Risks of Going Solar

On February 22, 2016, Catherine Wolfram posted the blog Risks of Going Solar on the Energy Institute at Haas blog, part of the University of California Berkeley.  I posted the following, which I am adding to my blog.

Of the various regulatory Risks of Going Solar, Catherine Wolfram identifies two biggies, reducing the size of the net metering interval and shifting the rate design to include a smaller energy charge and a greater fixed charge.  But the risk of these two can be much larger than Dr. Wolfram suggests.  Reducing the size of the net metering interval exposes rooftop solar customers to the possibility of negative prices, while cost re-classification could result in (greater) demand charges instead of greater monthly customer charges.

In “Renewable Electric Power—Too Much of a Good Thing: Looking At ERCOT,” Dialogue, United States Association for Energy Economics, 2009 August,[1] I point out that a surplus of wind in West Texas forced the wholesale price for electricity below zero for about 25% of the pricing periods during that April, at least in West Texas.

Transmission constraints generally kept these negative prices from spreading to the rest of Texas.  Negative prices did spread to other parts of the state for just less than 1% of the rating periods.  As Dr. Wolfram well pointed out, these pricing periods are sometimes as short as 15 minutes (as they were in West Texas at the time), though are often one hour.

Many ISO do not seem to allow prices to go negative.  In West Texas, the combination of transmission constraints and the various credits[2] given to wind led to negative prices.  I believe that similar combinations elsewhere will force ISOs to allow negative prices in their dispatch programs.

I have long seen the need for utilities outside the footprint of an ISO to implement real time “value of solar” prices that are similarly negative.  Hawaii seems to be ripe for such negative solar prices.  Utilities outside the footprint of an ISO can implement “value of solar” prices using a Walrasian auction, as is discussed in many of my articles.

I actually disagree with the concept of a separate price for “value of solar.”  If we are to use prices to influence generation, there shouldn’t be a separate price for solar versus other spot generation imbalances.  A different price for unscheduled versus scheduled generation, yes, but not a separate price for just solar.

There will often be many prices during any pricing interval.  For instance, a single 15 minute period may be part of a 24×7 contracted delivery of power with one price and part of a 16×5 contracted deliveries with another price.  A third price might be applicable to variances.  Variances would include both solar that is dumped into the system and hiccups in the 24×7 or 16×5 deliveries, whether the hiccup is positive or negative.

Utility rate making often includes the concept of cost classification, where costs are identified as energy related, customer related, and demand related.  In the context of Risks of Going Solar, customer related and demand related are combined into the concept of a fixed charge.

The discussed increase in the monthly charge is only one way to reduce the energy charge.  The other way, and I believe a better way, to decrease the energy charge is to increase the demand charge, or to implement a demand charge when there is not a demand charge in place.

Customer charges impose greater burdens on small, often lower income, residential customers, while demand charges tend to protect these smaller customers, as is discussed in

  • “Curing the Death Spiral,” with Lori Cifuentes (Tampa Electric Company), Public Utilities Fortnightly, 2014 August;[3]
  • “Demand a Better Utility Charge During Era of Renewables: Getting Renewable Incentives Correct With Residential Demand Charges,” Dialogue, United States Association for Energy Economics, 2015 January;[4] and,
  • “Fairly Pricing Net Intervals While Keeping The Utility Financially Healthy,” 48th Annual Frontiers of Power Conference, cosponsored by The Engineering Energy Laboratory and The School of Electrical and Computer Engineering, Oklahoma State University, Stillwater, Oklahoma, 2015 October 26-27.[5]

Thus, as we see a continued growth in solar, I see a growing need for finer pricing intervals and a growing need for demand charges.  Fortunately, the huge growth in interval meters allow these better rate designs.  We just need to political will to implement something other than a monthly charge for energy.

[1] http://livelyutility.com/documents/USAEE-ERCOT%20Aug%2009.pdf

[2] such as production tax credits and renewable energy credits

[3] https://www.fortnightly.com/fortnightly/2014/08/curing-death-spiral?authkey=54d8da5efd3f76661023d122f3e538b4b3db8c8d5bf97a65bc58a3dd55bb8672

[4] http://dialog.usaee.org/index.php/volume-23-number-1-2015/271-lively

[5] A copy is available on my website, www.LivelyUtility.com.

Billing Tweaks Don’t Make Net Metering Good Policy

Severin Borenstein published a blog on 2016 January 4 with the title of “Billing Tweaks Don’t Make Net Metering Good Policy.”  The entry reminded me of a presentation I had made in October at Oklahoma State, so I added the following comment to Severin’s Haas Blog.

Net Metering can be Good Policy for the recovery of some costs incurred by a utility in serving its customers, such as the cost billed to it by its ISO supplier.  But for the rest of the costs incurred by the utility, such as the cost of wires and meters, a demand charge and a monthly customer charge are more appropriate.

For the cost billed by the ISO supplier, the metering periods need to be aligned, an issue that is current before FERC in Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission Organizations and Independent System Operators, FERC Docket No. RM15-24-000.  If the ISO is billing the utility based on fifteen minute intervals, it might be good policy for the utility to bill the retail consumer for those ISO costs on fifteen minute intervals using net metered amounts during those fifteen minute intervals.

