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The Problem with Demand Response

A recent event highlights the difficulties setting baselines for demand response programs. 

It’s starting to feel like fall. In Berkeley, we are sensitive to subtle changes, but there was a bit of chill in the air last week and the sun is setting earlier.

Three months ago, the season change – from spring to an early summer heatwave – provided a poignant example of the existential problem with demand response.

Here’s what happened, as best I can reconstruct. Tuesday, June 20 was hot in Southern California. Temperatures were above 100 in Los Angeles and above 110 further inland. At 4PM that day, Southern California Edison (SCE) called on its demand response programs and achieved nearly 500 MW of reductions. The reductions are clear in the graph below – there’s a dramatic drop in load between 4:00 and 4:07 PM.

Source: SCE presentation to the CEC.

Let me be clear about terms. By “demand response,” I’m referring to programs where customers are paid, “to reduce their consumption relative to an administratively set baseline level of consumption,” following and quoting a very useful article by Jim Bushnell, Ben Hobbs and Frank Wolak. For example, SCE has an, “Agriculture and Pumping Interruptible Program,” through which customers are rewarded if they allow the utility to install a device on equipment to remotely turn it off when the electricity system is stressed, as it was in Southern California on June 20.

I’m not including “dynamic pricing” programs, such as SCE’s Summer Advantage Incentive critical peak pricing program. SCE declared June 20 a critical peak pricing event, meaning that some of their customers faced higher prices from 2 to 6PM that day.

Unfortunately, though, the dramatic 500 MW drop was not recognized by the California Independent System Operator as a real reduction. It appears that the California Independent System Operator’s (ISO) process for determining demand response payments decided that the customers’ consumption was above their baseline. The rules around demand response are super arcane, even for the electricity sector. But, I believe this means that the ISO charged SCE for these overages, rather than rewarding them for their customers’ reductions.

What’s a baseline? In a demand response program, customers are cutting their load on a specific date and time, called a demand response “event.” The challenge is to determine how much the customer would have been consuming absent the event. That’s the role of the baseline – it’s designed to reflect the “but-for” consumption levels.

Here’s where the season change comes in. The ISO calculates baselines using the average of the 10 most recent non-event business days (the “10-in-10” methodology), with an adjustment – up to a 20% adder – for conditions on the event day. Since June 20 was an early season heatwave, recent average consumption was a lot lower than the peak levels reached during the high temperatures that day. The graph below shows what Southern California Edison reported for one of its residential demand response programs. The baseline (in blue) is one third lower than the actual June 20 load (in orange), even after the apparent reduction.

Source: SCE presentation to the CEC.

Ah, you might say, why doesn’t the ISO just do what we can do with our eyes in the first graph above and compare 4:00 to 4:07? Here’s one problem with that approach: if demand response customers suspect an event will be called, maybe because the day is really hot, they might overconsume – for example, by pre-cooling their house – before 4 PM in order to inflate their baseline. One advantage of the ISO’s 10-in-10 methodology is that customers are unlikely to know that they’re in a baseline period until after the fact.

So, why am I hating on demand response? I certainly don’t object to the idea of engaging demand in electricity markets. What reasonable economist could object to working with both sides of the market – supply and demand? Plus, there are some super innovative technologies being developed to help consumers reduce demand.

The thing I object to is paying customers to reduce relative to an error-prone baseline. As we’ve emphasized in the energy efficiency context, counterfactuals are hard to develop. Economists often point to the possibility that customers will strategically increase their demand during baseline periods in order to later be paid to reduce relative to an inflated benchmark. The June 20 example highlights the opposite problem – the compensation mechanism overlooking what appear to be real reductions. If customers are taking steps to reduce and then not benefiting from it, this will dampen interest in demand response programs. And, ultimately, this will dampen company’s incentives to develop more cool technologies to help them.

It’s especially frustrating for economists to watch these baseline debates as there’s such a simple solution – use a baseline of ZERO. Don’t pay customers to reduce relative to an administratively set baseline when the electricity system is stressed, like on June 20. Instead, charge them more for consuming during these periods. Ideally, the prices, customers pay would vary by both time and location. Sound familiar? That’s exactly what dynamic pricing does.

