A little over a year ago, in an update on New York’s groundbreaking Reforming the Energy Vision (REV) proceeding, we wrote that the “devil is in the details.” Today, we have a lot more details. In late July, the Public Service Commission issued its “Staff White Paper on Ratemaking and Utility Business Models.” As the title suggests, this document makes initial proposals to change how utilities make money (the business models) and how they would charge customers to reward certain behaviors and discourage others (ratemaking). As with other participants in the proceeding, we have spent the past three months poring over this White Paper and thinking through the benefits and risks to advanced energy companies of its various provisions. Although the details are still devilish, the REV vision of a dynamic electric power system built around energy efficiency, onsite solar and wind, energy storage, cogeneration and microgrids, and other distributed resources, rather than a static, one-way system of central power plants, poles, and wires, continues to look bright for advanced energy.

Although many pieces of REV are still in motion, the white paper on ratemaking and utility business models represents a very significant component. That’s because it outlines, for the first time, a framework for how money would flow between utilities, third party providers of energy products and services, and customers. Specifically, it attempts to better align the utility profit motive with the policy goals of REV. Many details remain to be hashed out, but the white paper gives us enough information to envision how the business of electric utilities - how they relate to customers, how they relate to other companies that do business with them and their customers, and how they make money - would change with the implementation of REV.

Along with about three dozen other interested parties, Advanced Energy Economy Institute, working with its partners, Alliance for Clean Energy New York (ACE NY) and the Northeast Clean Energy Council (NECEC) filed detailed comments on the White Paper, continuing our deep involvement in the REV proceeding since it started in the spring of 2014.

In terms of business model changes, the NY PSC is proposing three new mechanisms that would encourage utilities to develop and operate the grid as a platform for enabling distributed energy resources (DER) owned and operated mainly by third parties and customers. Over time, utility profits will be derived less from regulated returns on capital investments and more on revenue associated with managing the “distributed system platform” (DSP) where customers can find products and services from a range of non-utility companies, and where they can also provide services to the utility, using DER. The three new earnings mechanisms will each impact utility business behavior over different timeframes, from near term to long term.

The first earnings modification is called the “modified clawback mechanism.” Currently, in New York, utilities file multi-year rate plans that outline their capital spending for three years at a time. Once approved, utilities start earning returns (profits) on the capital outlays right away. At the end of the rate plan period, if the utilities have spent less than expected, the PSC takes back the profits associate with the unspent capital (which makes sense). The REV proposal would allow the utilities to keep those profits on unspent capital if utilities can show that they pursued a DER solution that avoided the need for the planned capital investment. While this may sound like “something for nothing,” what it does is reward the utility for making choices that move them in the direction envisioned in REV. Specifically, it should make the utility indifferent between spending its own capital (growing the rate base) and getting the same or better results from third-party or customer DER solutions - something that the advanced energy industry has been advocating since REV began.

Still, utilities don’t get to earn those profits forever - just until the next rate case. The white paper also proposes to extend rate plans by up to two years if the utility is performing well. This would extend the time the utility earns profits on unspent capital, providing even more incentive for utilities to seek out DER solutions. The advanced energy industry would like to see the PSC go one step further and find a way to incentivize the utility to look at DER solutions more comprehensively, not just on a project-by-project basis. Presumably, that will start to happen as utilities lay out their plans for the DSP in filings due in 2016 and in future rate cases.

The second mechanism is what the PSC calls Earnings Impact Mechanisms (EIMs). This is New York’s version of performance-based regulation, where utilities have the opportunity to make higher returns if they hit certain performance metrics. The white paper lists five performance metrics, but does not specify how large the earnings incentives will be. The performance metrics cover peak load reductions, energy efficiency deployment, interconnection, customer engagement and information access, and affordability. These EIMs should lead utilities to make investments in the DSP that make it easier for DER to be deployed and meet important REV objectives.

