EDITORS INTRODUCTION
The last issue of Energy Regulation Quarterly (ERQ) included an article by Ahmad Faruqui on “Accelerating Electrification by Lowering its Operating Costs Through Technology-Specific Marginal Cost Pricing”[1]. Two Comments on that article follow.
As a forum for discussion and debate on issues affecting regulated energy industries, ERQ welcomes reader comments.
Carl R. Danner
I appreciated this article from Dr. Faruqui, and can see the appeal of price discrimination to benefit incremental loads for purposes that policy makers favour. To the extent feasible, it would preserve the position of other customers and loads as he mentioned. This has been a point raised in other instances of preferred prices for incremental demands, such as the low gas rates sometimes offered years back to industrial customers who had the ability to switch to oil fuels.
At the same time, this proposal raises some practical and philosophical questions, such as the following:
- For a customer who adopts the new technology, how much electricity should be offered at the preferential rate? Is there a way to track actual incremental usage? How much error is likely if simple measures are attempted (like pre and post bill comparisons)? What about a simple block discount entitlement (e.g. heat pump = a set number of kilowatt-hours at the marginal cost rate)?
- What about arbitrage possibilities, such as by drawing household electricity usage from the car battery? Or charging up the car to replenish the neighbour’s home batteries before charging it up again? Would such a large price incentive spur increasingly innovative responses? My favourite creative example was a discovery by California Public Utilities Commission staff of a fake mockup oil tank and pipes at an industrial facility seeking to pay a lower gas rate meant for those with fuel-switching capability. If we called usage for non-intended purposes “leakage”, how much might be anticipated under this rate proposal?
- What makes electricity demands for EVs and heat pumps so worthy compared to other demands that are now being suppressed due to California’s high electricity prices? Why are the preferences of government officials so important and those of members of the public (for themselves) to be overlooked?
- With regard to the fixed charge recently imposed on electricity bills from large California utilities (to reduce, somewhat, the high usage rates), would a more apt nationwide comparison involve the percentage of the bill rather than an average dollar amount? On the same dollar to dollar basis, what is the ratio of per-kWh rates for CA versus those across the nation? Given CA’s supersized bills, might larger fixed charges just come along as an unfortunate part of the package?
- For heat pump adoption including realistic installation costs and for full lifecycle electric vehicles, what is the per ton carbon abatement cost? How do those change if one includes reasonable estimates for consumer welfare losses due to forced or pressured adoption? (While this is beyond the scope of Dr. Faruqui’s analysis, these are important questions and perhaps someone has addressed them.)
- The expense of electric vehicles and heat pump adoption might suggest that wealthier people would disproportionately benefit from this policy. Is that accurate, and if so, acceptable?
- Might Dr. Faruqui’s proposal be extended to operators of vehicle charging stations as well? Could they be offered more sophisticated wholesale prices, e.g. a clearance rate during times of excess solar output?
I hope these questions will be of interest to readers of Dr. Faruqui’s analysis.
Philip Quadrini
Dr. Faruqui’s article[2] explains how electric rate design can be a barrier to the adoption of green end-use technologies and why these technologies should be priced at the utility marginal cost.
In my San Francisco Chronicle op-ed[3], I proposed charging for incremental green usage at the lower Tier 1 (baseline) rate. Richard McCann, of M-Cubed, pointed out to me afterward that the utility marginal cost is much more cost-based and lower. I could not disagree.
First, I would like to propose a simpler rate design than what Dr. Faruqui proposes: instead of using changes in a customer’s load shape to apply the marginal cost rate, apply it to pre-determined usage levels for each particular green technology, provided the customer is on an accurately designed Time of Use (TOU) rate.
For example, electric vehicle customers would be charged the marginal cost rate for their first 300 kWh of monthly usage (or receive a commensurate discount), regardless of their actual EV charging. Pacific Gas and Electric Compagny (“PG&E”) already uses this method for customers with medically necessary equipment: 500 kWh/month at the lower Tier 1 (baseline) rate. This rate design change could be implemented relatively quickly and is easy for customers to understand.
Second, there is no need to charge the marginal cost rate for heat pumps during the months of May through October since the heat pump replaces the pre-existing air conditioner. Hence, there is no net increase in usage during these months.
Finally, Dr. Faruqui proposes adding capacity cost to the rate design “if electrification in certain zones bumps into distribution capacity constraints.”[4] This may already be an issue with electric vehicles. Unless the EV owner is on a TOU rate, the owner will most likely plug in their EV when they return from work in the early evening when distribution demand is highest. Most EV customers are not on a TOU rate; neither are the vast majority of legacy solar customers. This can and will lead to capacity additions and rate increases.
The best way to avoid this is to first, require all customers to be on a TOU rate, and second, set the peak period at 6PM-9PM, with a shoulder peak one hour before and one or two hours after. (This is more accurate than PG&E’s current 4PM-9PM peak period.) However, it may be necessary to have a modestly different peak period in coastal areas where the load shape is different.
