The Texas Power Crisis, New Home Construction, and Electric Heating
No U.S. state has built as many new homes as Texas over the last decade and most of them use electric heat.
There is plenty of blame to go around for the deadly power outages in Texas last week. Much of the attention, correctly, has been focused on the supply side — from power plant outages, to freezing natural gas pipelines, to reduced wind and nuclear generation.
But in today’s blog I want to focus on electricity demand. How is it possible that Texas demand was able to reach 69 gigawatts in the winter?
To understand this you have to go back a few years. Coming out of the great recession, Texas embarked on an incredible binge of new housing construction. No U.S. state has built as many new homes as Texas over the last decade, and most of these homes use electric heat.
Go Big or Go Home
Texas leads the nation in new home construction. Between 2010 and 2019, 1.5 million new housing units were constructed in the state. Over this time period the population of Texas grew 15%, adding almost 4 million people.
To put this in perspective, this is almost twice as many new homes and twice the population growth as California, a state with over 10 million more people. Among the top-20 metropolitan areas with the most new homes in 2019, California only has a single city (Los Angeles), compared to Texas with four (Houston, Dallas, Austin, and San Antonio).
This pattern is not a coincidence. Texas approaches its housing market much like it approaches its electricity market with a heavy emphasis on the free market and minimal government regulations. An often-used index of residential land use regulations ranks Texas cities among the easiest places in the country to build new housing, while ranking California cities among the hardest.
Feeling The Electric Heat
Now combine this housing growth with a long-running historical trend toward electric heating. In 1950, less than 1% of Texas homes used electricity as their primary heating fuel. Electric heating in Texas has increased steadily since that time, reaching 8% in 1970, 40% in 1990, and 61% in 2018. Since 2010, 62% of homes built in Texas use electric heating.
Why so much electric heating? The single most important factor is low electricity prices. The average residential price for electricity in Texas is less than 12 cents per kilowatt hour, below the national average and way below states like California (19 cents), Massachusetts (22 cents), and Hawaii (32 cents).
Texas’ climate is also conducive to electric heat. During a normal year, Texas households experience fewer than 2000 heating degree days compared to, for example, over 9000 in Minnesota, so electric heating with its lower capital and installation costs is a more economical option.
Add in Historic Low Temperatures
Now take the 7 million homes in Texas with electric heating, add in record-low temperatures — in some cases reaching 100-year lows — and you get record breaking winter demand levels for electricity. Texas last week was colder than Alaska, with temperatures in Dallas hovering in the single digits.
Homes in Texas tend to be less well-insulated than homes in colder parts of the country. Yes, it gets hot in Texas, but the typical indoor/outdoor temperature differential on hot days tends to be much smaller than the typical temperature differential on cold days, so homes in colder parts of the country are insulated to a higher standard.
Consequently, a single home can easily use 5000 watts for heating. Many Texas homes use much more, but 5000 watts would be the equivalent of half of a 10KW electric furnace, or two 2500 watt baseboard heaters, or a little more than three 1500 watt portable heaters. Many homes in Texas are also being built with heat pumps. In general heat pumps are more energy-efficient than electric resistance heating — but these efficiency benefits shrink considerably during very cold weather.
7 million homes multiplied by 5000 watts yields 35 gigawatts! Normally, these units would be cycling on and off, but with polar vortex conditions most of this equipment would have been running full out. Add this to electric water heating and the rest of residential load, plus commercial and industrial, and you get to 69 gigawatts.
An Opportunity for Dynamic Pricing
Meeting this growth in electric heating is a serious challenge and it is pretty clear that the Texas market last week was not up to the task. As I said before, it seems correct that most of the attention has been focused on failed opportunities to weatherize power plants and other supply-side problems.
But there was also a missed opportunity on the demand side. Texas has retail choice for electricity, but the overwhelming majority of Texas customers face electricity prices that are too static, too inflexible, and don’t respond to market conditions. Economists have been advocating dynamic prices for decades, but adoption has been slow.
Case in point. While wholesale prices in the Texas market climbed last week to $9,000/MWh, the overwhelming majority of electricity customers in Texas continued to pay retail prices close to $120/MWh, barely 1/100th of the true marginal cost.
