Author Archives: Richard McCann

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About Richard McCann

Partner in M.Cubed, an economics and policy consulting firm.

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?

Overwhelmed by “opportunities” at the CPUC

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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.

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

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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.

Retrospective on restructuring and what it means for our future

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Jim Bushnell of UCD and the Energy Institute at Haas has posted about a paper he is coauthoring with Severin Borenstein looking back 20 years at restructuring. It has some interesting insights, but I take issue with a couple points about the original motivation for restructuring, and whether we will be left with legitimate stranded costs with the current transformation.

My comment on the post:

The rationale behind restructuring (as reflected by my agricultural and industrial clients at that time) of “never again”–the utilities had demonstrated an inability to contain costs in constructing Diablo Canyon, SONGS and Helms, and FERC had gutted the ability for third parties to build turnkey plants in the BRPU decision. The utilities were very slow to adopt the low-cost combined cycle technology, so the only solution looked to be to walk away. Restructuring did establish the merchant industry which has been the leaders in developing renewable technologies and even rooftop solar. Again, we could have expected the utilities to drag their feet, so we have gotten institutional innovation that otherwise would not have happened. (Institutional innovation, not technological, is what got us reduced SOx emissions under the Clean Air Act Amendments of 1990.)

Going forward, leaving the utility system only “strands” network infrastructure if we take the static view that the network will continue in its current state. Shareholders are still recovering their investment, and if they’ve been paying attention since 2007, they should know that overall demand has been falling. They will only be stuck with infrastructure costs if either they have had little foresight or if a sudden technological change accelerates customer exit. In the latter situation, this will only occur if distributed resource costs fall dramatically in which case the exit will probably be socially beneficial. Why should consumers be locked into a large scale network to protect shareholders?

Restructuring was marked by a sudden, dramatic change–opening the market on a single day, divesting generation assets within a few months. The current transformation is more gradual because it is house by house, business by business. Utilities can change their investment plans, and depreciation recovery allows them to recoup their past costs. We may be foregoing the benefits of a paid-up network, but we have almost never regretted such technological change in the past. (Maybe the sale of the “red cars” rail system in LA as the most salient exception.) Do we regret that we’ve left behind land lines for our cell phones? Given the benefits of carrying around microcomputers for daily activities, I think not.

Paying for Water in California

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My partner David Mitchell has coauthored an article in the Hastings Law Review:

Paying for Water in California: The Legal Framework

Brian Gray, Dean Misczynski, Ellen Hanak, Andrew Fahlund, Jay Lund, David Mitchell, and James Nachbaur
Over the past four decades, California voters passed a series of initiatives that
amended the California Constitution to limit the power of the state legislature and
local governments to enact taxes and restrict their authority to adopt fees and other
charges to fund government programs. Three of these initiatives—Proposition 13
(enacted in 1978), Proposition 218 (passed in 1996), and Proposition 26 (approved in
2010)—have placed significant constraints on the funding of water resources projects.
Although each of these laws has enhanced the transparency and accountability of the
decision-making process, the funding constraints now jeopardize an array of vital
water supply, management, and regulatory functions. These include funding for the
development of new water supplies, integrated water management, protection of
groundwater resources, development of alternative water sources (including recycled
and conserved water programs), control of stormwater discharges, and regulation of
water extraction and water use to protect water rights, water quality, aquatic species,
and other beneficial uses of the state’s water systems.
This Article is a companion to the report Paying for Water in California and focuses
on the legal aspects of water financing. The Paying for Water study demonstrated the critical importance of local funding to support California’s water system: local
utilities and governments raise eighty-five percent of the more than thirty billion
dollars spent annually on water supply, quality, flood, and ecosystem management
through local fees and taxes. The study identified a two to three billion dollar annual
funding gap, with critical gaps already evident for provision of safe drinking water in
small, rural communities, prevention of stormwater pollution, protection of people,
property, and infrastructure from flooding, recovery efforts for aquatic ecosystems,
and integrated water management. In most cases, these gaps reflect legal obstacles to
raising more funds locally. In addition, urban water and wastewater systems—now in
relatively good fiscal health—face looming challenges related to rising costs and legal
constraints on the ability to raise fees to support modern, integrated water
management.
This Article begins with an overview of the traditional sources of funding for water
development, management, and regulation, and proceeds to a detailed analysis of the
effects of the constitutional constraints (especially of Propositions 218 and 26) on
these essential governmental programs. Topics include: (i) analysis of the effects of
Proposition 218 on water rates and fees charged by public retail water agencies for
water service and integrated, portfolio-based water management; (ii) consideration of
the special problems of Proposition 218 for groundwater regulation and stormwater
discharge programs; (iii) predictions about the effects of Proposition 26 on wholesale
water rates, water stewardship charges, and regulatory fees; and (iv) suggestions for
harmonizing the fiscal strictures of Propositions 218 and 26 with the reasonable use
mandates of Article X, Section 2, of the California Constitution, which form the
foundation of the state’s water law and policy.
Our key conclusions are that: (1) Propositions 218 and 26 have created significant
impediments to economically rational and sustainable funding of California’s most
important water service, management, and regulatory programs; (2) judicial
interpretations of the constitutional restrictions generally have compounded these
impediments; and (3) reform of the law is needed. The Article concludes with
recommendations that water agencies, the legislature, the courts, and the voters
should consider as a means of correcting (or at least ameliorating) those aspects of
the law that are inconsistent with sound and creative water resources administration

