Opening a new frontier in utility resource planning
Last week, the California Public Utilities Commission (CPUC) opened a new rule making for distribution planning that could have a major impact on market participants in the West. The OIR, officially named “Order Instituting Rulemaking Regarding Policies, Procedures and Rules for Development of Distribution Resources Plans Pursuant to Public Utilities Code Section 769” brings last year’s assembly bill 327 to life for investor owned utilities in California. It requires that IOUs file distributed resource plans (DRP) by July 2015 that define how they will integrate distributed energy resources (DER) on their systems. The new rulemaking recognizes that DER could potentially benefit rate payers by providing lower cost and more reliable service. Utilities must now define a methodology for planning for DER, for determining their cost effectiveness, and provide a roadmap for operating their systems with these new resources in place. Why is this important?
For developers of small scale technologies such as rooftop solar resources or combined heat and power, this is a long-awaited opportunity to play in the “big league” of utility planning—DER now need to be considered on the same basis as any other utility resource. This offers opportunities for better integration and for recognizing potential cost-effectiveness of DER, but it is also likely to expose potential free riding on grid-provided reliability. For example, recognizing the volatility of generation from solar PV and the costs associated with maintaining reliability could diminish their perceived cost-effectiveness, whereas more stable technologies such as combined-heat-and-power are likely to compare favorably since they offer the potential for base-load power on a small scale.
For California utilities, the new rule-making could offer significant upside. Utilities make money by investing in capital assets and earning a fixed and regulated return on equity—investing in distribution system upgrades to accommodate DER could therefore provide potential growth and expansion of the rate base. On the other hand, planning becomes much tougher. The rulemaking will likely require an apples-to-apples comparison of new resources—grid connected large scale supply versus DER while recognizing differences in the various cost components. The challenge is to fully account for costs and benefits in an integrated manner. For example, will a behind-the-meter investment by a developer in a combination of solar PV and energy storage offset potential upgrades of the distribution system substation? Will the same investment also offset the need for new generation and reduce ancillary service needs?
In recognition of these new planning challenges, many utilities across the US are transitioning from traditional siloed planning departments with separate functions for generation, procurement, transmission and distribution towards an integrated approach. But more is needed—modeling electric operations and costs is very complex and we need to be able to seamlessly integrate operations and costs in order to compare costs and cost-effectiveness of DER compared to conventional assets.
The new OIR seeks to define the planning process by asking a set of questions from stakeholders: What elements should the plans include, what methodology should be used to determine impact of location, what criteria should be considered in the planning process, should DER ownership be restricted, how should electric tariffs be structured, and so on. The CPUC requires the California IOUs to lay out a roadmap for integrating DERs, taking these questions into consideration. Approval of the DRPs is expected in March 2016.
In working with utility clients across North America, we have found that integrating utility planning functions to achieve a coordinated view of costs and benefits is very challenging and will require improvements in modeling tools and in the IRP process itself. At the same time, our work also suggests that under the right conditions, DER compare favorably against conventional assets and can indeed offer savings for rate payers as well as investment opportunities for utilities. But the key is rate design.
For rate payers, the question comes down to cost, reliability and emissions—will DER provide a lower cost, cleaner and more reliable supply of electricity? The figure below illustrates that trade-off based on actual electricity rates in California in 2013. If DER, on an incremental investment basis, can provide a solution that offers a competitive package of generation costs, transmission and distribution costs and reliability costs, than they are here to stay and poised for growth.