Not seeing these high prices, Texas consumers had little incentive to conserve. You had a feast or famine — with millions of consumers at an all-you-can-eat buffet — while millions of others faced tragic blackouts and, essentially, an infinite price.
If everyone instead had turned their thermostats to a chilly, but manageable, 65°, this could have really helped the state manage the emergency. As Severin Borenstein pointed out after the California power outages last August, even modest adjustments to the thermostat can save a lot of electricity.
Dynamic pricing allows customers to pay lower prices throughout 99% of the year, in exchange for facing much higher prices when supply is tight. Numerous studies have documented that dynamic pricing yields substantial demand reductions (here, here, here, and here).
You may have read about households who paid enormous electricity bills last week. 29,000 out of Texas’ 11+ million customers buy their electricity from Griddy, a retailer that charges customers wholesale prices for a monthly fee of $9.99/month. This is a very extreme version of dynamic pricing. The evidence shows that you don’t need such extreme price changes to encourage conservation. Moreover, it is straightforward to incorporate hedging into retail contracts to protect customers from these outcomes.
With 28GW of forced outages in Texas last week, it is unlikely that dynamic prices alone could have closed the gap between demand and supply. But dynamic pricing is the fastest and cheapest way to build flexibility into the market, and can play an important role moving forward.
Keep up with Energy Institute blogs, research, and events on Twitter @energyathaas.
Suggested citation: Davis, Lucas. “The Texas Power Crisis, New Home Construction, and Electric Heating” Energy Institute Blog, UC Berkeley, February 22, 2021, https://energyathaas.wordpress.com/2021/02/22/the-texas-power-crisis-new-home-construction-and-electric-heating/
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Lucas Davis View All
Lucas Davis is the Jeffrey A. Jacobs Distinguished Professor in Business and Technology at the Haas School of Business at the University of California, Berkeley. He is a Faculty Affiliate at the Energy Institute at Haas, a coeditor at the American Economic Journal: Economic Policy, and a Research Associate at the National Bureau of Economic Research. He received a BA from Amherst College and a PhD in Economics from the University of Wisconsin. His research focuses on energy and environmental markets, and in particular, on electricity and natural gas regulation, pricing in competitive and non-competitive markets, and the economic and business impacts of environmental policy.
Energy Institute Blog 
We moved to Panama 4 years ago. In Panama, we regularly have long electric outages, long water outages, and shortages of gas (propane bottles, in this case). No one, and I mean no one, in Panama relies on one source for anything. We have, for instance, municipal water and 1,500 gallons on-site storage, in addition to multiple levels of filtering for our water. On the electric side, we have utility power, a whole house surge protector, protectors on every single appliance and computer for the regular multi-hour brownouts, multiple battery backups for Wi-Fi and other items, and an endless number of battery powered emergency lights and backups. Several neighbors have diesel powered generators, and a few have solar in addition to ALL of the above. The local hardware store has an entire section devoted to power backup and regulation. When you live in an area with dicey reliability, people backup their backups, and relying on one fuel for a life supporting service (heat in a cold snap) is really crazy. I’m guessing that Texans will in the future have more diesel generators, more solar, AND more batteries. Thinking one thing, whatever it is, will be your silver bullet doesn’t work when supply isn’t something that can be counted on.
One modest positive note about dynamic pricing in Texas. According to the NYT article this morning, the customer they interviewed was receiving frequent price updates via cellphone. Obstacles to dynamic pricing 20 years ago were 1) metering and 2) communicating prices. Both of these are now gone, even for residential customers.
The third through 5th obstacles remain for residences although not so much for larger customers.
3) “Computational burden” figuring out what to do. (That’s probably not an issue when price hits $9 per kWh.)
4) Switching devices on and off.
5) Complexity. Keeping track of different rates, deciding who to sign up with, monitoring debugging the price-sensitive programming on your smart appliances, etc.
As usual I think we over-emphasize home customers, because most of these problems are smaller for commercial loads that already have energy management systems, not to mention industrials. But the relevance of home users is certainly increasing over time as the costs of computation and communication fall.
