California’s Outages Are a Teachable Moment

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Two keen observers of the power sector, Jigar Shah and Cheryl LaFleur, have noted that the responses to the rotating power outages in California on August 14 and 15 became a Rorschach test of individual preexisting biases. Before many facts were known, a favorite villain was chosen and a conclusion drawn: too much solar, not enough gas, underperforming gas, corrupt regulators, inept utilities, and failed market design are a few examples. Rather than jumping to such conclusions, however, we should recognize that extreme events and the responses that follow offer a high-profile teachable moment — and we should be learning and teaching all that we can.

Some facts surrounding the event have become clearer over the past several weeks, and more will be learned about the strengths and vulnerabilities of the California grid as historically hot weather and new wildfires continue to affect consumption and available generation. One thing is certain: The climate crisis is presenting increasingly severe challenges, and the need to effectively accelerate power sector transformation has never been more apparent.

We need to know how severe the controlled outages were and what prompted them. These outages are a signpost for potential larger-scale events, so assessing the need for action to protect system stability is important. Short-term actions to fend off additional supply-related outages have been implemented, and they are working. Long-term actions require the benefit of factual investigation and due consideration of fixes that accelerate market transformation while addressing any identified system vulnerabilities. Distribution utility practices, utility regulations, wholesale operating practices and market design improvements need to be considered to address identified vulnerabilities.

I am concerned that the investigation may overlook how this event affected people. Shah noted that the health impacts of outages tend to fall disproportionately on lower-income communities. The investigation should include a focus on how the outages affected people and whether they affected some populations disproportionately.

Above all, events like these need to generate lessons and dispel myths so that we can accelerate our progress toward power sector transformation. Key questions include:

  1. Who was affected?
  2. How severe were the simultaneous demand and supply contingencies?
  3. What does the success of voluntary load reduction on August 17 and beyond tell us?
  4. How did the California Independent System Operator (CAISO) market perform?

Who was affected? The CAISO staff provided a public briefing on August 17 to share information about the outages that occurred on August 14 and 15. The briefing indicated that on August 14, a total of 1,000 MW of load was shed for 80 minutes, with about 410,000 customers affected by rotating outages during that time. The August 15 event was much smaller — 470 MW shed for about 20 minutes. The customers affected by the rotating outages are determined by the distribution utilities (Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric). I have not seen a report on which customers were affected, nor have I seen assessment of whether any adverse public health impacts were experienced.  While the duration of the outages is modest from what we know so far, we should not miss the opportunity to learn whether they threatened public health or disproportionately affected certain low- and moderate-income communities. Setting a positive example assessing any disproportionate impacts on these communities is useful and will encourage similar assessments for other outages that may be more frequent and with greater duration.[1]

How severe were the simultaneous demand and supply contingencies? We know this was an extreme weather event that was prolonged, severe, and extended through the Southwest, California, and the Northwest, so we know that demand was higher than expected while availability of supply-side resources from the region was lower than expected. The CAISO staff public briefing summarized the specific contingencies that led to the need to shed load on August 14 (the unexpected loss of a 475 MW generation facility, combined with higher-than-expected loads and lower-than-expected imports) and August 15 (the unexpected decline of 410 MW of wind production, combined with an unexpected loss of a 400 MW generation unit). In addition to these discrete, incremental events, a joint letter to Gov. Gavin Newsom from CAISO, the California Public Utilities Commission (CPUC) and the California Energy Commission (CEC) identifies many areas for investigation that indicate additional contributing factors. Identifying these factors will provide insight into modeling, resource and program deficiencies that should be reflected more accurately going forward. Identifying these deficiencies will be helpful in the ongoing resource adequacy discussion in California and the West.