So, why have we gone so far down the demand response path, with such limited success introducing any form of dynamic pricing? I have ideas about why, and also hope blog readers who are more steeped in the debate can chime in. One guess is that it’s been difficult to develop retail rates that would expose a lot of customers to wholesale price variation. Regulators may be locked into the status quo and have a hard time introducing new pricing paradigms. Framing a program as rewarding customers for reductions instead of charging them for consumption is probably politically more palatable.

But, the June 20 event highlights that there are costs to going this way. We’ll get things wrong and eventually get less demand-side participation. Also, Severin’s previous blog post emphasizes the costs when customers game their baselines or get paid through a demand response program for doing something they would have done otherwise, like going on vacation. Are the regulators’ needs for political acceptability strong enough to outweigh these costs? I don’t know.

Addendum: Two quick notes based on correspondence with SCE: The June 20 event discussed was in 2016, not this year. Also, the agriculture pumping program used in the example wasn’t dispatched that day. SCE attributes most of the drop to an air conditioner cycling program whereby residential and commercial customers agree to let the utility turn off their compressors during an event.

Catherine Wolfram View All

Catherine Wolfram is Associate Dean for Academic Affairs and the Cora Jane Flood Professor of Business Administration at the Haas School of Business, University of California, Berkeley. ​She is the Program Director of the National Bureau of Economic Research's Environment and Energy Economics Program, Faculty Director of The E2e Project, a research organization focused on energy efficiency and a research affiliate at the Energy Institute at Haas. She is also an affiliated faculty member of in the Agriculture and Resource Economics department and the Energy and Resources Group at Berkeley.

Wolfram has published extensively on the economics of energy markets. Her work has analyzed rural electrification programs in the developing world, energy efficiency programs in the US, the effects of environmental regulation on energy markets and the impact of privatization and restructuring in the US and UK. She is currently implementing several randomized controlled trials to evaluate energy programs in the U.S., Ghana, and Kenya.

She received a PhD in Economics from MIT in 1996 and an AB from Harvard in 1989. Before joining the faculty at UC Berkeley, she was an Assistant Professor of Economics at Harvard.

46 thoughts on “The Problem with Demand Response Leave a comment

  1. Catherine, an excellent overview of the shortcomings of Automated Direct Response (ADR) programs.

    The inability to use air conditioning, refrigeration, industrial/manufacturing equipment, and other high-draw applications when needed is a very real cost which is increasingly foisted by utilities on their customers. Consumers have never had a real choice of providers for electricity at the retail level, a fundamental requirement of free markets. With ADR, consumers are being forced to bear the burden of availability – to use electricity when it’s convenient for utilities instead of when they need it.

    We didn’t have these problems before the 2005 repeal of FDR’s Public Utility Holding Company Act, under which electricity providers were required to serve “in the public interest”. Before then, the responsibility of providing electricity when needed fell on the shoulders of utilities. If renewables weren’t available, they had to have enough power to meet demand, everyone paid the same rate, and lower-income customers weren’t charged extra to run their dishwashers on cloudy days or when the wind wasn’t blowing.

    “Supply/supply” doesn’t even sound right.

    • Huh? Nothing really changed in 2005, at least in California. We didn’t notice any changes in service delivery, only in ownership arrangements.

      • mcubedecon, ownership arrangements changed everything after 2005. Utilities were no longer subject to annual review by the SEC; they were no longer prohibited from making campaign contributions, and subject to strict prohibition on lobbying. They were no longer prohibited from investing in other more risky ventures using capital accumulated from ratepayers. What could possibly go wrong, when your local electricity monopoly is able to bribe their state representatives? In the last five years, energy companies have donated over $100 million to the campaigns of state legislators, replacing healthcare as the #1 source of influence in Sacramento.

        The reason electricity rates are 40% higher than they were ten years ago has nothing to do with the price of generating electricity. It has everything to do with energy holding companies like Sempra Energy, Pacific Gas & Electric Corporation, and Edison International “selling themselves” natural gas to generate electricity, then billing ratepayers at the price they billed themselves. See how that works? When you can make up your cost of doing business then bill captive ratepayers for it, the sky’s the limit.

