Tag Archives: CPUC

Bob Dunning gets choice on VCEA wrong

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Electricity customers in Davis and Yolo County are in the midst of choosing between the current incumbent electricity utility Pacific Gas & Electric (PG&E) and the new community choice aggregator (CCA) Valley Clean Energy Alliance (VCE). VCE is a joint powers authority (JPA) of the governments of the Yolo County, and the Cities of Davis and Woodland. (The Cities of Winters and West Sacramento have expressed interest in joining VCE as well.) By state law, customers are initially defaulted to the CCA at the outset before being given multiple chances over a six month period to choose to stay with the incumbent investor-owned utility–PG&E in this case.

Bob Dunning in his Davis Enterprise column August 8 confuses a lack of choice with just changing the starting point of the choice. Regardless of whether VCE or PG&E is the default provider, local customers still have exactly the same choice. But by having VCE start as the default provider, we level the playing field with the long-time giant monopoly utility, PG&E. (And customers can return to PG&E after 12 months if they are dissatisfied.) Why should we continue to give the big guy a continued advantage at the outset?

PG&E has all sorts of shareholder money to spend on improving its image and retaining customers. The utility’s biggest problem is that it is spending an additional 3.3 cents per kilowatt-hour to mismanage risk in its portfolio based on calculations I made in the power cost indifference adjustment (PCIA) rulemaking proceedings. Why stay with a company that has such a poor management record?

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Commentary on CPUC Rate Design Workshop

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The California Public Utilities Commission (CPUC) held a two-day workshop on rate design principles for commercial and industrial customers. To the the extent possible, rates are designed in California to reflect the temporal changes in underlying costs–the “marginal costs” of power production and delivery.

Professor Severin Borenstein’s opening presentation doesn’t discuss a very important aspect of marginal costs that we have too long ignored in rate making. That’s the issue of “putty/clay” differences. This is an issue of temporal consistency in marginal cost calculation. The “putty” costs are those short term costs of operating the existing infrastructure. The “clay” costs are those of adding infrastructure which are longer term costs. Sometimes the operational costs can be substitutes for infrastructure. However we are now adding infrastructure (clay) in renewables have have negligible operating (putty) costs. The issue we now face is how to transition from focusing on putty to clay costs as the appropriate marginal cost signals.

Carl Linvill from the Regulatory Assistance Project (RAP) made a contrasting presentation that incorporated those differences in temporal perspectives for marginal costs.

Another issue raised by Doug Ledbetter of Opterra is that customers require certainty as well as expected returns to invest in energy-saving projects. We can have certainty for customers if the utilities vintage/grandfather rates and/or structures at the time they make the investment. Then rates / structures for other customers can vary and reflect the benefits that were created by those customers making investments.

Jamie Fine of EDF emphasized that rate design needs to focus on what is actionable by customers more so than on a best reflection of underlying costs. As an intervenor group representative, we are constantly having this discussion with utilities. Often when we make a suggestion about easing customer acceptance, they say “we didn’t think of that,” but then just move along with their original plan. The rise of DERs and CCAs are in part a response to that tone-deaf approach by the incumbent utilities.

Reblog: If you like your time-invariant electricity price, you can keep it

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.

Source: If you like your time-invariant electricity price, you can keep it

PG&E to release 65,000 emails since 2010

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?

Three key steps in designing rates for solar power

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.

Only the first issue is being addressed head on in the rulemaking and it hasn’t really delved into the importance of emerging consumer choice.

Overwhelmed by “opportunities” at the CPUC

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 generationsolar initiative, net energy metering, alternative fueled and electric vehiclesresidential 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.

Will “optimal location” become the next “least-cost best-fit”?

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.