Tag Archives: energy management

Thinking outside the box on the CPUC’s future

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Assemblymember Mike Gato (D-LA) is proposing a constitutional amendment to dissolve the CPUC–blowing up the box! The CPUC currently regulates energy utilities, telcom, transportation and water. That’s a tall order to ask five people to competently understand all of those arenas. And on the flip side, many have recognized that the state has too many “cooks in the kitchen” regulating energy, and it’s only gotten worse with increased climate change regulation. The CPUC hasn’t done much to burnish its reputation with the scandal of Mike Peevey’s “rulings for sale” and the inadequate responses to the San Bruno and Porter Ranch disasters. Closing up shop and starting over may be the best solution.

The decisions utilities must make soon

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Jeff McMahon at Forbes wrote a nice two-part series on the existential decisions that utilities face going forward. Part 1 is here, and Part 2 here. I posted earlier a longer article from the New Yorker looking at the changing landscape.

Smart, clean and local energy technologies for Davis

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Second in a series published in the Davis Enterprise on how the City of Davis can address its energy future:

Smart, clean and local energy technologies for Davis

Three key steps in designing rates for solar power

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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.

Reexamining growth and risk sharing for utilities

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Severin Borenstein at the Energy Institute at Haas blogged about the debate over moving to residential fixed charges, and it has started a lively discussion. I added my comment on the issue, which I repost here.

The question of recovery of “fixed” costs through a fixed monthly charge raises a more fundamental question: Should we revisit the question of whether utilities should be at risk for recovery of their investments? As is stands now if a utility overinvests in local distribution it faces almost no risk in recovering those costs. As we’ve seen recently demand has trended well below forecasts since 2006 and there’s no indication that the trend will reverse soon. I’ve testified in both the PG&E and SCE rate cases about how this has led to substantial stranded capacity. Up to now the utilities have done little to correct their investment forecasting methods and continue to ask for authority to make substantial “traditional” investment. Shareholders suffer few consequences from having too much distribution investment–this creates a one-sided incentive and it’s no surprise that they add yet more poles and wire. Imposing a fixed charge instead of including it as a variable charge only reinforces that incentive. At least a variable charge gives them some incentive to avoid a mismatch of revenues and costs in the short run, and they need to think about price effects in the long run. But that’s not perfect.

When demand was always growing, the issue of risk-sharing seemed secondary, but now it should be moving front and center. This will only become more salient as we move towards ZNE buildings. What mechanism can we give the utilities so that they more properly balance their investment decisions? Is it time to reconsider the model of transferring risk from shareholders to ratepayers? What are the business models that might best align utility incentives with where we want to go?

The lesson of the last three decades has been that moving away from direct regulation and providing other outside incentives has been more effective. Probably the biggest single innovation that has been most effective has been imposing more risk on the providers in the market.

California has devoted as many resources as any state to trying to get the regulatory structure right–and to most of its participants, it’s not working at the moment. Thus the discussion of whether fixed charges are appropriate need to be in the context of what is the appropriate risk sharing that utility shareholders should bear.

This is not a one-side discussion about how groups of ratepayers should share the relative risk among themselves for the total utility revenue requirement. That’s exactly the argument that the utilities want us to have. We need to move the argument to the larger question of how should the revenue requirement risk be shared between ratepayers and shareholders. The answer to that question then informs us about what portion of the costs might be considered unavoidable revenue responsibility for the ratepayers (or billpayers as I recently heard at the CAISO Symposium) and what portion shareholders will need to work at recovering in the future. As such the discussion has two sides to it now and revenue requirements aren’t a simple given handed down from on high.

Questions yet to be answered from the CAISO Symposium

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While attending the CAISO Stakeholder Symposium last week I had rush of questions, not all interconnected, about how we manage the transition to the new energy future. I saw two very different views about how the grid might be managed–how will this be resolved? How do we consider path dependence in choosing supporting and “bridge” resources? How do we provide differential reliability to customers? How do we allow utilities to invest beyond the meter?

Jesse Knight, former CPUC Commissioner and now chairman at SDG&E and SCG, described energy utilities as the “last monopoly” in the face of a rapidly changing economic landscape. (Water utilities may have something to say about that.) SDG&E is ahead of the other utilities in recognizing the rise of the decentralized peer-to-peer economy.  On the other hand, Clark Gellings from EPRI described a world in which the transmission operator would have to see “millions” of nodes, both loads and small generators, to operate a robust network. This view is consistent with the continued central management implied by the utility distribution planners at the CPUC’s distribution planning OIR workshop. At the end of the symposium, 3 of the 4 panelist said that the electricity system would be unrecognizable to Thomas Edison. I wonder if Alexander Graham Bell would recognize our telecommunications system?

One question posed to the first “townhall” panel asked what role natural gas would have in the transition to more renewables. I am not aware of any studies conducted on whether and how choices about generation technology today commits us to decisions in the future. Path dependence is an oft overlooked aspect of planning. We can’t make decisions independent of how we chose in the past. That’s why it’s so difficult to move away from fossil fuel dependence now–we committed to it decades ago. We shouldn’t ignore path dependence going forward. Building gas plants now may commit us to using gas for decades until the financial investments are recovered. We may be able to buy our way out through stranded asset payments, but we learned once before that wasn’t a particularly attractive approach. Using forethought and incorporating flexibility requires careful planning.

