Severin Borenstein at the Energy Institute at Haas makes the case for giving customers the choice of TOU or fixed price rates. I’ve commented several times on the Energy Institute blog about this approach, and blogged myself about the need for this option.
PG&E in the wake of more revelations about ex parte contacts with CPUC commissioners and staff is releasing 65,000 emails over the period from 2010. This should make for some interesting reading by interested parties. Is there anyone out their who might like to cooperatively compile a readable database?
KQED posted a good summary of how solar power is driving the residential rate design rulemaking at the CPUC. (M.Cubed works for EDF there.) I offer three steps that should be taken to address the issues of how to change ratemaking for a changing energy marketplace:
1) Consumers should see time varying prices (time of use or TOU being among that menu). Tiered rates make it impossible to see the current price for consumption, and tiered rates have been shown not to induce any additional conservation across the customer base. Consumer surveys show that customers want more control over their electricity use and the price signals to direct them.
2) Consumers should be offered a meaningful menu of rate options. This means rates that differ in risk exposure both over time of day and time horizon. Customers should be able to hedge against peak day prices or participate in demand response. They should be able to accept changes in hourly prices or buy a multi-year contract. Utilities already offer these contract options to their suppliers; why not treat their customers as they they are valued?
3) Any calculation of grid costs and responsibility should reflect the changing demand by consumers. The grid charges proposed by the utilities assume that future consumers will install the same-sized equipment as they do today and that they will consume in the same pattern. Solar panels are ready today to “island” a home from the network, and EV charging could create greater load diversity even at the circuit level. That will radically change utility investment. The distribution planning rulemaking is an important step toward resolving that issue but the CPUC hasn’t yet linked the proceedings.
The opening of yet another rulemaking at the CPUC and the revelations of more contacts between PG&E and CPUC Commissioners are two sides of a larger conundrum in state electricity policy development and implementation. The OECD recently issued a wish list for how regulatory agencies should be structured and behave. (Thanks to Mark Pearson for posting this.) Yes, some are “pie in the sky” but they provide a useful means of evaluating how a regulatory agency is performing.
Looking at the first principle, the CPUC has been set adrift in part by the lack of role clarity in the state. At one point at least 8 statewide agencies had significant roles in electricity planning and ratemaking. (Along with the CPUC, there’s been the CEC, CAISO, CARB, CDWR, SWRCB, Electricity Oversight Board, and California Power Authority, the last 2 now defunct.) And there are additional local agencies (e.g., SCAQMD). This has blurred the lines of authority and allowed forum shopping.
And perhaps most importantly the number of proceedings at the CPUC have proliferated to a point where it is impossible for intervenors to devote enough resources to follow what’s happening everywhere. At least 14 different rulemakings are looking at interdependent elements of planning for increased renewables and the transformation of the electricity market. These include the long term power procurement, renewables portfolio standard, energy efficiency, water-energy nexus, demand side response, utility shareholder incentives, storage, distributed generation and self generation, solar initiative, net energy metering, alternative fueled and electric vehicles, residential rate design, CCA rules, and recently, distribution resources planning. And these don’t count the many utility applications such as the green tariff and community solar garden proposals. Some of these proceedings have been open over a decade with only partial resolution, and the CPUC has opened direct successors up to 4 times. While looking to develop a consistent regulatory framework for evaluating integrated demand side resources is an admirable goal, it could be overwhelmed by the divided attention demanded from all of these other proceedings. That undermines another OECD principle–transparency–even if appearances look differently.
Finally funding for both intervenors and skilled CPUC staff has become untenable and effective participation in declining, further eroding yet another OECD principle. This allows the well-funded utilities to influence outcomes while no one is looking. The documentation of the meetings and emails are only a reflection of the underlying problems.
The answers would seem to include:
- to consolidate proceedings rather than opening new ones,
- not adding yet more ratesetting proceedings for specific add ons, and
- funding intervenors on a more equitable basis with utilities and paying those groups sooner than two years after the relevant decision.
Some of these will require legislative action; others might be implemented after the current CPUC president has left. But it will only happen if intervenors collectively demand reform.
At the CPUC’s first workshop on distribution planning, the buzz word that came up in almost every presentation was “optimal location.” But what does “optimal location” mean? From who’s perspective? Over what time horizon? Who decides? The parties gave hints of where they stand and they are probably far apart.
Paul De Martini gave an overview of the technical issues that the rulemaking can address, but I discussed earlier, there’s a set of institutional matters that also must be addressed. Public comment came back repeatedly to these questions of: who should be allowed into the emerging market with what roles, and how will this OIR be integrated with the multitude of other planning proceedings at the CPUC? I’ll leave a discussion of those topics to another blog.