        Because Americans have an aversion to history and the memories of goldfish, holding companies are back in business again. I urge you to read FDR’s Public Utility Holding Company Act of 1935 (PUHCA) , then what replaced it – “The Energy Act of 2005” – to see for yourself the loopholes 559 pages of legislation can guarantee for Big Oil. As a starter, check out PUHCA for Dummies, a warning written by former FERC attorney Lynn Hargis in 2003 for what was about to happen:

        In December of 2004 she testified before the Securities and Exchange Commission:

        “In my thirty-odd years of electric utility regulatory practice, I have come to believe that the Public Utility Holding Company Act of 1935 (“PUHCA”) is the most important piece of federal legislation relating to electric and natural gas utilities. I believe that if PUHCA is repealed, either by the Congress or administratively by this Commission, the consequences to electric and natural gas utility consumers and to our national economy may be catastrophic.”

        By throwing in perks for special interests, George W. Bush and a cabal of Texas oilmen were able to push the bill through Congress anyway on August 8, 2005. Catastrophe unfolding.

        • Bob, I don’t disagree with your characterization of the change in utility politics, but the 2005 change had no real effect on the obligation to serve which was your original point.

          • mcubedecon, San Onofre and Diablo Canyon are being closed, part and parcel, because of the repeal of PUHCA.

            The first exemption from PUHCA was granted in 1987 for a company named Enron, and it’s been downhill ever since. In 2013 when closing San Onofre permitted SDG&E’s holding company, Sempra Energy, to raise electricity rates by 56%, making them the highest in the continental U.S ($.28/kWh); when the closure permitted Southern California Edison to bill ratepayers for $billions in capital costs for a plant with decades of remaining utility; when the closure added 9 megatons of CO2 to California’s emissions, then yes – that had a real effect on “public interest”.

            Since 1935 the chief legal criteria to protect ratepayers from exploitation by utility monopolies is that phrase, and it was effective (by 1949 utility holding companies no longer existed). A cornerstone of the U.S. regulated utility model, it appears more than once per page in PUHCA. In The Energy Act of 2005, it appears once every 19 pages – that’s no accident.

          • Bob
            SONGS closed for two reasons, neither to do with repeal of PUHCA. The first was the failure of the new steam turbines and the enormous costs to retrofit a fix. The second was the need to install a new cooling system to replace the once-through system ordered closed by the SWRCB.
            Similarly, Diablo was closed for two reasons. Again Diablo faced a huge expense in replacing it once-through system that would at least 50% to its cost according to PG&E’s filings in it closure application. And second the departing load to CCAs is shrinking the base of bundled customers who pay for that resource. PG&E projected a large decrease in the plant output that increased cost per kWh even further.
            So in both cases, its new regulatory environments and economics that is forcing closure of those plants.
            As to rate increases, PUHCA didn’t forestall huge increases prior to 2005, e.g., the 40%+ increase in 2001 to pay for the energy crisis debacle (despite the fact that PG&E and SCE had transferred the CTC fund prematurely to their holding companies.)

          • mcubedecon, the steam turbines at SONGS were under warranty by Mitsubishi Heavy Industries and the total replacement cost would have been $670 million. The year before, an identical steam turbine replacement took place at Davis-Besse Nuclear Power Plant in Ohio, at a lower cost. The plant was back online in 97 days.

            I have no idea what the source might be for your claim San Onofre’s Once-Through Cooling (OTC) system was “ordered closed” by SWRCB – it sounds like a product of “Mothers for Peace”, “Friends of the Earth” or one of our other local anti-nuclear fear factories. On December 27, 2012 SWRCB had approved an extension requested by Southern California Edison to delay addition of Large Organism Exclusion Devices to its existing OTC system when the plant was permanently shut down six months later.

            Perhaps you didn’t read my post, so I’ll repeat myself: PUHCA would have forestalled the 40%+ increase in 2001 to pay for the California Energy Crisis debacle had the company responsible for the crisis – Enron – not been granted an exception from PUHCA 14 years earlier.

            Re: Diablo Canyon, the company’s goal is to replace 100% carbon-free nuclear energy with natural gas, to the detriment of both the environment and ratepayers, because PG&E Corporation can increase its revenue. The claims you make, again, sound like activist PR and have no relationship to the basis behind the closure or the economics involved. I suggest you review the progress of PG&E’s application A-16-08-006 “For Approval Of The Retirement Of Diablo Canyon Power Plant” on, because I have neither the time nor interest to continue to respond to fabricated anti-nuclear talking points.

