Kevin Novan from UC Davis wrote an article in the University of California Giannini Foundation’s Agriculture and Resource Economics Update entitled “Should Communities Get into the Power Marketing Business?” Novan was skeptical of the gains from community choice aggregation (CCA), concluding that continued centrally planned procurement was preferable. Other UC-affiliated energy economists have also expressed skepticism, including Catherine Wolfram, Severin Borenstein, and Maximilian Auffhammer.
At the heart of this issue is the question of whether the gains of “perfect” coordination outweigh the losses from rent-seeking and increased risks from centralized decision making. I don’t consider myself an Austrian economist, but I’m becoming a fan of the principle that the overall outcomes of many decentralized decisions is likely to be better than a single “all eggs in one basket” decision. We pretend that the “central” planner is somehow omniscient and prudently minimizes risks. But after three decades of regulatory practice, I see that the regulators are not particularly competent at choosing the best course of action and have difficulty understanding key concepts in risk mitigation.By distributing decision making, we better capture a range of risk tolerances and bring more information to the market place. There are further social gains from dispersed political decision making that brings accountability much closer to home and increases transparency. Of course, there’s a limit on how far decentralization should go–each household can’t effectively negotiate separate power contracts. But we gain much more information by adding a number of generation service providers or “load serving entities” (LSE) to the market.
I found several shortcomings with with Novan’s article that would change the tenor. I take each in turn:
He wrote “it remains to be seen whether local governments will make prudent decisions…” However, he did not provide the background which explains at least in part why the CCAs have arisen in the first place. Largely over the last 40 years, the utilities have made imprudent procurement and planning decisions. Whether those have been pushed on the utilities by the CPUC and Legislature or whether the IOUs have some responsibility, the fact is that neither institution sees real consequences for these decisions, neither financially or politically. In fact, the one time that a CPUC commissioner attempted to deliver consequences to the IOUs, she was fired and replaced by a former utility CEO. The appropriate comparison for local government decision making is to the current baseline record, not an academic hypothetical that will never exist. And by the way, government enterprise agencies, including municipal utilities, have a relatively good record as demonstrated as by lower electricity rates and relatively well managed, almost invisible capital intensive water and sanitation utilities. The current CCAs have a more extensive portfolio risk management system than PG&E—my calculation of PG&E’s implicit risk hedge in its renewables portfolio is an astounding 3.3 cents per kilowatt-hour.
Novan complains that CCAs have “dual objectives.” In fact they have “triple objectives,” the added one to encourage local economic development (sometimes through lower rates). I suggest reading the mission statements of the CCAs that have been created, including the local Valley Clean Energy Authority .
It’s not clear that “purchasing locally produced renewable energy will likely lead to more expensive renewable output” for at least two reasons. The first is that local power can avoid further transmission investment. The current CAISO transmission access charges range from $11 to $39 per megawatt-hour and is forecasted to continue to rise significantly (indicating transmission marginal costs are much above average costs). In a commentary on a UC Energy Institute blog, it was revealed that the Sunrise line may have cost as much as $80 per MWH for power from the desert. This wipes out much of the difference between utility scale and DG solar power. Building locally avoids yet more expensive transmission investment to the southeast desert. [I worked on the DRECP for the CEC.] In addition, local power can avoid distribution investment and will be reflected in the IOU’s distribution resource plans (DRP). And second, the scale economies for solar PV plants largely disappears after about 10 MW. So larger plants don’t necessarily mean cheaper, (especially if they have to implement more extensive environmental mitigation.) [I prepared the Cost of Generation model and report for the CEC from 2001-2013.]
It’s not necessary that more renewable capacity is needed for local generation. The average line losses in the CAISO system are about 6%, and those are greater from the far desert region. Whether increased productivity overcomes that difference is an empirical question that I haven’t seen answered satisfactorily yet.
Novan left unstated his premise defining “greener” renewables, but I presume that it’s based almost entirely on GHG emissions. However, local power is likely “greener” because it avoids other environmental impacts as well. Local renewables are much more likely to be built on brownfields and even rooftops so there’s not added footprints. In contrast there is growing opposition to new plants in the desert region. The second advantage is the avoidance of added transmission corridors. One only needs to look at the Sunrise and Tehachipi lines to see how those consequences can slow down the process. Local DG can avoid distribution investment that has consequences as well. Further, local power provides local system support that can displace local natural gas generation. In fact, one of the key issues for Southern California is the need to maintain in-basin generation to support imports of renewables across the LA Basin interface. [I assessed the need for local generation in the LA Basin in the face of various environmental regulations for the CEC.]
I was on the City of Davis Community Choice Energy Advisory Committee, and I am testifying on behalf of the California CCAs on the setting of the PCIA in several dockets. I have a Ph.D. from Berkeley’s ARE program and have worked on energy, environmental and water issues for about 30 years.
