Tuesday, February 8, 2011

Time-Of-Use Pricing

Time-of-Use (TOU) pricing is being implemented in Ontario.  This should provide the personal benefits of Ontario’s spending on smart meters.  More likely, it will result in the same efficiency gains we’ve seen on our bills from the rest of the smart grid initiatives (higher line loss factors added to our usage, and higher delivery charges in general).    Electricity policy encompasses issues of security, social responsibility, economics, politics, and environmental concerns.  TOU billing has implications for all of these things.   I won’t revisit the role of the OEB in protecting, or neglecting, the Ontario consumer – it’s in the smart meter column.  I will show TOU is limited in it's ability to alter Ontario's electricity supply - a supply that is being altered in a way incompatible with the intent of TOU as a demand management tool.

One approach to Demand Side Management (DSM) is the application of time-varying pricing structures – these require interval meters.  The smarter meters allow the movement away for a blended rate, which in Ontario has been practiced as the Regulated Price Plan (RPP).  Time-Of-Use (TOU) pricing is one approach to time-varying pricing.  The most significant other approaches are real-time pricing (RTP) and critical peak pricing (CPP), and then there are a number of hybrid approaches.    An overview of the reasons for DSM is available at the International Energy Agency (IEA) site for it’s DSM programme.    From that site:
Demand Side Management (DSM) was widely discussed in the 1980’s as the alternative to supply side “overspending” in energy systems. In the US DSM was carefully regulated with detailed procedures for investigating cost-effectiveness, rate-impact, programme deliveries, availability for different groups of customers. Public Utility Commissions had hearings with advocates from both sides. Outside the US the application was in most countries less formal but the basic idea was the same; that the least-cost option for the energy system performance should be chosen when more supply or less demand were compared on equal terms.
The “Negawatthour” (NWh) was made the conceptual alternative to the Megawatthour (MWh).The solutions were focusing on two issues, one was to reduce the demand for energy (conservation) and the other was to shift demand from peak periods to off-peak periods (load-management). Both measures motivated by a concern for resource optimisation. 
RPP (blended rate) plans have the advantage of not requiring the replacement of every meter in the jurisdiction, and an RPP can provide consumers some price clarity.   In Ontario this isn’t the case.  Utilities in Ontario add line loss adjustments, regulatory charges, debt retirement charges, delivery charges, and taxes onto the bill.  If you could check with the 10 smartest Ontarians you know, I doubt you’d find 3 who guess within 20% of what they paid, per consumed kWh, on their electricity bill.  All would be aware if their bills were going up, or down, though.   The TOU plan implemented in Ontario is also, essentially, blending rates – it’s simply doing so based on a far more speculative, and/or political, basis.  The Minister of Energy, Mr. DuGuid, recently mused perhaps peak rates needed to be 3 times what off-peak rates are.  If Mr. Duguid had checked the price history at the Ontario Energy Board (OEB), he would have found that is where they started (not including the 8-10 cents/kWh on the bill that are not impacted by ‘per kWh’ charges):

The ‘Low RPP’, and ‘RPP Avg’ figures on this graph are important.  The TOU average should equate to the RPP average if cost neutrality is achieved, so TOU customers should balance out at that black line.   But many small households in Ontario are billed entirely at the ‘Low RPP’ rate (it applies to the first 600kWh spring and summer, and the first 1000kWh in the fall and winter).  For a typical consumption pattern, Ontario’s switch to TOU pricing is regressive, because the customers consuming least see an increase, while the heaviest users (more that half their usage at the High RPP rate) see a decrease.  The government sent out some minions to stem the criticism in the fall, and they dutifully noted the majority of customers on TOU had lower bills in the hot summer of 2010 than they would have under the RPP.  This is why.  

TOU plans, in Ontario, and from what I can see in most other jurisdictions, are regulated to be revenue neutral.  This is an interesting concept all by itself – they are supposed to be revenue neutral, and the pricing is done with the assumption that there will be no change in the consumption pattern.  The problem is, that’s a pretty good assumption.   Because they are revenue neutral most won’t notice them at all, and they’ll have no impact.  Customers have been transitioning to TOU billing for a couple of years now, and there’s been no change in usage patterns.   I’ve entered the times (not accounting for holidays) into a database and here’s the estimated breakdown:

The data, in this case annual, shows no proportional change in the consumption pattern.  This data is very preliminary, but it does show that based on the initial households, a program implemented without any specific measurements of what it should accomplish isn’t likely to accomplish what it was hoped it would.

