informed the selection of the highest rated ownership and regulatory models, the financial impacts discussed above must also be taken into account.
1.3 Additional analyses
The Project Team also performed a high-level qualitative assessment of whether the benefits of ownership and regulatory model changes can be achieved through changes in rate design (Section 7.1). The Project Team evaluated a range of alternative rate designs including tiered rates (inclining and declining block rates), higher fixed charges, and time-varying rates (Time-of-Use (“TOU”) rates, Real-Time Pricing (“RTP”), and Critical Peak Pricing (“CPP”)). Based on a highlevel qualitative evaluation of these alternative rate designs, the Project Team concluded that rate design changes can be effective complementary mechanisms to ownership and regulatory changes and could help achieve some of Hawaii’s state energy goals such as increasing the adoption of DERs and other consumer side resources, lowering peak demand, and encouraging energy conservation. At the same time, rate design is inherently interlinked with ownership and regulatory models and care must be taken to ensure that changes to rate design are consistent with overall policy goals in light of the prevailing ownership and regulatory model.
Finally, the Project Team evaluated the management of the State’s electricity sector with each county operating independently as compared to a multi-county model approach (Section 7.2). The single-county vs. the multi-county models were analyzed from the perspective of the utilities’ management and operations, particularly with regards to how the utilities operate the electricity system from sourcing supply to dispatching resources. The analysis showed that the multicounty model is better positioned to address the State’s priorities. It received a better rating in three out of five criteria, namely, the ability to meet state energy goals, maximize consumer cost savings, and enable a competitive distribution system. In contrast, the single-county model works better in addressing two of the five criteria, namely, conflicts of interest and aligning stakeholder interests. The sixth criteria, transition costs, was not within the scope of the study for assessing single versus multi-county models as it would require a detailed analysis of the costs and policy implications of interconnecting two or more of the island grids, which is outside the scope of this study.
1.4 Key takeaways
Based on the Project Team’s analyses, alternative regulatory models have a greater likelihood of helping to achieve the core policy objectives of House Bill 1700 (Act 124) relative to changes in utility ownership. This conclusion is further supported given that shortcomings of the current ownership models identified in the evaluation can be offset by changes to the regulatory model. For example, the legislature passed the Ratepayer Protection Act (SB 2939) of 2018 to address capital investment bias for investor-owned utilities under the existing regulatory regime.
The Project Team incorporated assumptions for its analyses based on publicly available data and existing studies on future developments of the State’s electric infrastructure. While the actual costs for a specific implementation of alternative models may vary from the chosen assumptions, the Project Team’s approach was selected to leverage data and studies that have been reviewed and approved by the Public Utilities Commission (“PUC”). This report and the supporting analyses provide enough detail to gauge the impact of changes in assumptions on the assessments contained within.
The Project Team concluded that a preferred outcome for the evolution of Hawaii State’s utility business model could include a PBR framework6 and possibly integrate alternative regulatory structures complementary to PBR. These alternative regulatory structures could be incorporated following the initial implementation of a PBR framework in Hawaii State, with decisions on whether, and how, to incorporate them being informed by developments in other jurisdictions which are currently exploring those concepts.
This Report is a summary of the analyses conducted for more than 40 underlying tasks and reports, which contain more background and additional details. These underlying reports are available on the Hawaii State Energy Office website.