Rather than focus on CCA procurement, the CPUC would better serve the state to use the provisions of AB 57 (e.g., PUC Section 454.5(b)(6)) and its other authorities, including those still in force from AB 1890 (1996). PG&E and SCE already collected $7 billion on an accelerated basis during the “competitive transition period” from 1998 to 2001 towards their legacy utility-owned generation resources such as Diablo Canyon, San Onofre and their hydropower generation. SDG&E completely paid off its generation portfolio in 1999 this way. Further, PG&E had already recovered its entire investment in Diablo Canyon by December 31, 1997 prior to the start of the opening of the restructured market. (I tracked the CTC accounts throughout the period, reporting to the CEC in 2001, and calculated the return on investment in Diablo Canyon for settlement discussions in 1996.) If the Commission wanted to repay the debts incurred during the 2000-01 energy crisis, the better solution, which it did in part with SCE, would have been to simply establish a “regulatory asset” with no connection to the generating facilities which had already been paid off. As it is, customers-–bundled and departed–are paying twice (and THREE times in the case of Diablo Canyon) for the same power plants.
The IOUs currently lack any real incentives to control their portfolio costs, as evidenced by their bundled portfolio plans for PG&E and SCE. Those plans say nothing about minimizing costs or managing risks except to avoid incurring shareholder penalties for missing the RPS mandates. In fact, PG&E has accrued a 3.3 cents per kilowatt-hour premiumabove the market value of its RPS portfolio to protect against a potential “price spike” between now and 2027. It is no wonder that customers have become unhappy with how the IOUs have managed their generation portfolios.
Nick Chaset is the CEO of East Bay Community Energy which is a community choice aggregator (CCA) that serves Alameda County. He also was Commission President Michael Picker’s chief advisor until last year when he left for EBCE. He explains in this article how two proposed decisions that the CPUC is considering are fundamentally wrong and will shift cost onto CCA customers. (I testified on behalf of CalCCA in this proceeding. I’ll have more on this before the Commission’s scheduled vote October 11.)
Figure 1 – CPUC’s Proposed Resource Adequacy Value vs. True Market Values
Figure 2 – GHG Premium Value Missing from CPUC Proposed Decision
Figure 3 – Falling Utility Rates as Customers Depart Filed in Their ERRA Rate Applications
The University of California ARE Update published a short study that found that the drought emergency regulations adopted by the State Water Resources Control Board were only 18% more costly than the most “efficient” standards. In May 2015, the State Water Resources Control Board adopted Resolution No. 2015-0032 which imposed restrictions to reduce water use by local agencies by 4 to 36 percent depending on their circumstances. Northern California agencies were to reduce usage by 16.2 percent on average, while Southern California utilities were to reduce by 22.5 percent. In the end, Northern California utilities far exceeded their target with a 23.3 percent reduction, and Southern California’s just missed theirs with an average of 21.4 percent. M.Cubed conducted the economic study of the regulations, and found that the insurance benefits were likely substantial enough to justify the costs.
The real headline of the study should be “Drought regulations remarkably efficient!” Given that the regulations were developed in just a few months and that they were done on a prospective basis with uncertainties and unknowns (e.g., the price elasticities referenced in the study), missing the mark by only 18% is truly remarkable. In comparison, the California Air Resources Board may have missed the mark by more than 100% in setting out its AB 32 Greenhouse Gas Reduction Scoping Plan in 2008 by relying too heavily on mandated measures such as renewables generation and certain types of energy efficiencies instead of more effective market based measures.
Nevertheless, the study appears to the make mistake of making the classic economist’s joke “sure it works in practice, but does it work in theory?” Consumers are chastised for behavior that doesn’t fit the fitted values for price elasticities. The study compares the mandated and achieved reductions and notes that achieved reductions were more even across agencies than the mandates. Agencies with lower mandates achieved higher reductions, and those with higher mandates fell short on achievements. Instead of questioning the original price elasticity estimates–and such estimates commonly have a wide range and are often situation specific–the report just plows ahead as though these theoretical results should have driven human behavior.
The more interesting question the researchers should have asked given the consistent patterns in achieved versus mandated reductions is what factors caused these agencies to diverge from the mandates. Geography is clearly only part of the reason. It also appears that there is not as much “demand hardening” at the low end of use, and a higher premium put on water uses at the upper end. These factors have implications for how we should modify our price elasticity estimates.
M.Cubed partner David Mitchell is the lead author on this PPIC report that reviews the responses by urban agencies to the California’s recent drought and looks at the lessons learned. He’s speaking during a webinar on June 16 at noon. In addition, he co-authored an opinion article for the Sacramento Bee.
We just looked at the frequency of different water conditions over the last 15, 35 and 110 years. Over the longer period, wet, “normal” or average, and dry years have occurred in about equal shares, at about one-third each. But over the last 35 years dry conditions have occurred in about half of the years. Over the last 15 years, wet conditions have declined to less than 20% of the years.
We’re also working with Sustainable Conservation on a program that will incentivize growers to use diverted floodwaters to recharge groundwater aquifers below their fields.
California is likely to see more extreme floods and drought with climate change, but the state’s water infrastructure may not be ready.
We’re now in the midst of the “third wave” of electricity industry reform in California. The first was in the early 1980s with the rise of independently-owned cogeneration and renewable resources. Mixed with increased energy efficiency, that led to a surplus of power in the late 1990s, which in turn created the push for restructuring and deregulation. Unfortunately, poorly designed markets and other factors precipitated the 2000-01 energy crisis. The rise of renewables and distributed resources is pushing a third wave that may change the industry even more fundamentally.
I wrote a paper in 2002 on how I viewed the history of California’s electricity industry through 2001 and presented this at a conference. (It hasn’t yet been published.) I identify some different factors for why the energy crisis erupted, and what lessons we might learn for this next wave.