The Abstract for one study of the PJM market, which moves similarly to the Ontario market, stated:
In PJM, 15% of electric generation capacity ran less than 96 hours, 1.1% of the time, over 2006. If retail prices reflected hourly wholesale market prices, customers would shift consumption away from peak hours and installed capacity could drop. I use PJM data to estimate consumer and producer savings from a change toward real-time pricing (RTP) or time-of-use (TOU) pricing. Surprisingly, neither RTP nor TOU has much effect on average price under plausible short-term consumer responses. Consumer plus producer surplus rises 2.8%-4.4% with RTP and 0.6%-1.0% with TOU. Peak capacity savings are seven times larger with RTP. Peak load drops by 10.4%-17.7% with RTP and only 1.1%-2.4% with TOU. Half of all possible customer savings from load shifting are obtained by shifting only 1.7% of all MWh to another time of day, indicating that only the largest customers need be responsive to get the majority of the short-run savings.
This study itself explores the price elasticity of demand.  I have always been of the opinion energy demand is inelastic, but this study, and others, imply there are large customers capable of adjusting their usage with the price – ie. there may be categories of customers that have more elastic demand.  This is important as the greater the demand elasticity, the less acute the price changes need to be to trigger the demand change, and/or, the greater the elasticity the greater the impact of an equal price change.   One conclusion of the paper;  “Because only modest aggregate price elasticities are necessary for large peak capacity savings, most of the benefits can be achieved by shifting only large, responsive customers to RTP.”

There’s a solution to Ontario’s regressive implementation indicated here – don’t put customers consuming less than 800 KWh/month of the TOU plan.  Practically speaking, that also solves the metering issues for large apartment buildings and condominiums currently lacking separate metering for each unit.

Severin Borenstein explored some of these issues in Electricity Pricing that Reflects Its Real-Time Cost.  Borenstein notes a structural issue in transitioning a from a regulated pricing scheme, which I’ve been referring to as a RPP, to a RTP mechanism:
Under regulation, the utility nearly always charges prices that are based on some notion of average cost, including the accounting amortization of long-term capital expenditures. Such an approach is targeted at cost recovery, not efficient pricing. Also, regulated utilities may be less likely to appreciate one of the main attractions of RTP, the effect it has in shaving demand peaks and reducing the need for capital investment. If regulators allow utilities to earn generous returns on investment, or if the utility management simply wants to grow the company, a pricing strategy that constrains new capital investment is unlikely to be popular with managers.
Theoretically, we should anticipate both that there are electricity market segments that have more price elasticity than others, and that the electricity supply market would provide resistance in moving to a more efficient market if their ROI’s (or ROE’s) continued to be regulated as they have in the past.  Put another way, a policy of reduced demand without any policy to reduce supply, is not a policy to allow a functional market to provide increased efficiencies.  It’s a policy of inflation and oversupply.  This is what we see with Ontario’s rapidly escalating residential prices.

I find the elasticity of demand for electricity, at peak demand periods, isn’t likely elastic at all – or, more correctly, it’s inelastic in the very short.   Following a particularly cold winter, people may switch their heat source away from electricity, insulate better – or add more heat sources.   The choice between upgrading the building’s thermal seal, or adding cooling, is the same in the summer.  This should have brought up issues both from a broader energy policy perspective, and an environmental perspective.  It is not desirable to move all homes from electric heating to natural gas heating, for both air and water, nor, from an energy security perspective, is it desirable to rely on natural gas to both heat our homes and, due to supply mix changes, to generate our electricity.  From a social perspective we should not have intentionally driven up the price of electricity knowing that the poorest households are not only the least likely to own their residence, and therefore the least likely to personally realize efficiency upgrades, they are also the group most likely to heat with electricity, and the group that spends the highest proportion of their incomes on energy (nearly 3 times the proportion richer households do).

The data, from the Independent Electricity System Operator (IESO), is indicative of the shortcoming of Ontario’s TOU implementation.

Since May 2002, we can see that demand has trended down – here shown by month:

I have written how this trend has little to do with price, and that we are paying the people taking credit for it.    But if it did indicate some longer-term elasticity of demand for electricity, that is simply an argument for higher prices to reduce total consumption.  No smart infrastructure is required for that.  How much higher prices need to move to achieve the government’s goals is important to note.  The 2008 Ontario budget included; “The 20-year plan begins with replacing coal-fired generation by 2014, reducing electricity demand by 6,300 megawatts (MW) or about 20 per cent of projected future peak demand.”  At a price elasticity of demand of -.1 (which is amongst the most optimisticly elastic claims for residential electricity), that suggests tripling the price.  The price has doubled since 2003 for residential electricity, and another 50% - to make it triple - is only 5 years away according to the government.   The question is therefore a very cynical one – is Ontario deliberatly giving money away to the chosen few, in order to justify tripling the price, which is the actual electricity policy?