          • No matter what the cost might have been, the steam turbine replacement cost was one of the two key factors leading to the closure, not the PUHCA repeal, which was your original claim. And SONGS gained a deferral in complying with the OTC order, but as with Diablo, it was going to have to comply in its next relicensing phase. The cost of the replacing the turbines wasn’t justified over the short period remaining. (I worked for the CEC on evaluating the potential impacts of combination of the OTC and air quality regs on reliability.)
            If you think that Enron was solely responsible for the market crisis in 2000-01, I suggest that you read the several treatises on the causes of the crisis, including Jim Sweeney’s ( and mine (posted on my blog site.) Enron is the popular mythological source because it’s so sexy and had a movie made about it.
            As for Diablo Canyon, I helped draft the testimony submitted on behalf of the CCA and DA customers. I am very well aware of why Diablo is being closed. PG&E expressly lists (1) the high costs of upgrading Diablo and (2) the reduced bundled load as the primary reasons for closing the plant in its application and testimony. PG&E then submitted a request to be exempted from the IRP process to procure various resources, but that was entirely separate for the rationale for closure. Fortunately, PG&E withdrew its procurement proposal.

          • “No matter what the cost might have been?” mcubedecon, it shouldn’t be necessary to point out when determining whether a facility is to be shut down the cost of maintaining it does matter. That’s how business works, and certainly how natural monopolies should work – but instead of maintaining their facility “in the public interest” (there’s that pesky phrase again) monopoly Southern California Edison chose to shut down SONGS so it could enhance its bottom line.

            Not only could Edison make more money by burning natural gas, but the shutdown of SONGS, approved by the California Public Utility Commission, would permit SoCal Edison to soak ratepayers for an estimated $14 billion in capital costs and costs for new gas-fired generation. The capital costs were on a plant which, if maintained, would have served the public for another forty years (there is no evidence whatsoever SWRCB would not have approved the SONGS’ OTC system, which had been working fine for forty years). The shutdown would raise California’s CO2 emissions by 9 million tonnes. If any of these are in the public interest, next you’ll be telling me radiation leaking from the turbines at SONGS was a danger to the public, or then-CPUC President Michael Peevey was playing cards, and not negotiating terms of the SONGS shutdown with an Edison official at a secret 2013 ex-parte meeting in Poland.

            You claim you’re “well-aware” of the motivations behind Edison’s and PG&E’s nuclear closures, but unless you sit on the boards of both companies, you’re basing your awareness on public documents submitted to CPUC. Anyone can read aware PG&E’s application and see its foundation is a “Joint Proposal” – one made up of parties selected by the corporation alone behind closed doors – and that is presumably supposed to represent public interest.

            Re: the California Electricity Crisis of 2000-2001, you’re wrong. Without Enron’s exemption from PUHCA, its acquisition of Portland General Electric Company, and its ability to manipulate energy markets as an interstate energy holding company, the crisis would not have happened – period. A good summary, and a lousy recommendation, from SEC Commissioner and Bush-appointee Isaac Hunt here:

            Testimony Concerning The Enron Bankruptcy, the Functioning of Energy Markets and Repeal of the Public Utility Holding Company Act of 1935

            Hunt here advocates repealing PUHCA, but notes

            “The SEC has always stressed, however, that, in order to protect the customers of multistate, diversified utility holding companies, it is necessary to give the Federal Energy Regulatory Commission (“FERC”) and state regulators authority over the books and records of holding companies and authority to regulate their ability to engage in affiliate transactions.”

            “Affiliate transactions” – like having an affiliate gas company sell an affiliate electricity company its natural gas, then the electricity company billing ratepayers at the gas company’s marked-up price. But unlike the SEC, FERC never got the authority to “regulate [holding companies’] ability to engage in affiliate transactions” – and even if it had, it does not have the resources to prosecute multi-$billion energy conglomerates like Sempra Energy and Edison International. So he was mistaken, and PUHCA was repealed anyway.

            That’s why carbon-free sources of energy like San Onofre and Diablo Canyon are being closed – because due to the repeal of PUHCA, energy holding companies can now make more money for their shareholders at the expense of the California public and the environment. When boiled down to essentials, it’s really not that complicated.

          • Bob
            SCE closed SONGS because of resistance from intervenors and stakeholders at the CPUC. SCE initially proposed to repair and restart when it appeared only one unit was affected, but agreed to the closure when both units were affected. SCE suffered some financial losses, but those were famously mitigated by “a couple bottles of wine” in an influence peddling scandal with former Commissioner Pevey. Again, that had nothing to do with the repeal of PUHCA, but rather with state regulatory policy.