What does the success of voluntary load reduction on August 17 and beyond tell us? One commentator ominously predicted that the “wolf is at the door,” indicating a common expectation that outages would be worse on a Monday (August 17) than they had been on Friday and Saturday. Instead, there were no rotating outages needed at all. The CAISO staff briefing for August 18 shows that more than 4,000 MW of load was shaved from consumption during the highest-stress hours on August 17. That 4,000 MW substantially exceeds the 800 MW of emergency demand response accessed by CAISO on August 14; it exceeds the approximate 1,000 MW of diesel generation authorized to operate during the emergency and also swamps the magnitude of the deficiency (about 1,000 MW) that caused the need for outages on August 14. This tells me that demand response programs in California are broken, and the potential for an order-of-magnitude increase in demand response is reasonable. Severin Borenstein provides two straightforward measures to expand demand response in California: critical peak pricing and improved communication with customers.

How did the California ISO market perform? We know that the rotating outages were limited and did not persist into the following week, so there is evidence that policy actions and the market effectively limited more serious damage. However, we do not yet know whether prices effectively conveyed the urgency of the event leading up to and through the contingency periods. Prices were higher — but were they high enough to elicit a fast response to the contingency events? Further consideration of raising price caps to induce greater resource participation is worth consideration. The CAISO Department of Market Monitoring will fully vet any potential withholding, and that needs to be included in the assessment. At the same time, we also need to understand whether suppressed price signals originating from market design choices contributed to insufficiencies in demand- and supply-side resources.

A full examination of the facts surrounding the rotating outages is needed before long-term policy responses are implemented. The short-term actions have been effective, and the distribution utilities, the CPUC, CEC and CAISO should be commended for rising to the challenge. The joint agency memo to Newsom cites many of the questions that need to be investigated to identify lessons, expose myths and craft solutions. Most important, solutions must address the lead story: The climate crisis is at our door, and accelerating progress toward an equitable, decarbonized power sector remains the focus.

Note: Dr. Carl Linvill is a member of the Western Energy Imbalance Market (EIM) Governing Body. This blog post reflects his individual views, not those of the EIM Governing Body or CAISO.


[1] The question of how outages and blackouts affect communities is important to understand for all outage events, whether they are controlled, short-duration outages like these, longer-term outages arising from local distribution system deficiencies or more prolonged outages arising from more severe events. Outages on distribution systems are the most frequent, often last longer than an hour and tend to affect some neighborhoods more often than others. Wildfire season brings Public Safety Power Shutoffs (PSPS), which leave affected customers without power for an entire day or for several days as the utility protects us all from additional wildfires. And wildfire damage can deprive customers of power for days or even weeks.

California’s Mandatory PV Code Amendment: Is It Really Time for This?

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The press has been abuzz this summer about the California Energy Commission’s (CEC) new building code amendment that will require most single-family residential and low-rise multi-family dwellings to incorporate PV systems at construction. The amendment takes effect in 2020. Buildings located where solar will not perform well will be exempt, but the typical California neighborhood of the future may look something like the Hawaiian one pictured below.

Criticism of the amendment has come from several places, including the Haas Energy Institute at UC Berkeley. One concern offered by critics is that residential PV is not cost-effective compared with central station solar. Another concern is the ramping and storage issues surrounding solar, such as the “duck curve.” These are important, but were adequately considered by the CEC.

California is again unambiguously ahead of the curve on this front, but it isn’t the “first state” this time. Hawaii mandated solar water heating on single-family homes more than a decade ago. It has worked out well, and to my surprise, some builders installed PV-to-electric water heaters in order to meet the standard, instead of installing traditional solar-thermal water heaters. PV has gotten that cheap.

Today, the average Hawaii residential consumer uses about 15 percent less grid-supplied electricity than a decade ago, and a significant portion of the decline is due to solar, both water heat and PV. In Hawaii, where electricity is expensive, this has been a significant benefit to occupants of new homes.

The duck curve challenges in California—and Hawaii—are very real, but both states are taking steps consistent with the ten strategies we presented in Teaching the Duck to Fly. These include time-varying rates, targeted energy efficiency, pursuit of peak-oriented renewables, ice-storage air conditioning and grid-integrated water heating, and other effective measures.

I too was initially skeptical of California’s blanket mandate. But California’s notion that “making it code” will turn rooftop PV into a lower-cost commodity has certainly been true for other mandated technologies, such as high-performance glazing, heat pump water heaters, and high-efficiency refrigerators.

