Why Fixed Charges for Fixed Costs are a Bad Idea

I recently filed testimony in a rate case in Ohio. The utility proposes to recover much of its demand-related distribution fixes costs through the customer charge - adding $10 to the monthly electricity bill of all residential customers. Here is a question and answer addressing the core issue.
You can read the entire testimony by following this link to the
Public Utilities Commission of Ohio website. The question appears at page 18 of the testimony.
The PUCO case number is
Q. Is the Company’s statement of justification adequate and reasonable?
A. The Company’s justification for its residential rate redesign is not adequate or reasonable. First, the Company appears to confuse fixed costs and sunk costs. Sunk costs do not vary with levels of usage; they are, by definition, not subject to change with usage of the associated asset. Once the money is spent to install a conductor of a certain size, that investment is fixed no matter how much, or how little, electricity is carried over it. Sunk costs are historical, or embedded. Given that usage of almost every asset impacts its useful life and the ultimate replacement costs for that asset, very few fixed cost investments involve truly sunk costs.
Fixed costs are costs, like sunk costs, that tend not to vary with level of use over the short term. Over the long term, fixed costs do change with the level of use. An increasing number of utilities are also recognizing, with so-called Non-Wires or Non-Transmission Alternatives projects, that some future fixed costs can be cost-effectively deferred or avoided in the mid- and short-term as well.
In the past, electric utilities did not worry about over-forecasting demand and incurring excessive demand-related fixed distribution costs. If the system was overbuilt, year-over-year growth in energy sales and accompanying demand quickly caught up with any over-building. As Warren Buffet commented in a letter to Berkshire Hathaway investors, “[h]istorically, the survival of a local electric company did not depend on its efficiency. In fact, a ’sloppy’ operation could do just fine financially.” In recent years, utilities have experienced decreasing sales growth, flat sales, and even negative sales growth. At the same time, demand has increased, loads have become peakier, and load factors have declined. Peakier system loads can be addressed in three ways: (1) aggressively pursuing peak reduction programs for all customers, (2) spending more on the system to meet peaks, and/or (3) implementing rate structures that immunize the utility from the consequences of increased demand-related fixed cost investment through non-bypassable rates that ensure utility revenues remain constant regardless of customer usage. The Company’s residential rate proposals focus on the rate redesign approach, with the likely result that they will have to spend more money on distribution system infrastructure.
It is understandable that the Company would try to fix its larger problems with rate restructuring, but it is not reasonable. If a utility company forecasts greater demand for energy than it ends up experiencing, it will have an overbuilt system and experience a situation where sunk fixed costs are potentially stranded—not subject to recovery under current rates. The economically efficient solution is good price signals that do not undermine the economics of demand response and energy efficiency, better forecasting, and a smarter grid that leverages the potential benefits of all manner of distributed energy resources. As explained previously in the section discussing impacts on energy efficiency and distributed generation, the Company residential rate proposals not only constitute the bad choice, they frustrate the good ones.
For example, if the utility forecasts that demand on a particular feeder will be heavy, it may install a larger, more expensive transformer. The money spent on that transformer is a historical or sunk cost. Since the money is for a transformer, the costs will be treated as a fixed cost, and allocated accordingly. If demand does not match the forecast, the utility will face problems recovering the cost of the too-large transformer through volumetric rates. Of course, if the utility is guaranteed recovery of the costs through fixed charges, it will have no incentive to improve the accuracy of its forecasts. Importantly, the size of the next transformer and associated cost is a fixed cost that can be impacted by customer demand in the future. Energy efficiency, demand response, and other factors can reduce the fixed cost requirements in the future, and perhaps even allow for the installation of smaller replacement equipment. These measures can also extend the useful life of the installed fixed cost assets. For these reasons, the price signal impacts of rate design can and do impact fixed costs on a going forward basis.
Second, even if demand and customer connection costs are the primary drivers of distribution costs, this does not compel or even justify the allocation of demand-related fixed costs to the customer charge. The Company offers no evidence to support the leap of logic that because demand-related fixed costs are, like customer connection costs, a driver of distribution costs, they should therefore be collected as a customer cost.
Third, the statement about price signals is illogical in the extreme. The Company assertion is that recovery of fixed costs through the volumetric energy is a false price signal because a change in usage cannot reduce demand-related costs. Again, the Company confuses fixed costs with sunk costs. It is widely accepted—and a strong justification for grid modernization investments—that customers can reduce the requirement for expensive infrastructure investments by reducing their usage during particular times of the day. These reductions arise as a result of reduction in system loading so to avoid upgrades, as well as reduction in wear and tear (temperature-related degradation) and resultant capital cost deferrals for replacement. Higher volumetric charges for on-peak usage can support demand response programs and energy storage deployment with similar results.