I’d think smart house technology is either or already there or is soon to be there to instantaneously do 3 through 5 for you without any human input.
Sometimes you have a long tail event that you can’t possibly plan for. This was one of those long tail events. No amount of planning or policy changes could have anticipated this event or prevented the consequences. There was plenty of capacity margin available at the start of the storm, something like 30 percent above what was required. Based on historical data, ERCOT likely viewed that as enough. But the depth, severity and duration was not within the historical limits. Plus, you had freak incidents like Unit 1 of STNP going off line. At 5:30 a.m., on the first day of the freeze, the extreme cold caused a sensor to trip and 1350 megawatts of baseload power were taken offline.
My hope is that policy makers in the Texas Legislature, Counties and Municipalities will realize that more time and money should go into Civil Response. Long tail events will continue to occur. There are a lot of things that municipalities can coordinate when the grid and the water system go down. Examples: The public pools remained locked while neighbors went begging their neighbors for pool water to flush their toilets. The public pools could have been opened and the water distributed. There were lots of localities that had warming centers, but nobody was aware of them. They can communicate warming centers better. They could coordinate boil centers for people who couldn’t boil water. All the resources were out there, for people to find heat, flushing water, and potable water but there was really poor communication on where to find them. Individuals were left to rely on texts to coordinate with their neighbors.
“If everyone instead had turned their thermostats to a chilly, but manageable, 65°, this could have really helped the state manage the emergency. As Severin Borenstein pointed out after the California power outages last August, even modest adjustments to the thermostat can save a lot of electricity.”
Based on 28 GW of outage or 40% of the 69 GW of load, dynamic pricing wouldn’t made much of dent in this catastrophe. In the August event, California needed only a few thousand MW to avoid the outages, so turning back thermostats a few degrees could make a difference, and in fact such actions reduced load substantially over the next few days after August 14–and that was just with public calls for action, not prices. In Texas, the source of the problem was in the failure to hold generators and fuel suppliers to appropriate standards. Maybe dynamic pricing enters the equation after they get back 20 to 25 GW of generation, but that’s a huge gap to make up before even starting the conversation about whether dynamic pricing sufficient.
As an additional point, studies repeatedly show the old “20/80” rule holds here–only about 20% of customers respond significantly to price signals. So a calculation of potential savings needs to account for a response rate substantially less than 100%.
Is there an analysis of where the power savings came from during the few days where CA was short on power? They were substantial, and it was never clear to me if they came from (built-in) demand response (commercial? residential?), voluntary industrial cutbacks, voluntary residential cutbacks (where?), etc. I’d love to learn more about how we got the savings that we did, and what it cost.
nd.
The problem with GRIDDY is that customers must expose their entire load to the wholesale spot market volatility. That’s risky and imprudent, as we now see with customers receiving bills in excess of $10,000 for just 5 days of usage.
One alternative that I proposed was for the REPs to augment their current fixed-price contracts by allowing a customer to sell back to the REP the energy he/she chooses to not consume and receive a high percentage of the wholesale spot prices (less the fixed contract price). The REP can then sell that energy back into the wholesale spot market and share the revenue with the customer. This would require determining how much energy the customer chose to not consume, which can be resolved using measurement and verification techniques, such as temperature-adjusted historical baselines, that are currently used in other ISO markets to compensate economic demand response under FERC Order 745.
When I suggested that the Public Utility Commission of Texas facilitate the development of retail demand response the response of the Chairwoman was, “Texans don’t want anyone messing with their air conditioners.”
The chickens have come home to roost – again.
The discussion about dynamic pricing makes sense in normal circumstances, but makes no sense in a case where the utility failed to be prepared for unusual, but foreseeable events–as is the case in Texas. That kind of dynamic pricing shifts the burden of poor utility planning to the consumer, who had no say in it. A couple of thousand dollar extra utilty bill is, in fact, just adding insult to injury for all the health and property damage caused by a failed electric system plan. Without a reliable, resliient grid, all the reasonable pricing systems in the world are insuffiicent or unfair.