The more salient question is defining “optimal location.” I’m sure that it sounded good to legislators when they passed AB 327, but as with many other undefined terms in the law, the devil is in the details. “Least cost-best fit” for evaluating new generation resources similarly sounds like “mom and apple pie” but has become almost meaningless in application at the CPUC in the LTPP and RPS proceedings. Least cost best fit has just led to frustration for both many developers of innovative or flexible renewables such as solar thermal and geothermal, and for the utilities who want these resources.
SCE and SDG&E were quite clear about how they saw optimal location would be chosen: the utility distribution planners would centrally plan the best locations and tell customers. Exactly HOW they would communicate these choices was vague.
Many asked how project developers and customers might know where to find those optimal locations among the utilities’ data. Jamie Fine of EDF might have had the best analogy. He said he now lives in a house that clearly needs a new paint job, so painters drop flyers on his doorstep and not on his neighbors who’s paint is not peeling. Fine asked, “when will the utilities show us where the paint is peeling in their distribution systems?” His and others’ questions call out for a GIS tool that be publicly viewed, maybe along the view of the ICF tool recently presented.
I can think of a number of issues that will affect choices of optimal locations, many of them outside of what a utility planner might consider. The theme of these choices is that it becomes a decentralized process made up of individual decisions just as we have in the rest of the U.S. market place.
- Differences in distributed energy resource characteristics, e.g., solar vs. bioenergy;
- Regional socio-economic characteristics to assess fairness and equity;
- Amount of stranded investment affected;
- The activities and energy uses both of the host site, neighboring co-users/generators, and surrounding environs;
- Differences in valuation of reliability by different customers;
- Interaction with local government plans such as achieving climate action goals under SB 375.
- Opportunities for new development compared to retrofitting or replacing existing infrastructure.
In such a complex world, the utilities won’t be able to make a set of locational decisions across their service territory simply because they won’t be able to comprehend this entire set of decision factors. It’s the unwieldly nature of complex economies that brings down central planning–it’s great in theory, but unworkable in practice. The utilities can only provide a set of parameters that describe a subset of the optimal location decisions. State and local governments will provide another subset. Businesses and developers yet another set and finally customers will likely be the final arbiters if the new electricity market is to thrive.
As a final note, opening up information about the distribution system (which the utilities have jealously guarded for decades) offers an opportunity to better target other programs as well such as energy efficiency and the California Solar Initiative. Why should we waste money on air conditioning upgrades in San Francisco when they are much more needed in Bakersfield? The CPUC has an opportunity to step away from a moribund model in more than distribution planning if it pursues this to its natural conclusion.
The CPUC has opened a long awaited rulemaking to revisit (or maybe visit for the first time!) how utilities should plan their distribution investments to better integrate with distributed energy resources (DER). State law now requires the utilities to file distribution plans by next July. But the CPUC may want to consider some deeper questions while formulating its policies.
To date the utilities have pretty much been able to make such investments with little oversight. For one client, AECA, we submitted testimony pointing out that PG&E had consistently overforecasted demand and used that demand to justify new distribution investment that probably is unneeded. Based on a corrected forecast that recognizes that that PG&E’s (and the state’s) demand has turned downward since 2007, PG&E’s loads don’t return to 2007 levels until at least 2014. (We found a similar pattern in SCE’s 2012 GRC filings.)
Both PG&E and SCE justified new investment based on phantom load growth, but they would have been better served to show what investment might be required for the evolving electricity market. SCE has responded with the Living Pilot that tests out how to best integrate preferred resources.
The CPUC is relying on Paul De Martini’s More than Smart paper as a roadmap for the rulemaking. The CPUC has asked a number of questions to be addressed by September 4 with replies September 17. A workshop is to be held September 18.Beyond these questions, two more questions come to mind.
First, who will be allowed to play in the DER world? The OIR asks about non-IOU ownership of distribution lines, particularly related to microgrids, but it doesn’t consider the flip side–can utilities or affiliates participate in the DER market? Setting market rules in the face of rapid evolution and uncertainty, current participants will look to protect their current interests unless they are shown a clear opportunity to gain the benefits of a new market. The CPUC ignores the political economy of rulemaking at our risk.
The second is how is this proceeding to be integrated with the multitude of other proceedings at the CPUC that set various resource targets? The LTPP, energy efficiency, demand response and solar initiatives, along with others, all seem to run on parallel tracks with little in the way of interactive feedback. Megawatt targets seem to be set arbitrarily with little evaluation of comparative resource costs and effectiveness, and more importantly, how these resources might best integrate with each other. How are the utilities to adapt to the spread of DER if the CPUC hasn’t considered how much DER might be installed?
