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.

Utility 2.0 or Just Utility 1.X

On Tuesday, 2013 October 29, I attended a discussion of the report “Utility 2.0: Building the Next-Gen Electric Grid through Innovation.”  I left feeling that the innovations discussed are just more of the same, just as I have often described the smartgrid as SCADA[1] on steroids.  The innovations are not creating Utility 2.0 as much as making slow changes to the existing utility structure, just varying the X in Utility 1.X.

Electric utilities began automating the electric system as soon as Edison started his first microgrid, the Pearl Street Station.  At one time, an operator would read a frequency meter to determine the balance between supply and demand.  In the earliest days, Edison had a panel of light bulbs that would be switched on and off to maintain that balance, which was a strange form of load management.  The operator would also be able to vary the generation by change the water flow to a hydro-turbine, the steam from the boiler, and the fuel into the boiler.  Edison invented control mechanisms that were cheaper than the labor costs of the operator, control mechanisms that his companies also sold to other utilities.  These control mechanisms can be considered to be some of the first SCADA systems.  As the control mechanisms and telephony got cheaper and labor become more expensive, more labor saving devices could be installed.  The policy of having an operator at every substation was replaced by remote devices, lowering the cost of utility service.  The smartgrid concept is just more of the same, as computers become cheaper and faster, remote metering less expensive, and remote control easier to accomplish.

The true quantum change in utility operations occurred in federal law.  PUHCA[2] effectively prohibited private individuals from selling electricity to a utility, by defining the seller to be a utility, subject to utility type regulation and to prohibitions on non-utility operations.  Because of PUHCA, Dow Chemical operated its chemical plants as the ultimate microgrid, running asynchronously and unconnected to local utilities.  Dupont installed disconnect switches that would separate its microgrid chemical plant from the local utility if power began to flow out of the plant.  International Power and Paper became International Paper.  Exxon intentionally underinvested in its steam plants, limiting its ability to produce low cost electricity.  PURPA[3] provided exemptions from PUHCA for cogeneration plants such as those mentioned here and for qualifying small producers using renewable resources.  The latter exemption was almost in anticipation to the growth of roof top solar photovoltaics (PV).  These facilities needed utility markets into which to sell their surplus, which generally resulted in individually negotiated contracts.  The creation of the ISO[4] concept could be considered to be an outgrowth of the desire by these large independent power producers (IPPs) for a broader, more competitive market, instead of the monopsony into which they had been selling.  ISOs now have a footprint covering about 2/3 of the lower US, excluding Alaska and Hawaii.

ISOs generally deal only with larger blocks of power, some requiring participants to aggregate at least 25 MW of generation or load.  ISO control generally does not reach down into the distribution system.  The continued growth of labor costs and the continued decline of automation costs has allowed the SCADA concept to be economic on the distribution grid, including down to the customer level.  This expansion of SCADA to the distribution system will soon require changes in the way the distribution system is priced, both for purposes of equity and for Edison’s purpose of controlling the system.

  • The growth in rooftop PV is dramatically reducing the energy that utilities transport across their distribution system.  This energy reduction generally reduces utility revenue and utility income.  Under conventional utility rate making, the result is an increase in the unit price charged by the utility for that service.  Some pundits point out that the owners of the rooftop PV panels are generally richer than the rest of the population served by the utility.  These solar customers are cutting the energy they consumer, though not necessarily their requirements on the utility to provide some service through the same wires.  The rate making dynamics thus result in other, poorer customers seemingly subsidizing the richer customers who have made the choice for rooftop solar.  This seems inequitable to some.
  • The growth in rooftop PV has outstripped the loads on some distribution feeders, with reports that the generation capacity has sometimes reached three times the load on the feeder.  These loading levels cause operating problems in the form of high voltages and excessive line losses.  During periods of high voltage and excessive line loss, prices can provide an incentive for consumers to modify their behavior.  The genie seems to be out of the bottle in regard to allowing the utility to exert direct physical control over PV solar, but real time prices could provide some economic control in place of the tradition utility command and control approach.

I have discussed the need for real time pricing of the use of the distribution grid in “Net Metering:  Identifying The Hidden Costs;  Then Paying For Them,” Energy Central, 2013September 20.[5] I have described a method in “Dynamic ‘Distribution’ Grid Pricing.”[6]

Changes in state regulations have also impacted this balance between labor costs and automation costs.  Some states now have performance incentives based on the number of outages and the typical restoration times.  The cost associated with the time of sending a line crew to close a circuit breaker now competes with the incentives to get that closure faster, through the use of automation.

In conclusion, the increase in utility automation is not so much innovation as it is a continuation of the historic utility practice of the economic substitution of lower cost technology for the ever increasing cost of labor.  The 1978 change in federal law led to the growth of ISOs and bulk power markets, but did not reach down to the distribution level, perhaps of the lack of non-utility industrial support.  The growth in rooftop PV will provide the incentives for expanding the real time markets down the distribution grid to retail consumers.  Though computers indeed have gone from 1.0 (vacuum tubes), to 2.0 (transistors), to 3.0 (integrated circuits), I don’t see the current changes proposed for utilities to be much more than following the competition between labor costs and automation costs.  We are still Utility 1.X, not Utility 2.0.



[1] Supervisory Control And Data Acquisition.