There is another lesson to be learned here: great caution must be used in proceeding to electrification too quickly. It is not as likely that California’s electric grid would suffer as much in an extreme winter cold snap, but even if it did, it currently would have less impact because so many California homes are served by natural gas. Many of those homes could have space heating, cooking, water heating even if the grid was down–especially those with a modicum of solar and/or storage. Diversity, as is often the case, is a good thing, but has a cost. I expect a lot of Texas are going to be buying bigger propane tanks and back-up systems, which is probably wise, but not the best use of resources from a societal perspective.
Job 1 has to be to have an electric infrastructure that is both robust and reslient. They certainly don’t have that in Texas, but the recent California blackouts prove that we don’t here as well. Putting more strain on the grid (e.g. through eletrification) must be minimized until the infrastructure is place to reliably support it.
“The discussion about dynamic pricing makes sense in normal circumstances, but makes no sense in a case where the utility failed to be prepared for unusual, but foreseeable events….”
Agreed. What happened was a Force Majeure event so the normal market pricing regime should be suspended until operations return to normalcy. That means the customers don’t pay the high spot prices and the generators don’t receive those prices. But that shouldn’t allow the owners of generation and natural gas assets to escape any penalties for their refusal to weatherize their facilities after being warned to do so following the blackouts that occurred in 2011.
Complaining that “While wholesale prices in the Texas market climbed last week to $9,000/MWh, the overwhelming majority of electricity customers in Texas continued to pay retail prices close to $120/MWh, barely 1/100th of the true marginal cost” while customers were freezing to death and/or seeing $10,000 electric bills seems a little tone deaf.
Agreed. Those customers paying 12c/kWh paid to have a guarantee of delivery of power. I don’t know what the allowed rate of return is in Texas, but in other states the return on equity is 9-10% which is quite a premium on average corporate debt rate of 3-5%. That premium is intended for utilities to deliver power when demanded, and for shareholders, not ratepayers, to absorb the $9,000/MWH costs if the utilities fail to ensure power delivery under most extreme conditions. The catastrophe in Texas appears to be much more related to a failure to implement standard maintenance practices than in general planning for extremes and not having sufficient capacity. That argues for the consequences to land on shareholders, not ratepayers.
“Those customers paying 12c/kWh paid to have a guarantee of delivery of power.”
Richard, while I fully agree with you point of view, the fact is that no utility (at least that I know of) has a legal obligation to prove its customers with guaranteed, firm power. If that condition were imposed on them they would need to charge customers substantially higher risk premiums. But this concept is worth further consideration.
Robert
That’s an interesting question about what constitutes “obligation to serve”? It also depends on what is being represented to customers about reliability. The political reality in Texas is likely different than in California, but here the reason for so much outcry over the PSPS is because of the perception of that guarantee. Trying to assume that customers will be completely informed is not a realistic premise.
As to whether utilities need a yet higher premium, the empirical work that I’ve done shows that California utilities are already earning a 3% premium above what companies with comparable risk profiles earn.
https://mcubedecon.com/2019/11/13/utilities-returns-are-too-high-part-2/
You are right about most customers being ignorant regarding the legal obligation of the utility. Typically the utility’s tariff sheets contain language stating that it is not obligated to provide uninterrupted service (and in all practicality it cannot since outages are inevitable).
But who reads the fine print? I have to confess, I have never read the tariff sheets of my own utility, PEPCO. And if I did, what good would it do? I am not going to disconnect from the grid.
Robert
Right, these corporate disclaimers are really useless. There’s no opportunity to negotiate an alternative arrangement and various externalities prevent entry by firms that might offer a different product, whether its electricity or social media platforms.
That’s a good point. The total societal cost imposed by involuntarily interrupting 15 to 20 GW of demand almost certainly overshadows the high electric bills received by the small percentage of retail customers exposed to ERCOT spot market prices.
Do you know how Texans heated in 1950 when electric heat was just 1%. Did they use heating oil and propane back then?
No fuel used 1%
Utility gas from underground pipes 75%
Bottled, tank, or LP gas 16%
Electricity 0.5%
Fuel oil, kerosene, other liquid fuels 1.50%
Coal or coke 0.1%
Wood 5%
Other 0.3%
Variable pricing makes much more sense at the wholesale level than for customers, who shouldn’t be asked to waste mental effort figuring out exactly where they want their thermostat set, depending on price. I certainly don’t want to spend my time doing that! Much better to pay customers a hefty lump sum for the right to turn down their thermostats to as low as, what, 58F in winter, or as high as 85F in summer for a fixed number of days, to avoid rolling black-outs. No?
