PG&E in its 2020 ERRA Forecast Proceeding testimony wrote “however, BTM DG [behind the meter distributed generation] has a limited impact to the annual system peak as customer-owned solar photovoltaic (PV) generation is minimal during the peak hour of 7 p.m.” Uh, how does PG&E know that customer-owned solar doesn’t contribute to reducing the system peak if PG&E does not meter that generation?
PG&E actually has it wrong. Customer-owned solar has in fact reduced the former pre-solar peak that used to occur between 2 and 4 p.m. The metered load that PG&E can see, which is customer usage minus solar output (BTM DG), has shifted its apparent peak from 4 p.m. to 7 p.m.–3 hours. The graphic above illustrates how this shift has occurred. (PG&E produced a similar chart of its 2016 loads in its TOU rate rulemaking.) So BTM DG has had a profound impact on the annual system peak.
Severin Borenstein at the University of California’s Energy Institute at Haas posted on whether a consumer buying an electric vehicle was charging it with power from renewables. I have been considering the issue of how our short-run electricity markets are incomplete and misleading. I posted this response on that blog:
As with many arguments that look quite cohesive, it is based on key unstated premises that if called into question undermine the conclusions. I would relabel the “correct” perspective as the “conventional” which assumes that the resources at the margin are defined by short-run operational decisions. This is the basic premise of the FERC-designed power market framework–somehow all of those small marginal energy increases eventually add up into one large new powerplant. This is the standard economic assumption that a series of “putty” transactions in the short term will evolve into a long term “clay” investment. (It’s all of those calculus assumptions about continuity that drive this.) This was questionable in 1998 as it became apparent that the capacity market would have to run separately from the energy market, and is now even more questionable as we replace fossil fuel with renewables.
I would call the fourth perspective as “dynamic”. From this perspective these short run marginal purchases on the CAISO are for balancing to meet current demand. As Marc Joseph pointed out, all of the new incremental demand is being met in a completely separate market that only uses the CAISO as a form of a day to day clearinghouse–the bilateral PPAs. No load serving entity is looking to the CAISO as their backstop resource source. Those long term PPAs are almost universally renewables–even in states without RPS standards. In addition, fossil fueled plants–coal and gas–are being retired and replaced by solar and wind, and that is an additional marginal resource not captured in the CAISO market.
So when a consumer buys a new EV, that added load is being met with renewables added to either meet new load or replace retired fossil. Because these renewables have zero operating costs, they don’t show up in the CAISO’s “marginal” resources for simple accounting reasons, not for fundamental economic reasons. And when that consumer also adds solar panels at the same time, those panels don’t show up at all in the CAISO transactions and are ignored under the conventional view.
There is an issue of resource balancing costs in the CAISO incurred by one type of resource versus another, but that cost is only a subcomponent of the overall true marginal cost from a dynamic perspective.
So how we view the difference between “putty” and “clay” increments is key to assessing whether a consumer is charging their EV with renewables or not.
M.Cubed produced four reports for Sustainable Conservation on using floodwaters to recharge aquifers in California’s Central Valley. The first is on expected costs. The next three are a set on the benefits, participation incentives and financing options for using floodwaters in wetter years to replenish groundwater aquifers. We found that costs would range around $100 per acre-foot, and beneficiaries include not only local farmers, but also downstream communities with lower flood control costs, upstream water users with more space for storage instead of flood control, increased hydropower generation, and more streamside habitat. We discussed several different approaches to incentives based on our experience in a range of market-based regulatory settings and the water transfer market.
Don Cameron at Terranova Ranch started doing this deliberately earlier this decade, and working with Phil Bachand and UC Davis, more study has shown the effectiveness, and the lack of risk to crops, from this strategy. The Department of Water Resources has implemented the Flood-MAR program to explore this alternative further. The Flood-MAR whitepaper explores many of these issues, but its list of beneficiaries is incomplete, and the program appears to not yet moved on to how to effectively implement these programs integrated with the local SGMA plans. Our white papers could be useful starting points for that discussion.
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