Using an event to measure energy savings program effectiveness (again)

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Koichiro Ito again has used a discrete event to develop a “control” for an economic experiment. In this case, he has studied PG&E’s 20/20 rebate program in 2004. The “event” he uses is the eligibility date for the program–he uses new customers who connected to service just before and after that date. He finds that the program had almost no effect on coastal customers but that it was effective in reducing energy use for low-income inland consumers. 

Previously, he had looked whether tiered-block rates were better at inducing conservation across the entire pool of customers. The final version of his paper was published February in the American Economic Review. Discerning the true effects of tiered-rates has been very difficult due to the endogeneity problem–consumers essentially set their own marginal price by choosing their consumption level. Many studies have been conducted in both water and electricity trying to tease out this effect, but the results have always been questionable for this reason. 

Ito was able to use two key facts in his latter study: 1) the 2001 California electricity crisis caused rates to rise rapidly and 2) the SCE and SDG&E service areas are closely interlocked across similar communities in southern Orange County. He was able to run an after-the-fact experiment with two treatment groups that had similar socio-economics and were exposed to the same media market. It’s as if two groups of customers were presented with two different sets of rates from the same utility–a truly unique situation that probably can’t be duplicated. He found that the tiered rates induced no more change in energy use than simple average rates.

These well-done studies can cause policymakers to ask whether complicated proposals that seem to mitigate various concerns are truly effective. In these two cases, the answers are largely “no”. 

What are the missing questions in California’s distribution planning OIR?

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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.)

 

AECA - PG&E 2014 GRC Testimony: Comparing Demand Forecasts

AECA – PG&E 2014 GRC Testimony: Comparing Demand Forecasts

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.

Looking beyond performance based ratemaking in New York’s Utility 2.0

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Rory Christian of EDF has written about using performance-based ratemaking “+” (PBR+) in New York’s Reforming the Energy Vision proceeding. EDF, in taking an important step for an environmental advocate, recognizes the importance of providing the right economic incentives for market participants to achieve environmental goals. Prescriptive solutions too often are misguided and inflexible leading to failure and high costs.

That said, PBR+ may not be the best solution (and I don’t have the immediate answer to this question.) PBR hasn’t had a great track record in California. Diablo Canyon suffered from excessive costs that led to the push for restructuring. The competitive transition charge (CTC) opened the door for market manipulation. And the CPUC couldn’t say “no” when it awarded incentives for questionable energy efficiency gains. Other jurisdictions have had mixed results. Mechanism design is critically important to make PBR work.

Taking a step back from specific policy proposals, an important perspective to consider is that the “regulated utility” is not the same as “utility shareholders.” Shareholders are the true stakeholders in the discussion about the new utility business model. (Utility managers may hijack that role but that probably is not a sustainable position.) So we should be looking outside the box of standard regulatory tools, even PBRs, and ask “how else can utility shareholders see value from the electricity industry outside of their regulated utility affiliate?” There are potential models for alternative approaches that might ease the political and economic transition to the new energy future.

Chuck Goldman at Lawrence Berkeley National Lab made a presentation on the various business model options that are available. The Energy Services Utility (ESU) is an option that deserves greater exploration, particularly in concert with a distributed system operator (DSO). An ESU might provide a model for utility holding company shareholders to participate. But the devil could be in the details.