Retail customer price-responsive demand does not require “…mental effort figuring out exactly where they want their thermostat set….” Customers only need to program their enabling device once and it will selectively reduce the customer’s various appliance loads at the price points the customer initially chooses. These devices are available today at modest cost but they are useless if the customer is not served under a tariff that dynamically reflects the wholesale spot market prices.
This is the classic chicken-egg problem. The first step is for state legislatures to require all utility and competitive retail suppliers to offer their retail customers the option of choosing dynamic rate tariffs.
“Customers only need to program their enabling device once and it will selectively reduce the customer’s various appliance loads at the price points the customer initially chooses. ”
This only works for homeowners, who are only 55% of residents in California. (It is 70% in Texas.) And it is only makes sense for customers who have enough income and see the potential for cost savings. Even in Texas, the price spikes have been a relatively rare event until this last year. I don’t see such an investment paying off here for me. Equity is a big consideration here.
Sorry but I don’t really buy the equity argument. There’s an argument to be made that it makes sense for both the utility and for the end consumer, regardless of ownership status or income level. Utilities get to offload risks onto consumers and consumers get to reduce their bills, regardless of income level. Key is dynamic pricing+smart house technology to avoid the communication of price issue, which really isn’t all that expensive.
Smart house technology is not expensive to whom? Almost two-thirds of Americans are living paycheck to paycheck. (https://www.cnbc.com/2020/12/11/majority-of-americans-are-living-paycheck-to-paycheck-since-covid-hit.html)
And the agency problem in the tenant-landlord relationship is real. It’s about LEGAL issues, not just economics. A tenant cannot just install a smart thermostat, and likely doesn’t see the economic benefit of doing so with a likely short tenure. This is why there are barriers to installing energy efficiency measures in general.
“Smart house technology is not expensive to whom? Almost two-thirds of Americans are living paycheck to paycheck.
And the agency problem in the tenant-landlord relationship is real. It’s about LEGAL issues, not just economics. A tenant cannot just install a smart thermostat, and likely doesn’t see the economic benefit of doing so with a likely short tenure. This is why there are barriers to installing energy efficiency measures in general.”
Good points.
This is why it may be good social policy to require distribution utilities to install the enabling devices and rate base the investment.
Back in 2012 I proposed this to the Texas PUC but got push-back from the commissioners, who argued that the utilities would install equipment that would quickly become obsolete due to the rate of technology change, leaving ratepayers to foot the bill. The problem with that argument is that it is an excuse to indefinitely defer doing anything.
When I was a grad student my neighbor sold hand calculators. I pointed out that calculator costs were coming down so I want to wait before buying one. He laughed and said, “Then you will never buy one.” His practical, down-to-earth words often come to mind.
“Back in 2012 I proposed this to the Texas PUC but got push-back from the commissioners, who argued that the utilities would install equipment that would quickly become obsolete due to the rate of technology change, leaving ratepayers to foot the bill. The problem with that argument is that it is an excuse to indefinitely defer doing anything. ”
The problem is that utilities are particularly bad at this because they don’t have the right risk sharing incentives to make good choices. For other businesses, if they choose the wrong technology, the shareholders eat at least a portion of the costs. In California, the utilities appear to have made the wrong smart meter investments, but they’ll just plow along collecting with not even a hand slap. The utilities here are going through billing system revisions, yet again, that have frozen them from implementing new rate options. We’d be foolish to hand over universal smart control installation to utilities with the current risk/reward incentives.
As to argument that they should then receive a boost in ROE, the fact is that CA IOUs are only slightly more risky than the munis that are paying out 2-5% on debt with no complaints. Comparing IOU ROEs to the S&P 500, they are already earning a 3%+ premiums that are not justified. It’s just that regulators need to get a spine.
Lucas –
At the end, you mention the benefit of hedging costs to avoid crazy prices. Aren’t you complaining about hedging through the rest of the article?