            SCE (and PG&E and SDG&E) make almost nothing on burning natural gas because (1) all fuel costs are pass through with no investor return) and (2) almost all gas is used at merchant gas plants on which the utilities again have no investor return. So there is no incentive for the IOUs to burn more gas. In fact, they make much more on nuclear fuel that is treated as a capital expense and have an associated return of 10%+ to shareholders.

            The SWRCB had already issued orders phasing out OTC for all coastal plants. You have no evidence for an alternative conclusion. In fact, PG&E’s proposal to install a different cooling system at Diablo directly contradicts your conclusion.

            You assert that I can’t discern the motives of PG&E for closing Diablo, yet you try to claim that you alone know their motives. I’m basing my opinion on a close, repeated reading of PG&E’s testimony. In fact, you’re speculating about motives in meetings held “behind closed doors” by your own admittance. I’m open to you submitting specific passages from PG&E’s testimony that demonstrate that PG&E’s sole motive was to replace the plant with non-GHG emitting power.

            As for the energy crisis, I conducted modeling in May 2000 just before crisis for the CPUC as part of PG&E’s hydrodivestiture application review that revealed that generators who held at least 1500 MW in their portfolios could profitably manipulate the market price. I also designed the withholding analysis based on Ed Kahn’s seminal research that was used in the California Parties testimony in the FERC case. Again, that showed that the generators had everthing they needed to exert market power. One surprising finding was how little Enron’s actions actually affected market prices. Enron was really just exploiting the crisis, not causing it. You will need to conduct a much deeper analysis and present your case to convince the many professionals who worked extensively on the case. (In February 2002, Issac Hunt could not have possibly seen the evidence that we had on cause of the crisis. He was speaking based on a very superficial understanding of the situation. Paul Krugman made the same mistake in several NY Times columns.)

            I’m not arguing one way or the other about the propriety of closing SONGS or Diablo, which you want to focus on. Those issues are already decided. I am rebutting your claim that those choices were driven by the repeal of PUHCA. None of your claims hold water. Nuclear plants are closing due to fundamental economics and risk assessments. I was on the team that proposed closing Rancho Seco in 1988 (it was closed in 1989) and I’m well steeped in the ongoing challenges that nuclear plants have. They are failing on their own accord.

          • mcubedecon, because the SONGS Unit 3 steam generator was the same design as Unit 2, SCE wisely assumed it would eventually leak so both should be replaced. Unit 3 was never “affected”.

            State regulatory policy was expected to assume oversight of utility holding companies after 2005. It didn’t, and that has everything to do with the repeal of PUHCA. Fuel costs are indeed passed through to customers – but when Southern California Gas is collecting a profit on every cubic foot of natural gas burned by San Diego Gas & Electric, and both subsidiaries are owned by holding company Sempra Energy, and ratepayers are billed at SDG&E’s cost, there is a huge incentive to burn more of it.

            No, the SWRCB had not “already issued orders phasing out OTC for all coastal plants”. Here is your alternative evidence, courtesy of the California Energy Commission:

            “The OTC policy determined that closed-cycle evaporative cooling was the best available technology and established this as a benchmark for two compliance tracks.

            Track 1: Reduce the intake flow rate at each power-generating unit to a level that can be attained with a closed-cycle evaporative cooling system. A minimum of 93 percent reduction is required compared to the design intake flow rate.

            Track 2: If compliance with Track 1 is not feasible, reduce the impingement mortality and entrainment for the facility as a whole to 90 percent of Track 1 reductions, using operational or structural controls, or both.

            Alternatively, a plant can comply by shutting down.”

            Both SONGS and Diablo Canyon were on schedule for compliance with Track 2 by 2020. But if you believe it was a coincidence OTC systems in place for decades were challenged 3 years after the repeal of PUHCA, you probably believe MRW Associates, the consulting firm of CEC chairman Robert Weisenmiller, wasn’t getting rich from “consulting fees” paid by California natural gas interests – and didn’t steer policy accordingly.

            You have no monopoly on “close, repeated” readings of CPUC testimony (I would wager I have read at least as closely and repeatedly as you) – and by my reading, everything Enron had to manipulate the market was handed to them by the repeal of PUHCA. So you will need to conduct a much deeper analysis and present your case to convince anyone who doesn’t accept your analysis at face value. Somehow, deregulation ended up in egregious exploitation of the public by a monopoly, one capable of turning gas plants on and off at its whim. Who, but those familiar with the exploits of Samuel Insull in the 1920s, would have thought it was possible?