One recent news story on the CEC action stated, “For residential homeowners, based on a 30-year mortgage, the Energy Commission estimates that the standards will add about $40 to an average monthly payment, but save consumers $80 on monthly heating, cooling and lighting bills.” Many readers of this post would want to see a long-run marginal cost analysis, not a retail bill analysis, but its 2:1 benefit:cost ratio for the consumer makes it attractive, not a penalty, so I would approach that analysis with some confidence.

And CEC has explicitly called out one of the biggest benefits of rooftop PV: its shading effect that reduces air-conditioning loads. One study from San Diego showed that for every kWh generated by a PV system, consumers saved another 0.3 kWh in air conditioning usage. Another, from Arizona, showed an 11 percent reduction in electricity costs, taking in to account both reduced AC load and increased heating load. Taking reserves, marginal line losses, and distribution capacity costs into account, this is a big boost to PV cost-effectiveness that most analysts ignore.

Solar prices have indeed come down sharply, but the prices for small-scale residential installations remain higher than those of large-scale systems. However, residential systems have other advantages over central-system solar. They include avoided transmission and distribution costs, avoided distribution losses, and reduced air-conditioning requirements due to roof shading. The CEC considered all of these factors.

The graphic below shows a recent comparison of PV system costs. Residential rooftop systems cost about three times as much as large utility-scale systems. If Xcel Energy’s recent bids (and those received by utilities from Mexico to India to the United Arab Emirates) are representative, this means 3 cents per kWh for utility-scale systems compared with about 9 cents per kWh for small rooftop systems. But one stated goal of the CEC is to make rooftop solar a “commodity” to reduce the “soft costs” of installation. With a mandate, for example, “customer acquisition” costs drop to zero. If the installed residential PV system drops to about 6 cents per kWh with a combination of cost reduction and financing through low-cost mortgages, the societal cost-effectiveness will be pretty solid.

Source: GTM Research and Solar Energy Industries Association

By making solar a code element, subdivision builders will simply treat it as one more subcontractor task, along with plumbing, electric, roofing, framing, drywall, and painting. And the majority of the “supply chain, overhead, and margin” cost—fully one-half of current small-scale solar costs—would shrink to resemble the utility cost stack.

Before one criticizes California’s decision here, one should consider the results of past policies. For instance, let’s compare two states with very different approaches: Georgia and California. Georgia has lower electric rates. California has lower electric bills.

First there are a few caveats regarding this comparison: It uses 2015 income data but 2016 electric bill data; the picture would be more full with an analysis of natural gas rates, too; and housing stock and climate adjustment might be appropriate (though Georgia’s coal-heavy electricity mix contributes more to that climate adjustment). But overall, while California’s residential electric rates are much higher than those in Georgia—17.4 cents per kWh average vs. 11.5 cents per kWh—California’s average electricity bills are lower than those in Georgia.

Georgia has chosen the low-regulation, high-supply approach to energy. Weak energy codes, no appliance standards, few utility incentive or rebate programs, and electric rate design with relatively high fixed charges and low per-kWh charges.

California has chosen a high-regulation, high-efficiency approach, with lots of appliance and building standards, lots of utility incentive and rebate programs, and electric rate design that encourages efficiency and frugality. Now they’ve added another building standard: integrated PV.

The bottom line is illustrated in the table below. The electricity burden in California is much lower than in Georgia, despite the RPS, EE programs, rate design, and other California policies that have drawn the ire of some. In fact, it is not despite these policies that Californians enjoy lower electricity bills than Georgians, it’s because of them.

Comparison of California and Georgia Electricity Bill Burdens
California Georgia
Average monthly electric bill $95.20 $130.87
Average monthly household income $5,375 $4,270
% of income going to pay for electricity 1.8% 3.1%


California’s past efficiency and rate policies—including the California Alternate Rates for Energy (CARE), a very generous assistance program for low-income households—have kept electric bills manageable for nearly all households. That’s an impressive achievement in a high-cost business environment like California’s, with expensive real estate, labor, taxes, and transportation congestion costs.