“An Opportunity for Dynamic Pricing” …
I’m gonna be a bit hard on you because this is a very serious situation for many. Aren’t you just arm-chair quarterbacking? You are substituting your own judgement of *appropriate levels of hedging* for the levels of hedging that exist in current fixed price contracts in Texas? Shouldn’t the folks that paid for those hedges benefit from them? They paid extra to have a known price – and retail is competitive in Texas so its not like they didn’t have an alternative. If I pay for a buffet, shouldn’t I get a buffet???
I greatly appreciate the part about the proliferation of electric heat in Texas. The rest needs a bit more peer review…
Thanks for this comment. I should have been clearer what I mean by hedging. I have in mind a customer buying a fixed-quantity, fixed-price contract to cover some of their demand, but then paying/receiving a dynamically-determined price for deviations from the contracted quantity. Severin Borenstein’s “Customer Risk from Real-Time Retail Electricity Pricing: Bill Volatility and Hedgability” Energy Journal, 2007 shows how this type of contract can eliminate 80% of the bill volatility, while still providing a strong price signal on the margin.
The type of hedging proposed that would be consistent with Borenstein’s article sounds good, but there is an important difference between retail electricity customers (at least in the current state) and airlines (and other fuel consuming businesses) that Borenstein uses for this paradigm. Airlines who over procure (as Southwest may have done in 2007 when the article was written) has the opportunity to sell its excess fuel in the open market. Even today, a load serving entity that overprocures fixed price power contracts is able to sell that power at either the short-run market price, or better yet, negotiate a mid or long term sale of a portion in the marketplace. In other words, those businesses have opportunities to participate in bilateral contracts as sellers as well as buyers.
Retail electricity customers, particularly small customers, do not have an opportunity to unload excess contracted amounts. Whether a utility with 5 million customers can manage that many bilateral transactions, and whether customers want to participate in such bilateral transactions is highly questionable. So These customers are left if having make a single transaction that may mean, if they are sufficiently informed, that they buy their minimum exposure, which probably is not the optimal exposure.
One solution might be to pool the amounts that customers would prefer to hedge, which could be in aggregate the optimal amount. Customers might then be able to purchase from that pool within a range of monthly usage. The issue would be determining that optimal aggregate amount, and the band would have to be set for each customer individually.
An alternative could be to provide the load serving entities (LSEs) with the right incentives to hedge their customers’ bills. That means putting investor-owned utility shareholders at risk for their procurement practices. That most certainly is NOT happening in California, which is why PG&E has a hedging premium of about 2 cents a kWh on its portfolio and its average generation cost is over 11 cents/kWh. CCAs on the other hand have such an incentive, both through a lack of a nearly guaranteed through AB 57 and competition from the IOUs.
I believe most residential and C&I load in Texas is served by LSEs, not the IOUs, for some time now. Those customers, particularly residential, are paying fixed prices significantly above the typical dynamic hourly prices. Proof is seen in the gross margins of the publicly traded ESPs like Spark Energy that earn over 20%. So the homeowner/renter is paying for price protection just like an insurance holder is paying for a low deductible. The market works. Which means that the LSE is taking the imbalance risk on their balance sheet in exchange for deep in the money contracts. And last week that bargain may have come home to roost for those LSEs, not the consumers, that did not hedge in one fashion or another (although block hedging is a bit out of date).
I take exception to Mr. McCann tying PG&E’s generation costs (and its “hedging premium”) to anything more than entering renewables contracts years ago with higher legacy costs than today. Today, CCAs mimic PG&E tariffed prices explicitly but are not burdened with those legacy, i.e. PCIA, costs, as the writer should know. Dynamic pricing is very scary to CCAs, both to implement (and account for) and to sell to its consumers. It should be embraced.
I do like Lucas math on the impact of new electric home heating and it points out why, even in California, especially in the central valley, we will continue to need a two regime fuel source of natgas (maybe hydrogen in the pipe one day) and electricity to mitigate the risks of over-reliance on power only. No wildfire was caused by a natgas line in a wind or lightning storm(to my knowledge). Many businesses still use and need natgas as essential in their manufacturing process. So any costs of displacing natgas demand by electricity should be borne by electric ratepayers, not the gas ratepayers, so we prevent a death spiral of costs for the natgas consumers with no real market option (other than relocate to a natgas friendly state). Just my economic opinion….