            The idea existing nuclear plants don’t operate economically is a flat-out lie. Based on comparative fuel prices from 2015, nuclear fuel, per megawatthour, is four times cheaper than both coal and natural gas/renewables. It takes very little uranium to make a lot of energy, and there is a lot of uranium in the ground.

            Due to higher security, regulatory, and the legal costs of fighting anti-nuclear fear factories (Greenpeace, Friends of the Earth, NRDC, etc.) nuclear plants have higher operating expenses: twice those of coal and five times higher than natural gas/renewables. So how how do marginal costs of generation compare overall? Existing nuclear is the cheapest dispatchable energy there is – with fuel, maintenance, and operation expenses included, nuclear costs 23% less than natural gas/renewables and 31% less than coal.


          • Bob, everything you cite was well in motion before the repeal of PUHCA. SDG&E and SCG merged in 1988. However, with decoupling, neither SDG&E nor SCG profits more or less from variations in gas sales–those volumes are all pass through costs. I don’t know how SCE could profit from higher gas sales because it’s owned by a different holding company.

            On OTC, you may fantasize that there are alternative compliance measures, but all of the investor-owned generators are choosing to either retire or repower. SONGS and Diablo are no different. PG&E estimated the cost of meeting the OTC standard you listed, and the cost went to over 10 c/kWh, and even higher at the lower capacity factor. I read PG&E’s stated motivations at face value in their application–reduced load and higher plant costs. Replacing with GHG-free power is the proposed solution, not the motivation that you seem confused about. The OTC issue was going at the SWRCB 10 years earlier with the diverstiture waves 1997-1999. I worked as a consultant to the CPUC on those applications.

            As for nuclear fuel costs, you’re wrong on your calculations, but I’m not going to go off into a new line of discussion with you, so I won’t give you any further fuel. As for presenting a “deeper analysis” I’m not doing this on this blog. I sent you a link to my paper on the energy crisis, and you can read that and critique it on my blog. The bottom line is that you’re looking for motivations from PUHCA repeal that are false correlations, both in timing and relationships.

          • mcube, both SCG&E and SCG were exempt from PUHCA in 1988 – neither did business outside of California. When the company they became, Sempra Energy, bought gas storage facilities in Alabama and Louisiana they were no longer exempt. After being accused of price gouging and manipulating gas supplies during the California Electricity Crisis Sempra was ordered to comply, but (like Enron) applied for, and was granted, an exemption under the pretext PUHCA was no longer “relevant” – that price fixing and monopoly abuses had somehow gone extinct.

            Not sure what it is you don’t understand about this situation – SCG could, in theory, charge SDG&E any price for gas they like, and SDG&E passes its cost through to customers. SCE has its own holding company – Edison International – and its own gas supplier, “Edison Energy”, whose price for natural gas Southern California Edison passes through to its customers. These are the same “affiliate transactions” which energy holding companies used to exploit the public 90 years ago.

            I too read PG&E’s “stated motivations” in their application, and “replacing [Diablo Canyon] with GHG-free power” is nonsense. Until Californians are willing to spend $30 billion on solar farms and hundreds of $billions more on storage it’s impossible, and was never meant to be possible. Like San Onofre, it will be replaced by natural gas, and will add another 9 million tonnes to California’s emissions.

            Re: fuel costs, I provided a link. If you had bothered to read it, you would know they are not “my calculations” but those of the U.S. Energy Information Administration – so if you don’t like them, take it up with them. I’ll also note like other renewables advocates, you provide no links to reputable third parties but to your own blog. Notwithstanding your invitation to review it, because renewables blogs typically only reference more fact-free advocacy I usually don’t bother.

          • Bob
            SCG does not make money on the actual gas commodity sale to SDG&E. The gas cost is a straight passthrough with no shareholder return. Edison Energy is selling a trivial amount of gas in California as affiliate transactions are closely regulated. Their market is elsewhere. In addition, SCE made much more for shareholders from SONGS than they could ever hope to make from gas sales. In fact, the same is true for PG&E and Diablo Canyon. Your reasoning is financially nonsensical.