[2] Public Utility Holding Company Act of 1935

[3] Public Utility Regulatory Policies Act of 1978

[4] Independent System Operator

[6] A draft of this paper is available for free download on my web page, www.LivelyUtility.com

Electricity Pricing—Fair Trade vs. Free Trade—Which is High/Lower

When I got married in 2004, my wife introduced me to the term “Fair Trade” as in fair trade coffee, where coffee growers are paid a price that allows a “living wage” to be paid to the workers on the coffee plantation where the coffee beans were grown.  I quickly realized that Fair Trade could be used to describe the standard regulated electricity market, including a fair rate of return to the investors.  In contrast, the term Free Trade could be used to describe a competitive market, such as the ones then being developed by Independent System Operators (ISOs).  Free Trade could also be used to describe the bulk power markets between large vertically integrated electric utilities, such as when my former employer American Electric Power (AEP) sold electricity to other utilities, whether Commonwealth Edison to its northwest or TVA to its south.  However, both these Free Trade examples have some aspects of Fair Trade, as has been shown by regulators intervening in the Free Trade markets when prices have appeared to be excessive, such as the imposition of caps on the ISO markets.

 

In 1978, the Federal government implemented a mixed form of Fair Trade/Free Trade for Qualifying Facilities, requiring many utilities to buy electricity at Avoided Cost under the Public Utilities Regulatory Policy Act (PURPA).  In 1984, Ernst & Whinney, my employer at the time, won a contract with the Texas Study Group on Cogeneration to investigate the way Houston Lighting & Power (HL&P) was paying (or not paying) cogenerators for the electricity that was being produced.  I invented the Committed Unit Basis[1] (CUB) for evaluating long term contracts under which utilities bought power from cogenerators.  CUB was adopted by name by the Texas Public Utilities Commission in its regulations and was used to determine the reasonableness of three large cogeneration contracts that HL&P signed over the next year.

 

CUB develops an inflation adjusted annual revenue requirement for the next generating unit that the utility would build were it not for the presence of the cogeneration plant.  The inflation adjustment results in economic depreciation rates, which could be negative in the first few years of the model.  Thus, not only did CUB reduce the first year payment to a levelized rate below the standard utility model for the revenue requirement, but the first year payment was below even that levelized rate.  The payment escalated with inflation over the life of the contract.

 

I saw HL&P sign three major contracts in 1984/5 based on CUB.  My analysis suggested that the second and third contracts were for rates that were successively lower than the first contract.  Some suggested that the lower rates reflected the loosening of the market for electricity.  The first contract reflected the full value identified by CUB, while the subsequent markets reflected competition, effectively going from a Fair Trade price to a Free Trade price.  When I subsequently addressed the concept of a competitive market for unscheduled flows of electricity, I concluded that sometimes the Free Trade price needed to be above the Fair Trade price, not always below the Fair Trade price.  This concern was included in the name of my model for a competitive market for electricity, WOLF, or Wide Open Load Following.

 

The Free Trade/Fair Trade issue comes up most starkly in the discussion of dispatchability, an issue that dramatically affects wind and solar generation.  They are not dispatchable and many argue that they should be paid a price that is lower than the price paid to dispatchable generators, such as gas turbines.  This lower price would be paid to any “as available” wind and solar (as well as many other forms of QF power, such as surplus cogeneration).  But sometimes, the “as available” power happens to occur when it is needed.  Should “as available, as needed” power always be paid a lower price than dispatchable power?  Should there be a way for “as available, as needed” power be made whole relative to the lower prices that they are paid during many of the hours when dispatchability is important?  How can that be done?

 

WOLF provides a price adjustment to reflect the concurrent need for power.  When load outstrips supply, the price follows the load upward above the standard price for scheduled power.  Conversely, when load is much below supply, the price follows the load downward below the standard price for scheduled power.  For electricity, the standard measure for whether load and supply are in balance on a utility is Area Control Error.  When the utility is synonymous with the entire grid, the standard measure for whether the load and supply are in balancer is frequency error.  Since both ACE and frequency error can be positive or negative, the price adjustment can serve to raise or to lower the settlement price relative to the standard price.

 

There are times when dispatchable generators fail to meet their obligations and the utility is able to meet its load because of the availability of non-dispatchable generators.  During such times, the value of the non-dispatchable generation is equal to the value of the dispatchable generators, perhaps even more valuable.  WOLF provides a way to set a price based on the value of “as available, as needed” generation.  When there is a shortage, the Free Trade price for “as available, as needed” generation should even exceed the Fair Trade price for dispatchable generation.



[1] Recently I googled “Committed Unit Basis” and had ten hits, including a paper written in Portuguese by Brazilian authors, but I had include the quotation marks to reduce the hits down to ten.

Solar PV might be sufficient but needs storage and agnostic pricing

It has been said that the US Department of Energy is supposed to be technologically neutral.  Many people say that DOE isn’t technologically neutral, but let’s build on the concept anyway.

We should have imbalance prices that are technologically neutral.  If I pump more solar PV into the grid than I have under contract, I will want to get paid for that surplus.  That surplus will be absorbed by someone with a shortage, who should pay for absorbing that surplus.  Given that there are hundreds, or thousands, or tens of thousands, or even millions (think of the number of solar roof tops) of parties participating in this balancing act of surpluses and shortages, the real time balancing price needs to be uniform (except for geographic differentiation.)

We could price my solar PV surplus differently from a simultaneous coal surplus, or from a simultaneous solar PV shortage, or from every other surplus or shortage, but that would be an accounting nightmare.

One way to handle the shortages and surpluses is with storage.  The uniform simultaneous price concept would be a way for storage to be compensated for its actions, buying the surpluses when the price is low and selling the shortages when prices are high.  This pricing concept should also be technologically neutral with regard to the form of storage, whether the lead acid or lithium ion batteries discussed by others or thermal storage that would fully handle the surpluses and only indirectly handle the shortages by turning of the charging power.