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.

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.

Electric Demand Charges: A Lesson from the Telephone Industry

The only ad with prices that I remember from 50 years ago was AT&T’s offering of a three minute coast to coast telephone call for $1.00.  With the inflation that we have seen over the last 50 years, one would expect that a coast to coast call would now be at least $10.00 for three minutes.  Instead, most telephone bills show a monthly service fee and no itemization for individual calls.  Automation has allowed the telephone companies to do away with most telephone operators, which was a significant portion of the variable cost of making long distance telephone calls.  The principal cost is now the investment in the wires, which doesn’t change with the number of calls that are carried.  So, most carriers now charge a monthly fee and little or no charge per call.  Perhaps it is time for the electric industry to go that way?

 

The restructuring of the electric industry has generally separated the distribution wires function from the generation[1] and transmission[2] function for most customers of investor owned electric utilities.  This restructuring puts such electricity customers into the same position as their counterpart customers of municipally and cooperatively owned utilities.  Municipally and cooperative owned utilities have generally been distribution only utilities, buying generation and transmission services from others, instead of being vertically integrated like most investor owned electric utilities.

 

The restructuring of the electric industry has resulted in most customers being served by a distribution company which has very little variable cost, much like the telephone companies.   A significant distinction is that telephone lines handle one call at a time.  The telephone line is either in use or is not in use.  In contrast, electric utilities provide a continuously variable service.  The customer may be taking 10 watts (a small light bulb) or 10 kilowatts (running the A/C, water heater, and stove at the same time), or any amount in between.  The telephone company has the wires to serve the customer’s demand, whenever that call occurs[3].  The electric distribution company similarly has the wires to serve the customer’s demand, whenever that demand occurs.  While the telephone company will have customers on a binary basis (they are either a customer or are not a customer), the electric distribution customer serves its customers on a continuous basis (they might be very small customers who never use more than 10 watts or a very large customer that might use up to 100 MW.)

 

The binary basis of telephony customers allows the telephone companies to charge their customers a specific amount on a monthly.  The continuous nature of the size of electric services suggests that electric distribution companies charge their customers a price based on the size of the electric service used by the customer.  For commercial and industrial customers, electric utilities have long included in their tariffs a demand charge that depends on the maximum power that the customer used during the billing period[4].  Typically such demand charges will be based on the average consumption for some 15 minute period.

 

Cost has been a significant factor that limited the use of demand charges to commercial and industrial customers.  Demand meters are more costly to manufacture, in that they do more than just accumulate the amount of energy that goes through the meter.  Demand meters are more expensive to read, in that the meter reader has to note two quantities and has to manually reset the demand register.  These two cost factors are lesser issues in regard to determining residential demand now that the industry has moved significantly to Advanced Meter Reading (AMR) and to Advanced Meter Infrastructure (AMI[5]), both of which automatically collect consumption data, including for 15 minute intervals.

 

Historically residential demand charges was thought to produce an insignificant shift of revenue among residential customers.  The reasoning was that, though residential customers are different in size, they have a similar load pattern.  A customer using 1,000 KWH a month would have ten times the demand as a customer using 100 KWH a month.  Implementing a demand charge that collected an amount equal to 20% of the energy revenue collected from the larger customer would also collect an amount equal to 20% of the energy revenue collected from the smaller customer.  There would be no revenue shift among these residential customer, at least for consumption.  However, the utility would have had to install more expensive meters, which would have increased the monthly customer charge of both customers without providing a significant benefit to the utility or to the customers.

 

The move to AMR and AMI has reduced the cost of determining the demand for residential customers.  Now the cost of determining metered demand is not an issue in differentiating between customers with different consumption patterns.  Customers who should be paying a demand charge equal to 30% of their energy payments can be distinguished from customers who should be paying a demand charge that is only 10% of their energy payments.  Further, on site generation has changed the paradigm that residential customers have similar load patterns, so that now the industry knows that there are the 30% customers versus the 10% customers and can bill them appropriately.  Indeed, for houses with sufficient on-site generation, the revenue from the demand charge could be several times the revenue from the energy charge, especially when the energy charge vanishes for a net zero home.

The growth in AMR and AMI along with the growth in residential on-site generation makes this an appropriate time for restructuring residential tariffs to include a demand charge to collect the cost of the distribution utility owning the power lines.  The energy charge should continue to collect the cost of generation and transmission, though the energy charge should be time differentiated to reflect the real time value of generation and transmission, as well as the associated energy losses.



[1] The creation of Independent System Operators (ISOs) is alleged to have brought competition to the generation sector of the electric industry.  However, many distributed generators, such as roof top solar, do not experience the real time market prices set by their local ISO.  This distorts the market for distributed generation.

[2] The creation of ISOs is also alleged to have brought competition to the transmission market.  But ISOs compensate many transmission lines on a cost of service basis, through a monthly fee, though they charge geographically differentiated prices based on line losses and line congestion and generally don’t compensate for loop flow or parallel path flows, such as PJM imposes on TVA and on the Southern Company, both of which have lines in parallel to PJM>

[3] Telephone customers occasionally receive a business signal, indicating that the called party is using his/her phone.  More rarely, customers will receive a circuits business signal, indicating that intermediate wires are in full use, not that the called party is using his/her phone.

[4] Demand charges come in a variety of forms including contract demand, thermal demand, and ratcheted demands, a distinction beyond the scope of this discussion.

[5] AMI is generally distinguished from AMR in that AMI generally includes the ability to communicate both ways, from the meter to the utility and from the utility to the meter/customer location.  The ability to communicate from the utility to the meter allows the utility to control devices that the customer has opted to put under the utility’s control such as electric water heaters, air conditioning compressors, and swimming pool pumps and heaters.