This net metering paradigm seems to be only appropriate for the charges coming to the utility from the ISO, as I discussed in “Fairly Pricing Net Intervals While Keeping The Utility Financially Healthy,” 48th Annual Frontiers of Power Conference, cosponsored by The Engineering Energy Laboratory and The School of Electrical and Computer Engineering, Oklahoma State University, Stillwater, Oklahoma, 2015 October 26-27.  A shorter version of this paper was published in Dialogue, United States Association for Energy Economics, 2015 September 1.  The full paper is on my web site  in the library under Conference Papers.

The majority of the cost incurred by an increasing number of utilities are incurred for wires.  A much better way to recover the cost of wires is a demand charge.  When the customer wants to have access to a specific amount of power, the customer can contract for wires access in that amount, which would be billed monthly based on contract demand.  Customers with poorer information about their power requirements can rely on a demand charge based on the interval with the highest net metered amount, generally fifteen minutes or an hour, though I have seen the interval being an entire summer month.  Customers who exceed their contract demand would pay for the excess demand through a multiple of the demand charge.

There are a few appropriate demand metrics, such as the customer maximum demand or more exotic demands such as the contribution to the distribution system peak or the peak on a subsection of the distribution system, all as discussed in the above paper.  We are still several years away from real time pricing of the distribution system, as I discussed in “Dynamic Pricing: Using Smart Meters to Solve Electric Vehicles Related Distribution Overloads,” Metering International, Issue 3, 2010.

The Goldilocks Dilemma

An old posting about why intermittency is not a big deal came to my attention today.  I re-read some of what had been said, especially when I had just sent out a paper on the topic yesterday.

I believe that the value of electric “energy” is often overstated.  The author of the old posting, Chris Varrone, inadvertently acknowledges this when he wrote

However, the energy in wind is worth 100% of the energy in nuclear (or anything else) in the spot market; wind energy in the day-ahead market may be worth a little less, but this can be “firmed” using energy trading desks or by using other assets in the operator’s fleet.

If the day to day differential can be handled by firming with other assets, then the value of the electricity is not just energy.  It is not worth debating what to call this other value, but a substantial part of the value in the spot market is something other than energy.

As to The Goldilocks Dilemma, the paper I sent out yesterday, I began by asking

Is the price paid to dispatchable generation too high, too low, or just right for intermittent generation?

I then answer

Though intermittent generators often argue that they should receive the same price as dispatchable generation and some utilities argue that they should pay less to intermittent generators, sometimes intermittent generators should face a higher price than dispatchable generators, such as when intermittent generation is part of the market during instances of extreme shortage.

The entire paper is available on my web site, the companion to this blog site.  Look for the hot link to the library near the bottom of the first page.  A hot link for the article is near the bottom of library index in the section called drafts.

Electricity Crisis in Japan—California 2000/2001 deja vu

About three weeks ago Japan was severely ravaged by an earthquake.  From half the world away, it seemed as if what the earthquake didn’t devastate, the ensuing tsunami did.  In addition to the immediate damage, the long term suffering has been made worse by inadequate supplies of electricity, so inadequate that there are reports of rotating blackouts.  Some friends whose son lives near Tokyo worry about him being stuck in the subway if a rotating blackout hits the subway.

Economists say that the best way to ration a commodity when there is a shortage is through price.  Of course, economists deal with prices, so it is expected that an economist would suggest prices.  The economists view on economic rationing reminds me of the concept that if the only tool in your toolbox is a hammer then everything looks like a nail.

But I question whether there should be a shortage.  When California was experiencing a shortage of electricity and introduced rotating blackouts, a friend provided me data on backup generators in the Western US.  My analysis appeared in “Saving California With Distributed Generation: A Crash Program To Use Small, Standby Diesel Generators To Keep The Lights On,” Public Utilities Fortnightly, 2001 June 15.  California’s backup generating capacity was about 80% of its peak load.  I suspect that Japan has a comparable amount of backup generation, perhaps more because of Japan’s greater history of earthquakes.

But getting backup generators to operate is problematic.  First, they are notoriously inefficient and burn premium fuels.  Thus, the fuel cost alone from a backup generator is likely to be 3-10 times the fuel cost of the best central station power plant.  But, if you want to avoid blackouts, connecting thousands of backup generators to the grid will help.  Further, since the backup generators are distributed around the country, their operation will reduce electrical losses on the grid though not by enough to pay for the higher fuel cost.

India has implemented a pricing plan that could be used for the purpose of paying backup generators.  India’s Availability Based Tariff (ABT) has a pricing component for unscheduled interchange (UI).  The price for UI changes every 15 minutes, indexed on system frequency.  When frequency is low, the price is high.  When frequency is high the price is low.  UI pricing would be ideal for paying backup generators who are connected to the grid.

The physics of electricity results in a uniform frequency within a grid, uniform across geographic areas at any instant, but changing instant by instant as the balance between supply and demand changes.  A shortage will push system frequency down, as system operators are contemplating rotating blackouts.  Backup generators operating in parallel with the system will help hold the frequency up, at least if enough backup generators are operating.  The data from California suggest that Japan is likely to have enough backup generators.  The uncertainty relates to Japan’s willingness to pay these generators enough money to get them to generate.

The dynamic ABT price is for UI.  But it can also be used to price retail customers who have been requested to curtail consumption, at least for the amount by which the retail customer has not achieved the requested curtailment.  At the same time, the ABT price can be paid to retail customers who have surpassed the curtailment request.  This concept will require some improved metering or serendipitous use of distribution station metering and load profiles.  Perhaps I will write more on that later.