Ron,
Your description is quite accurate with two minor exceptions.
(1) The LSEs are referred to as Retail Electricity Suppliers (REPs). I know, this is knit-picky.
(2) The LSEs (REPs) hedge most of their retail loads through contracts with the generators. They don’t take on the risk of buying their full requirement from the wholesale spot market. I don’t know how much of their load goes unhedged because that is confidential business information, thus not publicly available. However, a friend of mine that is a consultant to one of the largest REPs tells me that they typically hedge 85 to 90 percent of their retail load.
Ron P.
PG&E’s portfolio mismanagement is not explained away with a simple assertion that they bought when prices were higher. In fact, PG&E failed in several ways. First, PG&E knew about the risk of customer exit as early as 2010 and said so in internal memos that I’ve seen. Further PG&E also was told as early as 2010 (by me in testimony) that they were consistently forecasting too high, but didn’t bother to correct their error. Second, PG&E could have procured in stages rather than in two large auction rounds which they finished by 2013. By 2011 they should have realized that solar costs were dropping quickly (if they had read the CEC Cost of Generation Report that I managed) and that they should have rolled out their PPAs in a manner to take advantage of that improvement. Further, they could have signed PPAs for the minimum period under state law of 10 years rather than the typical 30 years. PG&E was managing its portfolio in the standard practice manner which was foolish in the face of what was occurring. Third, PG&E failed to offer part of its portfolio for sale to CCAs as they departed until 2018. PG&E then could have unloaded its expensive portfolio in stages. The ease of the RPS sales illustrates that PG&E’s claims about creditworthiness and other problems had no foundation.
I calculate the what the cost of PG&E’s mismanagement has been here:
https://mcubedecon.com/2019/10/28/pge-has-cost-california-over-3-billion-by-mismanaging-its-rps-portfolio/
An additional point on phasing out natural gas. The much more cost effective and environmentally preferable solution is to have propane as the back up for the very few days a year that a supplement or replacement to electricity is required. This is especially true in Texas if they have not yet laid gas lines in the neighborhoods. The industrial customers who require gas service are largely non-core customers on the gas transportation system. Other customers shouldn’t be taking gas service just to subsidize those customers for their continued use. Likely the gas transmission lines will downsize and transmission companies may not be as financially viable. Such is capitalism…
Well, again we agree. “Propane is the right answer for back generation that seldom runs.
I am not so sure the gas pipelines will become stranded assets because it may be possible to cheaply produce synthetic methane from “green” hydrogen and and CO2 then inject it into the existing pipelines. That gas could then be used to power generating plants and even home heating.
Producing synthetic methane will require a lot of cheap electricity, which will be available if we overbuild renewables to meet the winter needs in the winter (when renewables production is less than one-half that in the summer). The methane could be produced when there is excess renewables production and some of it could be stored for use in the winter, much like what we do today.
This process is being explored but may turn out to be a pipe dream (pun intended).
Agreed. Overbuilding renewables might the solution to several issues. Using existing pipelines rather than new transmission lines to send energy might be the cheaper solution.
Richard, you are making this way too complicated.
Competitive suppliers can offer fixed-price contracts with an option for the customer to sell back to the supplier its unused demand. In effect, the supplier then sells that energy back to the wholesale market at the prevailing spot prices (see my earlier comments describing this).
In actuality, the supplier merely takes less energy from the Real-Time Market than it is cleared to receive in the Day-Ahead Market so the ISO settlement system credits the supplier for the under-consumption at the prevailing RTM spot market prices. The mechanism for handling this already exists in every ISO market.
Robert
Your solution effectively just leaves customers exposed to RTM/DA market risk in the same way as if they simply chose their minimum use level as the hedged amount. That pretty much defeats the purpose of the hedging. It would be just as easy to set a baseline usage at a fixed price and price the remainder at the RTM. That’s still too much exposure for many, if not most, customers.