Comments on MIT Utility Report

MIT Issued a New Report Titled “Utility of the Future”
I share some reactions – not intended to be comprehensive or “fair and balanced.” These are the things that worry me.
MIT Report Greatest "Hits" (1)
From the regulators toolkit chapter – p. 307, et seq. 
“Any policy costs, taxes, and residual network costs that are not directly affected by changes in electricity consumption or injection should be removed from the volumetric ($/kWh) component of the tariff and charged in a manner that minimizes distortions of cost-reflective prices and charges for electricity services.”
Note the subtle reversal of decades of regulatory practice. The way things are now, and should be, is that only cost that directly vary with customer count and connection should be placed in fixed charges. Here, they advocate that the burden is to prove that the cost must be “directly affected by changes in electricity consumption or injection” in order to be in the volumetric charge.
MIT Report Greatest "Hits" (2)
Here is a blast from the past – the notion that customers who reduce their use of the utility product must pay for the right to do so through “exit charges.”
“Regulators and policymakers must also carefully monitor conditions that could lead to a serious threat of inefficient grid defection. If inefficient grid defection is a serious possibility, regulators should reconsider the costs that are included in the tariff, or the adoption of other measures (e.g., an exit charge), to prevent substantial cross- subsidization among consumers and a potential massive defection with unforeseen consequences.”
At p. 310
MIT Report Greatest "Hits" (3)
From p. 310 (call out box):
“We recommend a fixed charge (an annual lump sum conveniently distributed in monthly installments). The magnitude of each customer’s charge should be dependent upon some proxy metric of lack of price elasticity or some measure of wealth, such as the property tax or the size of a system user’s dwelling.”
Lack of price elasticity means – if the customer lacks any serious ability to change their consumption in response to increased prices, they are the ones that should bear the increase.
Think about that for a minute. And know that it is the “classical economic” argument about Ramsey pricing as the appropriate tool to recover excess monopoly embedded costs (e.g. from overbuilding) under monopoly pricing.
There is nothing “future” about this.
MIT Report Greatest "Hits" (4)
How does this classical economics and LMP (market prices are so wise!) mumbo jumbo translate for the large, very large, percentage of customers who are low- to moderate-income? Those who can’t jump into a full-on time of use world?
From p. 313, call-out box –
“Distributional concerns can be overcome and low-income consumers can be protected without giving up the implementation of a more efficient and comprehensive system of prices and charges for broad swaths of network users. Rebates to equalize average charges and mechanisms to hedge month- to-month bill volatility are some of the instruments that can be used to properly address these concerns.”
How durable would such rebates and supplemental payments really be? How likely is it that the regulators or legislatures would adequately fund them?
Pish posh – at least the poor are getting good price signals! (If they have no bread, then let them eat cake!)
MIT Report Greatest "Hits" (5)
How does this work for the incumbents? Well, what do we call costs charged that customers cannot realistically avoid, approved for imposition by regulators? Monopoly rents.
“Monopoly rents are (supernormal) profits earned that result from the monopolist restricting supply to raise price without fear of entry by rivals. They are distinct from Ricardian (scarcity) rents and from Schumpeterian (innovation) rents.”
As to “entry” – see previous Hit on exit charges.
MIT Report Greatest "Hits" (6)
Section Costs to be included in the tariffs
In which the authors point out that including “residual costs” – costs not directly related to volume of consumption – can raise rates and result in lower consumption!
Of course, that is a bad thing – because using more electricity is “economically efficient” and it may even indirectly reduce demand for renewables.
No discussion about economic incentive for energy efficiency, of course, because everyone is being just as efficient if they can be in the la-la-land of the neo-classical economist’s brain.
Oh, and if you are going to argue the carbon benefits of reduced consumption, the authors would like you to consider that the entire distribution system should be paid for in taxes. Cuz what is regressive about that?
MIT Report Greatest "Hits" (7)
Recommendation 13: Equalize incentives for efficiency in capital and operational expenditures.
That is, give the utilities rate of return (profit) on expenses as well as capital investments.
Cuz the traditional rate of return formula did such a great job of preventing over-building and over-spending.
MIT Report Greatest "Hits" (8)
Basically all of Chapter 5, which says that it is hard to be a distribution utility in a world where customers might invest in distributed energy resources.
So, after a commendable nod to designing efficiency metrics for the utility, the report concludes that best practice would be variations on one theme: Guaranteed Revenues. They call it a “Revenue Cap,” of course, to suggest that total revenues would be capped – they would not.
The proposals are a byzantine consultant’s dream of reference metrics, shared savings ratios, and other performance-based ideas.
I support performance based regulation, to be sure! But I would like us to measure performance against reducing customer bills and carbon emissions. Do we really have to ask much more?
Oh, yeah. And I would like utilities to do a much better job of forecasting under a high-DER scenario.
Proposals to immunize utilities from the consequences of over-building and reduced sales are nothing more than monopoly protectionism. And any (equivalent to) lost revenues payments send a powerful signal to the utilities to do nothing to improve the accuracy of their forecasts and to reduce revenue requirements.
Simply put – DER markets and utility transformation should eliminate the need for decoupling and lost revenue adjustments, if not in the near term, at least some day.
Isn’t that what a market would do?
MIT Report Greatest "Hits" (9)
This I actually like.
“We find that the best solution, from a market efficiency perspective, is structural reform that establishes financial independence between the distribution system operator (DSO) and any agents performing activities in competitive markets, including adjacent wholesale generation and ancillary services markets and competitive retail supply and DER markets within the DSO’s service territory.”
It needs to say more about a well-regulated DSO, but it is the right basic positioning.
MIT Report Greatest "Hits" (10)
I like this one, too:
Recommendation 19: Legal or functional independence requires significant regulatory oversight and transparent mechanisms for provision of services.
Last time we did dereg we mouthed a lot of silly language about how we would need less regulation – regulators would be put out of their jobs! Of course, Enron.
So, ignore the sentence right above this recommendation about “light-handed regulation,” and commit to the proposition that utility transformation is a full-contact regulatory activity.
We need the sharpest regulators, adequate funding for staffs, funding for intervenors, and strict rules of the road—this time.
MIT Report Greatest "Hits" (11)