And along those lines in our breakout session, another question was posed about how to resolve the looming threat of “overgeneration” from renewables, particularly solar.  Much of the problem might be resolved by charging EVs during the day, but it’s unlikely that a sizable number of plug-in hybrids and BEVs will be on the road before the mid-2020s. So the question becomes should we invest in gas-fired generation or battery or pumped storage, both of which have 20-30 year economic lives, or try to find other shorter lived transitions including curtailment contracts or demand response technologies until EVs arrive on the scene? It might even be cost effective to provide subsidies to accelerate adoption of EVs so as to avoid long-lived investments that may become prematurely obsolete.

Pricing for differential reliability among customers also came up. Often ignored in the reliability debate at the CAISO is that the vast majority of outages are at the distribution level. We appear to be overinvested in transmission and generation reliability at the expense of maintaining the integrity of the local grid. We could have system reliability prices that reflect costs of providing flexible service to follow on-site renewable generation. However the utilities already recover most of the capital costs of providing those services through rate of return regulation. The market prices are suppressed (as they are in the real time market where the IOUs dump excess power) so we can’t expect to see good price signals, yet.

Several people talked about partnerships with the utilities in investing in equipment beyond the meter. But the question is will a utility be willing to facilitate such investments if they degrade the value of its current investment in the grid? Fiduciary responsibility under traditional return on capital regulation says only if the cost of the new technology is higher so as to generate higher returns than the current grid investment. That doesn’t sound like a popular recipe for a new energy future.  Instead, we need to come up with creative means of utility shareholders participating in the new marketplace without forcing them down the old regulatory path.

Margaret Jolly from ConEd noted that the stakeholders were holding conversations on the new future but “the customer was not in the room.” Community, political and business leaders who know how electricity is used were not highly evident, and certainly didn’t make any significant statements. I’ve written before about offering more rate options to customers. I wanted to hear more from Ellen Struck about the Pecan Street study, but her comments focused on the industry situation, not customers’ behaviors and choices.

Looking at a locality’s options as the energy marketplace changes

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Here’s the first in a series of articles that I am coauthoring about how the new direction in the energy utilities marketplace can affect the choices for a locality like the City of Davis. This one is with Gerry Braun. This first article reviews the findings of study conducted last year that focused on a more traditional utility models, and then sketches the most salient options. This and future articles with other co authors will include:

  • What are the options going forward for Davis and what have we looked at.
  • Describing decentralized energy systems
  • How a decentralized energy system might fit into achieving local goals (e.g., climate action plan) and affect economic activity.
  • Barriers to achieving local goals in this future scenario.
  • Comparisons of potential business models to overcome those barriers.

The (telecom) path well travelled: What does it hold for electricity?

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In many ways, the potential for a dramatic transformation in the electricity industry feels like deja vu in the telecommunications industry of the 1980s. That industry evolved rapidly and radically so that what we see today is almost unrecognizable compared to three decades ago. Do we stand on the verge of a similar revolution in electricity?

In the 1980s, it was the entry of microwave transmission that threatened the hardwired long-distance network of AT&T. The combination of the MCI decision allowing competition and the DOJ anti-trust settlement that broke AT&T into the 7 Baby Bells, both in 1982, led to proliferating long distance competition.

The electricity industry had a similar transformative decision in FERC Order 888 in 1996. There was a similar first wave of opening up wholesale competition through a centralized grid through restructuring induce by the introduction of combined cycles. As with AT&T being slow to adopt new technologies, it’s hard to imagine the electric utilities building CCGTs before others forced their hands.

In telecom, allowing more players meant that they started to compete with customers using new technologies, Rapid innovation in computers bled over to phones and cell phones. The FCC facilitated this with innovative auctions of regional wireless band licenses. The entry of cable companies for local service created more competitive pressure. Yes, the industry went through consolidations, but the threat of entry and marketing innovations place caps on what these companies can charge and force more consumer options.

Long distance competition may not have benefited, but such an assessment ignores the second wave of telecom deregulation starting a decade later: the entry of cable companies, the use of the Internet for calling, the rise of messaging, and proliferation of smart cell phones. Now AT&T’s land lines are an afterthought for phone service and those companies offer bundles of services across telephone, television, Internet and cell phone. Long distance and local land line competition are but an afterthought in the industry after three decades. The better question is whether these services will even survive in the near future.

Electricity restructuring may not have delivered on its initial promise, but, as with telecom, it brought new competitors who are looking for different ways to enter market. New technologies that decentralize energy resources look like the second wave of telecom innovation in many ways. NRG is one such example of a company that focused on merchant generation but are now looking to distributed energy resources. Sempra and Duke are utility holding companies that are shifting their mission in promising ways. Will these and other innovators break into the energy services market and offer consumers the type of choices that telecom customers now have? Will the existing modes of delivering electricity lose dominance in the same way as happened in telecom?

The answer will depend in part on decisions made by regulators. The US DOJ and FCC played key parts, and the state commissions eventually backed away from close regulation. This requires support from stakeholders including the utilities. AT&T eventually evolved into a dominant player in the new marketplace although it wasn’t a smooth transition. Will the electric regulators have similar foresight? Will they avoid many of the same pitfalls?