The bottom line: California is again ahead of the curve in mandating PV systems in new homes. The experience of Hawaii’s solar water heat mandate shows that a code requirement dramatically reduces costs of the measure over a very short period of time. At lower costs, residential PV will likely be quite cost-effective, countering the critics’ argument that it’s too pricey compared with utility-scale options. And as our state comparison shows, California’s aggressive energy efficiency policies of the past three decades are clearly paying big benefits to the state’s electric consumers. Its rooftop PV requirement will be no different.


Across the Pond, but in the Same Boat: The 2017 California–Germany Bilateral Energy Conference

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Germany and California hold the distinctions on their respective continents of being first movers in decarbonization policy. Both have aggressively pursued power sector decarbonization with ambitious renewable energy policies, and both have now set their sights on decarbonizing the building and transport sectors. While they have differences, their implementation aspirations are strikingly similar. In recognition of these commonalities, the California Energy Commission and the German Ministry of Economic Affairs and Energy hosted the first California–Germany Bilateral Energy Conference in mid-October. The idea behind this meeting of the minds was to share innovations and lessons learned in the aggressive pursuit of decarbonization goals.

The target trajectories for both regions run parallel, aiming to reduce CO2 emissions by 80 percent by 2050 compared with 1990 levels. In 2016, renewable energy sources already met 32 percent of Germany’s power demand. California has charted a similar course—the state will meet 33 percent of its renewable portfolio standard before the 2020 target, even without including around 7,000 MW of behind-the-meter solar.

Their plans for addressing the upcoming challenges of power sector transformation are also similar, and with good reason. The German Ministry published a discussion paper in fall of 2016 on 12 trends and tasks for the power sector through 2030 and shared it with the California Independent System Operator (CAISO). CAISO’s discussion paper, “Electricity 2030: Trends and Tasks for the Coming Years,” identifies eight key trends for California, and the overlap reflects their collaboration.

While there are many similarities, the paths do differ in some ways. One difference lies in how the regions view the challenges associated with higher penetrations of distributed energy resources, such as demand response, behind-the-meter generation, energy efficiency, and storage. Germany is presently focused on integration and cost allocation challenges, while California is focused on linking customer resources to the power and transport sector transitions in a way that lowers the cost of achieving both. A second difference is California’s focus on the economic benefits of being a U.S. leader in the energy transition (70,000 jobs in solar power alone and 500,000 jobs in the clean tech sector), which derives from the importance in the United States of demonstrating that decarbonization is not inconsistent with prosperity.

It is fair to say that these differences reflect where the two regions are on their respective implementation pathways, rather than fundamental differences in direction.

Differences notwithstanding, participants in the bilateral conference agreed that the technologies and lower costs of today enable us to move forward aggressively. The primary hurdles to be overcome are customer acceptance, institutional changes (including regulatory changes and changes in utility practices and procedures), and incorporating decarbonization of the transportation and building sectors into the energy transition. Another common theme among the speakers was the need to focus on maximizing the cost-effectiveness of measures going forward.

Policymakers aspiring to advance power sector transformation in their jurisdictions will face similar challenges. Germany and California are sources of both encouragement and solutions for each other. Both regions envision energy efficiency playing a significantly greater role and variable renewable energy sources “shaping the power system” by 2030. They also seek regional cooperation and integration through market extension, encouraging flexible resources to complement clean variable generation, and incorporating building and transport decarbonization into power sector transformation. Whether others look to California’s Energy Imbalance Market (and potential regionalization) in the Western United States or Europe’s Internal Energy Market, declining fossil fuel use and the need for regional cooperation rank high among the favored solutions.

A final lesson to be learned from these two leaders is the power of collaboration. While this conference was ultimately a conversation between two regions about their respective experiences, both jurisdictions expressed hope that more collaboration emerges. For example, Germany seemed especially impressed in the progress California is making in electrifying transportation, and California seemed equally taken with the progress Germany is making in offshore wind development and regional coupling. In short, Germany and California are saying, “Why stop here?”

The bilateral conference offered a powerful stepping stone for ongoing dialogue and increasing exchange and collaboration on joint projects. These collaborative efforts will accelerate the development of best practices, which will not only benefit the two regions, but will undoubtedly produce global benefits as well. We look forward to seeing where these boats sail.