This one is a doozy. The run-up is a bit of a straw man argument, about how there is no single “value of solar” or “value of” any DER. (Just like there is no single class-wide cost of service – but rate averaging works for the utilities, unlike average value of DER estimates.)
“To accurately value the services provided by DERs, prices, regulated charges, and other incentives must therefore reflect the marginal value of these services to the greatest extent practical.”
So, DER should only get its short-run marginal cost savings value. Never mind that a solar system will operate reliability for 25-plus years and that long-run value is how the utilities justify most of their investments.
This is neo-classical economics, of course, the argument is that we will get “efficient markets” if we value everything against short-run marginal costs. There is some truth to this, but not in markets with humans involved. And that wise course has us spending money to uplift out-of-market coal and nuclear resources (I can accept the latter, for a while, for carbon reasons). In the Midwest, the utilities are even arguing for major changes to wholesale markets – “organized market reform” – because coal plants can’t keep up with market prices.
The wholesale markets don’t do a good job assessing and reflecting long-run marginal costs. DER is too important to risk with some kind of classical economist’s theoretical dream.

Value of Solar Letter to a Muni Manager

A few months ago, I had a chance to write to a current municipal utility manager in Massachusetts. He was considering changing net metering rates. I wrote to explain the option of using a value of solar analysis to support the compensation rates under net metering, and a few other thoughts.