The third mechanism is called Market-Based Earnings (MBEs). This is arguably the most innovative, but also the least defined, change in the utility business model. The basic idea is that the utility will begin to offer services - some based on the DSP platform, but some possibly not - for which it will charge fees to users of the platform. This would generate revenue for the utility outside of the traditional rate base. An example might be a utility, in its role as the DSP, identifying a business customer in a constrained area of the network that could benefit from energy efficiency services, and referring that customer to an energy efficiency provider, which would pay the utility a finder’s fee. Another could be the utility providing dispatch and balancing services for distributed generation on the network. If MBEs work as envisioned, the utility would derive revenue from activities and investments that further animate the DER market, without ratepayers paying for them. A principal challenge with MBEs is ensuring that the utility engages in activities that support third parties instead of competing with them, using the advantages that come from their monopoly position. Because of this, we think MBEs should be implemented gradually, so that utilities  focus initially on developing their role as DSP.

On these issues central to the new utility business model, our filed comments can be summed up as follows:

• The PSC should move forward as expeditiously as possible with mechanisms that reward utilities for performance rather than capital investments, in order to motivate utility action related to DER deployment, customer engagement, access to data, and energy efficiency, with reasonable targets set as soon as 2016.
• The PSC should implement market-based earnings for utilities gradually, so that utilities focus initially on facilitating and developing a robust market for DER, rather than potentially introducing products that compete with DER providers.
• The PSC should develop more robust transition plans for utility energy efficiency programs to provide growth in energy savings aligned with state objectives and continue development of energy efficiency as a key DER to be offered on the platform.

In our comments we also addressed the second major thrust of the white paper, which was rate design. Rate design is how the utility business model is translated into what customers are charged for electricity service - and increasingly, how customers are compensated for providing  services to the grid. Good rate design allows utilities to recover their costs, earn a fair profit, raise revenue needed for future investments, and gives customers the information they need to manage their energy costs and invest in DER that provide benefits to the system. It’s a lot to ask. Traditionally, rates for most customers have been pretty simple - you pay the same rate per kilowatt-hour no matter when you use them or how much you use. But as with technology, the future of ratemaking is likely to look very different than the past. 

Overall, we were pretty happy with what the white paper had to say about rates. The PSC Staff made it clear that they would keep net metering as it is for “mass market” customers. At the same time, they proposed a new compensation mechanism called “LMP+D” to value the contribution of DER to the system for customers who want to become more active in the energy marketplace. LMP is the locational marginal price, or the wholesale cost of energy on a time- and location-specific basis. “D” is meant to capture the range of benefits the DER provides to the distribution system. A separate stakeholder process is about to start on how to figure out just how to do that. As we have filed in earlier comments on benefit-cost analysis, we support the development of compensation mechanisms that value the full range of benefits of DER to the electricity system and to customers. At the same, time, existing net metering compensation should be retained and extended to other technologies that do not receive compensation at full retail rates, such as fuel cells, until this comprehensive compensation system is in place. For LMP+D to work, it will need to be comprehensive, so that the benefits of moving from retail net metering to LMP+D justify the investments that customers will need to make.

In other rate design proposals, the white paper suggested creating an opt-in “smart home rate” that will allow active and sophisticated customers - “prosumers,” as they are sometimes called - to experiment with highly granular and disaggregated pricing that would look at how these customers could provide a range of grid services beyond just capacity and energy. The white paper also includes improvements to commercial & industrial rate design to bill using more precise demand rates to reflect time varying prices. It also proposed to revise standby rates to provide a credit to customers with a good track record of reliability - something that would benefit owners of distributed generation like combined heat and power (CHP).

We are supportive of efforts to explore new rate designs that take advantage of advanced metering capabilities, such as time-varying rates, and focus on peak demand. But these should only be implemented along with the tools and capabilities to manage demand; otherwise, billing based more on demand effectively amounts to an increase in fixed charges, which we do not support.

REV is a long way from over, but the 21st century utility business model is starting to take shape. Stay tuned for further updates as we continue to engage on REV and get even further into the details, whether we find the devil in them or not.