Heat pumps represent a potential costly impact to the grid in areas without air conditioning. Areas with air conditioning, representing more than 60 per cent of PG&E customers, can easily handle increased winter loads from heat pumps because their circuits and local distribution systems were designed for much high summer loads. But communities without air conditioning, suc h as Berkeley, have little excess capacity in the winter to absorb new load from heat pumps. Unlike an EV, which is used year-round, using a heat pump for space heating is largely limited to just five months of the year. Therefore, it may not be cost-effective to encourage adding heat pumps on some circuits. Finally, anyone who adds a heat pump to a house with no air conditioning – as in Berkeley – will most likely use it as an air conditioner during summer heatwaves and cause spikes in summer loads. This could also increase costs.
To summarize, marginal cost pricing is the right solution for incremental green electricity, but only if the peak period is designed to avoid or minimize costly load increases. This requires each utility to identify, for each circuit and local distribution area, the times of the day and months when green electrification increases distribution costs, then devise the least-cost solution(s) to mitigate it. However, since utilities increase their profits by adding capacity to the grid, this is going to require legislative and regulatory oversight.
EDITORS INTRODUCTION
The last issue of Energy Regulation Quarterly (ERQ) included an article by Ahmad Faruqui on “Accelerating Electrification by Lowering its Operating Costs Through Technology-Specific Marginal Cost Pricing”[1]. Two Comments on that article follow.
As a forum for discussion and debate on issues affecting regulated energy industries, ERQ welcomes reader comments.
Carl R. Danner
I appreciated this article from Dr. Faruqui, and can see the appeal of price discrimination to benefit incremental loads for purposes that policy makers favour. To the extent feasible, it would preserve the position of other customers and loads as he mentioned. This has been a point raised in other instances of preferred prices for incremental demands, such as the low gas rates sometimes offered years back to industrial customers who had the ability to switch to oil fuels.
At the same time, this proposal raises some practical and philosophical questions, such as the following:
I hope these questions will be of interest to readers of Dr. Faruqui’s analysis.
Philip Quadrini
Dr. Faruqui’s article[2] explains how electric rate design can be a barrier to the adoption of green end-use technologies and why these technologies should be priced at the utility marginal cost.
In my San Francisco Chronicle op-ed[3], I proposed charging for incremental green usage at the lower Tier 1 (baseline) rate. Richard McCann, of M-Cubed, pointed out to me afterward that the utility marginal cost is much more cost-based and lower. I could not disagree.
First, I would like to propose a simpler rate design than what Dr. Faruqui proposes: instead of using changes in a customer’s load shape to apply the marginal cost rate, apply it to pre-determined usage levels for each particular green technology, provided the customer is on an accurately designed Time of Use (TOU) rate.
For example, electric vehicle customers would be charged the marginal cost rate for their first 300 kWh of monthly usage (or receive a commensurate discount), regardless of their actual EV charging. Pacific Gas and Electric Compagny (“PG&E”) already uses this method for customers with medically necessary equipment: 500 kWh/month at the lower Tier 1 (baseline) rate. This rate design change could be implemented relatively quickly and is easy for customers to understand.
Second, there is no need to charge the marginal cost rate for heat pumps during the months of May through October since the heat pump replaces the pre-existing air conditioner. Hence, there is no net increase in usage during these months.
Finally, Dr. Faruqui proposes adding capacity cost to the rate design “if electrification in certain zones bumps into distribution capacity constraints.”[4] This may already be an issue with electric vehicles. Unless the EV owner is on a TOU rate, the owner will most likely plug in their EV when they return from work in the early evening when distribution demand is highest. Most EV customers are not on a TOU rate; neither are the vast majority of legacy solar customers. This can and will lead to capacity additions and rate increases.
The best way to avoid this is to first, require all customers to be on a TOU rate, and second, set the peak period at 6PM-9PM, with a shoulder peak one hour before and one or two hours after. (This is more accurate than PG&E’s current 4PM-9PM peak period.) However, it may be necessary to have a modestly different peak period in coastal areas where the load shape is different.
Heat pumps represent a potential costly impact to the grid in areas without air conditioning. Areas with air conditioning, representing more than 60 per cent of PG&E customers, can easily handle increased winter loads from heat pumps because their circuits and local distribution systems were designed for much high summer loads. But communities without air conditioning, suc h as Berkeley, have little excess capacity in the winter to absorb new load from heat pumps. Unlike an EV, which is used year-round, using a heat pump for space heating is largely limited to just five months of the year. Therefore, it may not be cost-effective to encourage adding heat pumps on some circuits. Finally, anyone who adds a heat pump to a house with no air conditioning – as in Berkeley – will most likely use it as an air conditioner during summer heatwaves and cause spikes in summer loads. This could also increase costs.
To summarize, marginal cost pricing is the right solution for incremental green electricity, but only if the peak period is designed to avoid or minimize costly load increases. This requires each utility to identify, for each circuit and local distribution area, the times of the day and months when green electrification increases distribution costs, then devise the least-cost solution(s) to mitigate it. However, since utilities increase their profits by adding capacity to the grid, this is going to require legislative and regulatory oversight.