Here is the letter:

Dear Mr. X:
Thanks for the background about your utility and the issues you are considering.
Let me start by disclosing that I am the author/inventor of the Value of Solar tariff.
We had been using a Value of Solar calculation methodology at Austin Energy (a large muni in Texas) for some 6 years (before I arrived there) to benchmark several programs. I was the VP for Distributed Energy Services there. I ran world-class energy efficiency programs, distributed generation programs, EV infrastructure deployment, weatherization, and other efforts.
Basically, we wanted to know what value distributed solar brought to our system so that we would know what rate to compensate or procure it. I was managing a growing distributed solar market and program in a utility that wanted to do more solar.
This is important - if you don’t want to do more solar, a muni has a lot of tools -
1. Don’t provide fair compensation
2. Make interconnection difficult and expensive
3. Make processes take a long time
4. Make permitting difficult and expensive
On the other hand, if you want solar to develop in a orderly manner that ultimately becomes a “self-sustaining market” and if you don’t perceive it as a business threat, but rather a management challenge, then it really makes sense to find out what it is “worth.” And it makes sense to compensate - set the offset credit - at that value. That also helps you benchmark incentives, self-build options, etc.
This is almost exactly like the PURPA avoided cost process, but instead of measuring avoided costs at the power plant busbar, you measure it at the meter. Since that is the point of energy injection. And instead of only considering wholesale value (because that is the jurisdictional authority of the federal government), you also look at the full benefits and costs down to the retail level.
I used the value of solar calculation to come up with a defensible number that used sound ratemaking principles to find the “indifference value” - basically the full avoided cost. I wanted to know the number at which either I could provide it (as the utility) or the customer could, and I wouldn’t really care which. That means really unbundling what the delivered kWh does, what costs it represents, and what costs customer-generators could help me avoid, and what costs they created. (This process is what we used in the telephone industry years before - and is still used to allocate costs and credits for local and long distance and other cost elements.)
The first thing I realized is that net metering customers don’t “avoid” any charges at all. All customer-generators are fully billed for 100% of their consumption. The only real issue, and this is also important, is what offset credit we should give them for generating a kWh that we did not have to. And it was NOT just a kWh at the wholesale node, and helped avoid other costs we would normally incur, in the short run and over the full lifetime of the solar system. The accountants only see the net revenue, so they think that customers are “avoiding” costs. But really, you have a full charge for full consumption - which is entered on the revenue side.
Then you are “paying” an offset credit - that has to come from somewhere. Where it comes from is savings - what do you save when you don’t have to make and deliver the kWh that the net metering customer makes.
I also realized that excess kWh was easy - it flowed immediately to the nearest load, through a meter, and we collected the full retail rate for it! So we were kept 100% whole on that kWh and maybe even “profited” during peak periods when the market prices were higher than retail. We made special note that even if our system peak was at 6 pm, our system costs and fees were set on the system peak - and solar was on then. And we used an Effective Load-Carrying Capability analysis to calculate a capacity “credit” - since annual capacity factor told us nothing useful.
Bottom line - we looked at the solar customer generation system as a resource. And we used resource valuation techniques to measure its worth, on a 25-year levelized cost of energy basis. After we did the analysis and repeated it for many years, we learned several things.
We were free to do all that because we were a municipal electric utility, and if customer investments in distributed solar saved money, that would be a good thing. And since our board, the City Council, wanted us to be responsible in every sense of the word, having analysis was vital to earning and maintaining credibility.
We learned that the wholesale price is basically not right and far too low - since it did not account for several value components relating to transmission and distribution, reduced environmental costs, protection against price volatility, reduction in our annual capacity charges, etc.
We were also aware that distributed solar, like energy efficiency, was a much more valuable source of jobs, local economic development, spending multipliers in the community, tax base improvements, property value, etc. We accounted for those benefits in a separate study that informed policy but did not show up in rates.
We used a consultant to develop a methodology that could run on a simple spreadsheet. We learned - with data - that the value of distributed solar generation was higher than the retail rate, if you take a 25-year levelized cost/value of energy approach.
No “funny” numbers here - the operations guys actually inputted the data and ran the calculation - they were quite comfortable with the numbers produced for the rate-setting portion of the analysis. And over 6 years before I applied the number in a retail net metering rate (the Value of Solar Tariff), they saw that it tracked with reality and with their expectations.
What can I tell you on short notice? If you had time and budget and data, you would learn a lot about the value of customer solar in your municipality. You would learn:
That the wholesale price is unreasonably low. And that if you were doing perfect cost-of-service ratemaking, and thinking about future costs as well as sunk costs, you would find that your value of solar is probably closer to retail than wholesale, and actually a little higher than retail.
This value squares with common sense - the kWh that the customer generates does all the work that the utility-provided kWh does, and it is carbon-proof, fuel-price volatility proof, privately financed, privately insured, and we only provided a credit if they actually generated energy! Basically, it is “the good stuff” and it is worth more than generic system power that has to be generated and transmitted and distributed at ratepayer/citizen expense.
You would find that over the life of the system, solar will actually put downward pressure on rates. And that fair value compensation will allow solar to happen without a lot of additional subsidies. You would find that there are substantial numbers of customers who would invest a good deal of their own money to basically supplement your system and harvest that value for your entire community.
That opportunity is why the Net Metering Task Force in Mass recommended such a study.
Acadia Center has run some numbers -
Here is the most up-to-date guide on how to assess Value of Solar -
You would probably not see very different numbers from the Acadia study if you did the analysis yourself - but there are some details relating to getting “credit” for upstream issues that do show up with a muni that does not own its own generation. Since I don’t know the terms of your supply and transmission agreements and rates, it is hard to opine. Note that this does not negate the value, only change the way you need to get credit for it.
Generalizing from my experience around the country - and worth what generalizations are worth, I can also tell you:
You will probably experience some well-justified criticism for using a wholesale rate for either the excess or the entire amount of generation. You will not find any real support for that rate in any of the published literature or analysis. Even the most stingy utilities add at least line loss credit, variably O&M credit, fuel price stability credit, and some environmental regulatory risk reduction credit.
We are amassing all the info we can on the topic at our Value of Solar Center of Excellence website - http://voscoe.pace.edu - and it generally supports my generalizations.
I would be pleased to address any of the APPA materials that you have reviewed, if that would help.
I am pretty confident your rate review did not address the value of solar. At best, it probably considered the cost to serve the average residential customer - who by definition doesn’t self-generate. So it indicates what you save on costs - the retail rate - until you perform and actual cost of service study for net metering customers.
Grandfathering is definitely the right thing to do. I wouldn’t get all lawyerly on that issue - and recommend you just do the right thing.
One way to get past the “percent caps” issue is to use VOS analysis - since it captures benefits and costs, it will alert you to whether the penetration rates are creating integration costs. (LBL studies suggest that you won’t even be able to reliably measure those costs below 2.5% and that they are not significant until 10% - 15% penetration rates.
Finally, this stuff all traces back a few decades. We learned in the mid-1990s, for example, that solar looks like a high-efficiency heat pump to the grid, at least up the point of excess production. That solar has measurable capacity value in the grid. That transformers last longer and fail less when they are pre-cooled by solar generation (or demand reduction). That future T&D system costs are reduced by distributed generation. etc.
We documented all this when I was at Rocky Mountain Institute in a book called “Small Is Profitable,” published in 2003. And we explored the additional benefits of prospecting for high-value locations in the grid (against the metric of Marginal Distribution Capacity Cost) in a study entitled “Fuel Cells Are Profitable” (if my memory serves) - which showed that in heavily congested or otherwise expensive location, even very expensive Fuel Cells are cost-effective (published around 2004).
Finally, I will note that the market test that validates what I have described is now appearing in all the smart grid work, DA/DMS investment, and exciting new services offered by businesses like Current by GE (www.currentbyge.com). Looked at as a resource, customer-sited DG could have a lot of value for your utility as well.
I hope this helps a little!

Treating Efficiency (and other DER) as a Resource

I had a chance to hear Tom Eckman speak at an Energy Foundation Energy Efficiency Advocates meeting in Atlanta on September 30, 2016. He mixes humor with wisdom and shares some really profound lessons and insights, gained through decades of work in energy efficiency. He was kind enough to share this piece about treating energy efficiency as a resource. It is well worth a read - and the lessons in it apply to all distributed energy resources.


Sustainability Pioneers - Boulder

Check out the Sustainability Pioneers site!

Energy transition does not happen overnight – it is a step by step process. Steve Pomerance from Boulder, Colorado built a solar home after learning about climate change in the 1970’s. Since then he, with a group of other concerned citizens and the city of Boulder, have been paving the way for the city to go fossil free by 2030. Along the way, they are pressuring the state and the utility to go green with them.
Jonathan Koehn, Regional Sustainability Coordinator of the City of Boulder, explains why Boulder is attempting to municipalize its utility, and Karl Rábago, Executive Director of the Pace Energy and Climate Center, paints a bigger picture of how the utility industry is -or is not- responding to climate change.

Here is a
Vimeo VIDEO of about 13 minutes that tells the story, from the highly skilled Kirsi Jansa and team.