Both of these questions are about market functionality. Who are the likely participants? What are their incentives to act in different situations? How would the CPUC prefer that then act? How are price signals to be coordinated to create the preferred incentives? The system investment and operation rules are a necessary component of anticipating the market evolution, but they are not sufficient. California ignored the incentives of market participants in the previous restructuring experiment, at the cost of $20 to $40 billion. We should take heed of what we’ve learned from the past about the paradigm we should use to approach this impending change.
California has been quite successful at encouraging the development of (1) large utility-scale renewables through the renewables portfolio standard (RPS) and other measures and (2) small-scale, single structure solar generation through the California Solar Initiative (CSI) and measures such as net energy metering (NEM). However, there have been numerous market and regulatory barriers to developing and deploying the “in-between” community-scale and neighborhood-scale renewables that hold substantial promise.
Community-scale and neighborhood-scale distributed generation (DG) includes some technologies that simply are not cost-effective at the small scale of a single house or business, but are not large enough to justify the transaction costs of participating in the larger wholesale electricity market. These resources, such as “community solar gardens”, can meet the demands of many customers who cannot take advantage of adding renewables at their location and can also reduce investment in expensive new transmission projects. Examples of these types of projects are parking structure-scale solar photovoltaics, solar-thermal generation and space cooling, and biogas and biomass projects, some of which could provide district heating. Technology costs are falling so rapidly that these mid-scale projects are becoming competitive with utility-scale resources when transmission cost savings are factored in. SB 43 (Wolk 2013) recognizes that the promise of mid-scale renewables has not been realized.
In response to SB 43, each of the large investor-owned utilities–PG&E, SCE and SDG&E–have filed proposed tariffs with names such as Enhanced Community Renewables Program or Share the Sun. I filed testimony in the PG&E and SCE cases on behalf of the Sierra Club addressing shortcomings in those programs that would inhibit development of community solar gardens. SDG&E’s proposal, while not perfect, better meets the law’s objectives. After the hearings, the CPUC postponed a proposed decision from the July 1 deadline to October.
SB 43’s requirement that the investor-owned utilities “provide support for enhanced community renewables programs” is a critical step forward for California’s distributed energy goals. The CSI is the state’s premier distributed generation program. In SB 43 the Legislature expressed its intent that the “green tariff shared renewables program seeks to build on the success of the California Solar Initiative by expanding access to all eligible renewable energy resources to all ratepayers who are currently unable to access the benefits of onsite generation.” SB 43 advances the success of the CSI into the area of multifamily residential and multitenant commercial properties and introduces all types of renewable energy resources. Customers who, for various reasons, cannot benefit from the current net metering programs, will be able to benefit through SB 43.
The Legislature clearly intends for this program to lead to a transformation in the energy market akin to the success for single customers of the CSI. This necessary market transformation extends to multifamily and commercial lease properties that are currently beyond the CSI and Self Generation Incentive Programs (SGIP). The Commission should ensure that utilities’ programs under SB 43 provides the market transformation that is necessary for this underserved segment.
State regulations calls for all new residential dwellings to consume zero-net energy (ZNE) by 2020, and all new commercial properties by 2030. Fully implementing the market transformation identified in SB 43 is one of the obvious means to achieve this target. The CSI option has already facilitated many examples of feasible ZNE single-family homes using renewables well ahead of the 2020 deadline. There are several market barriers to integrating renewables in a similar manner on multifamily and commercial leased properties and on single-family that are not favorably located or that have other impediments.
A properly-designed community solar garden program should provide a critical work-around for the split-incentive problem that has plagued local renewable development in California. The split-incentive problem arises from the fact that multi-tenant structures, both commercial and residential, may not be able to implement solar or other renewable resources due to the fact that lessees are not the owners of the shared space where renewables could be sited. The problem of split-incentives between landlords and tenants has long been recognized, and has been the focus of energy efficiency programs.
As a corollary, the Commission should provide individual developers and property owners the opportunity to integrate energy efficiency and DG measures to achieve the best mix for meeting environmental and economic goals. Each project is unique so that a “one size fits all” approach that requires sale of all output into the wholesale market with buyback from customers who may have no connection with the project will only discourage enhanced development.
For distributed generation to expand in California there must be a cost-effective path for residential and commercial tenants, as well as not-well-situated buildings, to install solar and other renewables and share the costs among other customers. The focus to date has been on either utility-scale or single-building scale projects, but the most promise may be in mid-scale projects that can serve a community or a neighborhood cost-effectively through a combination of scale economies and avoided transmission and distribution investment. But to achieve this objective requires changes from current utility practices.