The average hourly consumption, by month, shows declining consumption, but the trend is less clear in the summer.  The most likely explanation for that undermines the environmental rationale desiring reduced electricity consumption.  That elasticity of demand is more pronounced long-term because of the option of heating the residences, and water, directly with natural gas.   It is far more difficult to find alternatives to cooling with electricity.
The TOU pricing has a tougher task – to change the consumption pattern within one day.  Over the same period, this graph shows the average daily variance (MW), between a day’s peak consumption, and the minimum, in Ontario:

There is no declining trend over the years in intra-day consumption patterns.  The record month is July 2010, at an average difference of 7271 MW over each day (some summer days will see the peak more than 10000MW above the minimum overnight consumption).  Taking steps to reduce consumption generally reduces consumption at all times – not just hourly. The summer has the greatest intraday variance because the demand is for cooling, which is most necessary in the middle of the day, and therefore coincides with commercial/industrial and MUSH sector activities.  In the winter, the coldest periods are at night, so the usage doesn’t’ vary as much over a 24 hour period.   If we abstract the peak to concentrate on, and agree it is in the summer, we see the pattern for each month's peak consumption are essentially the same as the trends for the variance between the lows, and highs, of each day:

We also see the annual summer peak averages about 2000MW above the winter peak (2004 being the last year the annual peak was in the winter).
Looking at the data as hourly averages by season, we see that the only actual ‘peak’ hours in 6 months of the shoulder seasons are the dinner hours in the fall:

Ontario has three big challenges.  Stop people from cooking supper, unless they cook it with gas – or wood, discourage air conditioning, and get people to heat with gas – or wood.

The theoretical benefit of TOU is reduced production capacity requirements.   Borenstein’s article concluded, from an RTP study in California:
The results were sobering because as exciting as the prospect of "getting prices right" may be to economists, the potential gains were likely to be only 5 percent or less of the energy bill. And energy is generally only about half of the entire electricity bill, the remainder being transmission, distribution, and customer administration costs. It still amounted to hundreds of millions of dollars in California, but it wasn't going to fundamentally change the cost of supplying electricity. The reason for this is worth highlighting: in an electric system that must always stand ready to meet all demand at the retail price, the cost of a constant-price structure is the need to hold substantial capacity that is hardly ever used. But utilities optimize by building "peaker plants" for this purpose, capacity that has low capital cost and high operating cost. The social cost of holding idle capacity of this form turns out to be not as great as one might think.
This is particularly the case in Ontario, as it acts to phase out coal, and increase wind supply, TOU fits into the puzzle only to complete the farce.  The cost of Ontario’s ‘capacity that is hardly ever used’ is particularly low – we own it already.   Last year our provincially owned coal units produced an average of 1119MW each hour, with a capacity of about 6000MW.  That is a low capacity factor.  It is not economical to build combined cycle power plants (CCPP) to run at such low capacity factors (CCPP plants average over 40% capacity factors in the USA).  The government doesn’t release the contracts for the recently procured private gas generation supply, but it is not only costing us heavily, we are likely producing more emissions because we are contracted to take production the economic decline means we don’t need.  The more economical natural gas replacement for coal would therefore by simple cycle (SCGT) – but that is minimally cleaner than coal, and it isn’t even determined it is cleaner as a continuously available peaking source awaiting the wind speed change.   I’ll treat wind as a separate topic from TOU.

But wind is extraordinarily relevant to the more efficient, in a market sense, real-time pricing (RTP) concept. The strength of the wind will increasingly impact the market price of power.

Another issue for RTP is pricing spikes can have more to do with supply issues than with demand issues.  This is actually one reason RTP is a more efficient price mechanism – it can send an escalating price signal in a sudden supply shortage.  Last week’s market price spikes in Alberta and Texas had both weather, and supply, causes.  All these RTP issues are, theoretically, part of any economic challenge.  Energy, like food, clouds our judgment into forgetting protectionism is less efficient (the only real cause of Texas’ blackout was grid connectivity with adjacent jurisdictions), as is subsidizing production and dumping exports (as Ontario has been doing for years now).  

If we want ‘real’ costs, we need a ‘real’ market.   


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