            Sempra was not part of the transactions during the 2000-01 energy crisis–it was required to stay out of the market during the start up. However, it did sign a large share of the PPAs issued in March 2001 to suppress the price spike, and those contracts were eventually revised in a separate action because the price was too high. There were many more actors than Sempra and Enron who created the crisis, and most were not covered by PUHCA as they were merchant generators.

            Yes, you provided a link to a partial cost of nuclear fuel, just the uranium. However, that cost ignores the cost of fuel assemblies. You can continue to be ignorant about the full cost of nuclear fuel, or you can delve into PG&E’s rate filings as I have and derive that full cost.

            As for my blog posts, you will find that they are well documented. The paper I referred to was prepared for an academic conference with a full set of references. You can continue to make unsubstantiated assumptions about people, or you can become well informed.

  2. From Barbara A.: “Your response would require all customers to see unpredictable price signals and face the potential of unaffordable bills (speaking about residentials primarily).”

    There is no requirement that customers “see” the prices (we have communicating thermostats and other devices to do that for them), and the prices are not “unpredictable.” Generally prices are provided 24 hours in advance – more than enough time for a thermostat to acknowledge and prepare for the change in HVAC service including precooling and peak setback. The studies I’ve seen show that the humans are also fine with this level of advance notification.

    As for the “unaffordable bills” I’d like to see some evidence to back up this claim, as all the evidence I’ve seen indicates that the vast majority (70-80%) of residential customers save money or have negligible bill changes on dynamic rates and prefer them to tiered rates. I would be happy to provide sources should you want to see them. I suppose you could say the bills are “potentially” unaffordable – with about the same likelihood that I will “potentially” make it to Wimbledon next year.

  3. New “demand response” should not be so narrow-minded as to only pay customers to reduce their “consumption relative to an administratively set baseline level of consumption,” which is only for very specific stressed periods by remotely turning it off. The overall “demand response” system needs to be revamped to reduce losses in the system 24/7 against the data already in their billed baseline level of consumption. It is possible to come up with rules that pay customers for what they don’t consume because there is
    a way to measure it, albeit some are better than others. If customers are rewarded for installing a device to remotely turn it off, surely they should be rewarded to install power electronics that measures to first gain knowledge of the system that it is connected to and then dynamically eliminates the losses behind the meter by tuning the system for ideal energy transfer. This applies to data centers, stores with refrigeration and air conditioning, motors, pumps, air compressors, etc. The knowledge gained by now being able to see and accurately account for losses (rule to pay customers) will help redetermine a new baseline level of energy efficient consumption and reduced losses upstream because of an overall system health revitalization that the customer is now responsible for by leaving it on to reduce losses. It is an immediate “demand reply” to the ever changing loads.

  4. One of the key difficulties with dynamic or critical-peak pricing programs is recruitment. The majority of customers tend to be risk-averse when it comes to their utility rates.
    Alectra Utilities (formerly PowerStream) has had great success with its “Advantage Power Pricing” pilot program, which pairs a dynamic price signal with enabling technologies that automatically respond to price signals.
    The evaluation of summer 2015 may be found here:
    I expect that the evaluation for the winter of 15/16 and the summer of 2016 will be published soon.

  5. This entire argument is based on the fact that electricity has historically been a unique good that must be supplied to the exact quantity of demand. The basic argument for demand response is that it takes expensive supply (and transmission and distribution) out of the market. It seems that storage technology (both behind and in front of the meter) will shortly turn energy markets into a more typical market that allows lags between demand and supply. In other words, it seems that the kind of demand response in this article is likely to diminish over time. In that case, does it make sense to spend a lot of time fixing a problem that is likely to go away in the 3-5 year timeframes of significant regulatory change?

    • Richard, not economics but physics dictate that electricity must be supplied to the exact quantity of demand. Demand response does take supply out of the market – at the cost of consumers. Electricity isn’t there when they need it.

      Is that a good thing? I don’t think so, and I don’t think that building hundreds of $billions worth of lithium-ion battery banks to store electricity generated by intermittent renewable sources (or dirty grid sources, for that matter) is “likely” to happen. I guess I’ve been listening to renewables advocates speak of these likelihoods for decades, and been consistently disappointed.

      • Bob, as recently as 2009, the economics of solar power did not look promising. I was working the the CEC’s Cost of Generation Report then and very few were forecasting that solar would be competitive with low-priced gas by 2020, much less in 2017. Saying that a technology that is experiencing rapid cost declines won’t be competitive until long in the future is a dangerous prediction.

