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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 the Cora Jane Flood Professor of Business Administration at the Haas School of Business, Co-Director of the Energy Institute at Haas, and a Faculty Director of The E2e Project. Her research analyzes the impact of environmental regulation on energy markets and the effects of electricity industry privatization and restructuring around the world. She is currently implementing several randomized control trials to evaluate energy efficiency programs.

37 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.

      • 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.

  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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