The power of having aggregated customers is that electricity can be bought as a group and the costs then allocated among customers. Perhaps dividing that into two differently priced products is a preferred approach, but we don’t need to move customers to being exposed to any great extent to real time markets in that model.
“Your solution effectively just leaves customers exposed to RTM/DA market risk in the same way as if they simply chose their minimum use level as the hedged amount. That pretty much defeats the purpose of the hedging. It would be just as easy to set a baseline usage at a fixed price and price the remainder at the RTM. That’s still too much exposure for many, if not most, customers.”
Richard, I confess, I don’t follow your argument.
The “sell-back” arrangement I described hedges the customer’s total load. If the customer chooses not to curtail any load he simply buys the energy he consumes at the fixed contract price. The incentive he has for selectively reducing a portion of his load is foregoing the wholesale market-based bill credit he would otherwise receive from his supplier. So (presumably) a rational customer will weigh the potential bill credit against the value the curtailed load would provide to him if it were not curtailed. The only complication in this arrangement is establishing a baseline to compare against his actual hourly usage to determine how much energy was curtailed but that has already been addressed in the wholesale demand response markets.
One further twist might be to charge the customer at the wholesale spot prices for any energy consumed that exceeds the baseline but that would expose him to some price risk. That is the way Southern Company’s old demand response tariff worked (and may still; I haven’t looked at it recently). Is this what you had in mind when you composed the comments that I quoted above?
It is the presumption of “rational” consumers in a rather complex calculation and determining that baseline. One question is whether that baseline is time differentiated or a monthly allowance? I suspect that it would have to be time differentiated to deliver the benefits of such a program. So if a customer decides to be out of town during a peak period and they are stuck buying a bunch of power that they don’t need then they are selling back at the real time price. To avoid those types of situations, the satisficing consumer may choose to hedge only a minimum usage level to avoid being stuck with a large hedged position.
An alternative is not to have an exchange or auction market but rather a dealer market where the utility/LSE buys a hedged amount and then buys and sells with individual consumers. Dealer markets tend to be much more liquid and provide benefits of larger pooled buying. That’s why supermarkets thrive. Dealer market are much more common than other types of markets, particularly for commodities at the retail level. CCAs operate as dealer markets and beginning to delve into bilateral transactions.
Economists don’t think enough about different market structures. (I’m biased because part of my dissertation on the different attributes.) They love auctions where price revelation is part of the process but they don’t consider the transaction costs and other issues associated with one market choice over another.
” I suspect that it would have to be time differentiated to deliver the benefits of such a program.”
Yes, the baselines are time-differentiated down to the metering interval (e.g., 15-minutes).
“So if a customer decides to be out of town during a peak period and they are stuck buying a bunch of power that they don’t need then they are selling back at the real time price.”
Correct. And the customer gets rewarded for doing nothing. Also, there are circumstances where the customer reduces load but does not get rewarded because circumstances cause even his reduced load to exceed the baseline consumption (e.g. an exceptionally hot day – although baselines can be temperature-adjusted).
These are some of the shortcomings in the measurement and verification process but there are ways to detect some of these these anomalies and adjusting for them. However, no baseline will always be precisely accurate. The point is that even with these flaws the benefits of demand response are still positive.
Measurement and verification is an art.
One other point about retail hedging: The average period that a home is owned is 7 years. Renters move even much more often. Given the capital intensity of electricity generation, viable hedging contracts for individual retail customers likely would need to be a decade or longer. That would appeal only to a small segment of the residential market, and likely biased heavily towards higher income customers. The customers who would benefit the most from this risk mitigation would be the least likely to be able to access this option.
No, hedge contracts need not extend out beyond on year, or even less, to insulate the retail customer from wholesale spot market volatility. The typical contract with a REP is one year. Some are shorter.
Robert
Depends on what you’re trying to hedge against. One of the strongest drivers of rooftop solar is the hedge against future utility rate increases. It’s looking like an especially good deal in the face of rate increases of 50% or more in California over the next several years.
With the Energy Institute working to lessen the value of rooftop solar with such things as asymmetric tarrifs and large fixed costs, I am not so sure rooftop solar is as good a hedge against rate increases as many thought.