        Another important point is that customer-side generation and storage can avoid rising distribution and transmission costs. Note that the apparent marginal cost of transmission is likely twice the current “postage stamp” rate.

    • Richard, that electricity must be supplied to the exact quantity of demand is a fact of physics, not history. The basic argument for demand response is an economic one of shifting cost from utilities to customers – from the cost of maintaining peak generation capability to customers’ cost of convenience.

      There is no evidence storage will “shortly” turn energy markets into a situation which allows a significant lag between demand and supply, for many, many reasons. On California’s CAISO grid, it’s not uncommon for consumption to top 40 billion watts on summer days. At the current cost of $500/megawatthour, it would cost >$300 billion to construct storage which could get the state through a cloudy, windless day – or the lights go out. About twice the cost of California’s total annual budget, it would need to be replaced every decade. Moreover, it would require ongoing maintenance of fossil fuel plants to keep the state from turning into a post-Maria Puerto Rico.

      Activists envision storing only renewable energy on sunny days, then using it on cloudy days. But due to the phenomenon of binding grid constraints, electricity can’t be transferred instantly around the state to wherever it’s needed – it must follow routes which are durable enough to transmit it, or CAISO risks melting wires from their poles. Conventional clean generation (nuclear) has resulted in the construction of these energy throughways from supply to demand. Serendipity alone is responsible, if the same transmission routes prove capable of transmitting energy from location-dependent renewable sources.

      In practice, grid storage in California is storing almost exclusively natural gas generation, and it’s not helping to reduce climate emissions. Li-ion grid batteries typically waste 5-10% of stored energy in resistance losses, raising emissions by a corresponding percentage.

  6. “Managing their energy use to game the DR program is only a secondary or even tertiary consideration in day to day operations. Their loads are are fairly constant day to day (most electric motors run at a single speed) so overconsuming requires a set of explicit decisions on top of the already difficult management tasks.”

    In California, most of the large customers of this type were (and may still be) enrolled in a DR program that required them to reduce load to a defined level when asked or face stiff penalties for failing to comply. This is entirely appropriate because customer compliance can be measured directly simply by reading the meter.

    In PJM, there was quite a bit of gaming by large customers, including colleges that attempted to claim load reductions when school was out of session and others that did, in fact, attempt to inflate their loads. A few bad actors forced PJM to change its rules, which made DR a lot less attractive for customers and aggregators.

  7. I would like to see what a 3-in-10 baseline would have produced for the day in question. The three highest consumption days in the last 10 similar days may better reflect the counterfactual for the event day.

  8. Here’s three practical counterpoints:
    – As mentioned previously, CAISO system dispatchers want to be able to “push the big red button” to get concrete responses. The CAISO operators liked seeing the 500 MW dip, even if the CAISO accountants dismissed the reduction. The CAISO’s bias against behavioral responses has long been evident and is receding only slowly. Underlying this all of this is a belief that increasing electricity demand is inexorable.
    – Most of the entities in the demand response program are large commercial and agricultural operations. Managing their energy use to game the DR program is only a secondary or even tertiary consideration in day to day operations. Their loads are are fairly constant day to day (most electric motors run at a single speed) so overconsuming requires a set of explicit decisions on top of the already difficult management tasks.
    – While apply “marginal costs” to retail rates may sound like an attractive solution, the truth is that determining what ARE marginal costs, much less what those marginal costs should be, is a far from settled issue at the CPUC. There are at least 4 different proposed approaches to setting MCs at the CPUC now. Whether 5-minute or hourly energy prices are truly representative of generation MCs in an age when almost all of the new power comes for zero-fuel solar and wind is another question. On top of that, the utilities’ average costs can be twice or more of the generation marginal costs, so what’s to be done to collect that difference?

  9. Let’s go back to Sally Holtermann’s 1976 piece in Economica. A Pigouvian subsidy is a a lump sum subsidy minus the Pigouvian tax. The baseline for the subsidy is flexible. It can be the efficient quantity of pollution, the profit-maximizing quantity of pollution, or anything in between, so long as it is independent of the polluters actual behavior. So the key to setting a baseline for voluntary load reduction programs is to set the baseline according to characteristics of the customer, not including historical use. And it is not necessary to make it voluntary, any more than peak-load pricing would be voluntary. This would remove the little bit of adverse selection associated with missing the mark on characteristics.

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