Pricing Gasoline When the Pumps Are Running on Backup Electricity Supply

I attended the MIT Club of Washington Seminar Series dinner on Tuesday, 2014 February 11, which this year is on the topic of “Modernizing the U.S. Electric Grid,” listening to Michael Chertoff talk on “The Vulnerability of the U.S. Grid.”

Chertoff’s maguffin was a story about a hurricane hitting Miami in about 2005.  Electrical workers couldn’t get to work because they had no gasoline for their cars.  The gas stations had gasoline but no electricity to pump the gasoline.  Back-up electricity generators would have required an investment of $50,000 which was not justified on the razor thin margins on which most gas stations operate.

The gas station owners thought process was that the sales lost during the blackout would just be gasoline that would be sold after the power came back on.  Investment in a back-up generator would not change the station’s revenue and would just hurt its profitability.  My first comment during Q&A was that the same issues were raised after Hurricane Sandy[1] in the New York City area in 2012, and perhaps in many other areas that experience wide spread storm damage.

After the dinner I talked with Matthew, a friend from ExxonMobil who had learned about the Seminar Series from my advertizing it to people who attend events of the National Capital Area Chapter of the U.S. Association for Energy Economics.  Because of that linkage, he makes a point to search me out at each Seminar Series dinner.  Our after dinner discussion focused on how to make the $50,000 investment in a back-up generator profitable to the gas station owner.

Matthew said that many gas station permits including anti-gouging provisions, preventing the gas station owner from increasing the price during emergencies.  My thought was that the investment in back-up power supplies would mean that a temporary price increase could be justified to pay for such an investment.  After all, bulk electricity prices in Pennsylvania on the PJM grid during the cold snap associated with the 2014 January arctic vortex soared to $1,839.28/MWH ($1.84/KWH) from an average of only $33.06/MWH during 2012.  This was a temporary 55 fold (not 55%) change in the base price of electricity.[2]

I believe that prices are sticky.  Once set, prices tend to stay unchanged for significant periods of time.  The independent system operators (ISOs such as PJM) get around some of this stickiness by having elaborate models for setting prices every hour, with the basic mechanism setting a value every five minutes and then averaging those five minute values over an hour to get a price.  The basic mechanism includes (1) bids by suppliers as to the price they want if they are to provide specified amounts of electricity and (2) estimates of the demands that will occur each hour or that are occurring on a real time each five minutes.

Almost 25 years ago, long before the advent of ISOs, I published my first article[3] on using the measured real time imbalance between supply and demand to set the real time price for unscheduled flows of electricity.  Using the measured imbalance eliminated the need for bidding processes, bidding process that can lead to stickiness.  I proposed using the concurrent system frequency for setting the price, calling the concept Wide Open Load Following (WOLF).

For electricity, a surplus of demand will drag down system frequency, which I say warrants a higher price, at least higher than the nominal price.  A surplus of supply will push up system frequency, which I say warrants a lower price, at least lower than the nominal price.  Over longer intervals, imbalances will change the accuracy of wall clocks that use system frequency to determine the correct time.  Thus, WOLF includes the concept of time error in setting the nominal price for electricity imbalances.  The WOLF concept could similarly be used to set prices within each of the five minutes of an ISO dispatch period, or even on a sub-minute basis, modifying the ISO’s sticky five minute nominal dispatch value.

The State of California has variable pricing for its State Route 91 Express Lanes under the rubric of congestion management.

“On July 14, 2003, OCTA adopted a toll policy for the 91 Express Lanes based on the concept of congestion management pricing. The policy is designed to optimize 91 Express Lanes traffic flow at free-flow speeds. To accomplish this OCTA monitors hourly traffic volumes. Tolls are adjusted when traffic volumes consistently reach a trigger point where traffic flow can become unstable. These are known as “super peak” hours. Given the capacity constraints during these hours, pricing is used to manage demand. Once an hourly toll is adjusted, it is frozen for six months. This approach balances traffic engineering with good public policy. Other (non-super peak) toll prices are adjusted annually by inflation.

“Recent customer surveys indicate that 91 Express Lanes users lead busy lives with many hours dedicated to commuting to and from their jobs. About 85 percent of customers are married, with more than half raising children. Many customers choose the toll road only on days they need it most, joining general freeway lane commuters on other days. Customers emphasize they value a fast, safe, reliable commute and the toll policy strategy is designed to support this value.

“The toll policy goals are to:

  • Provide customers a safe, reliable, predictable commute.
  • Optimize throughput at free-flow speeds.
  • Increase average vehicle occupancy.
  • Balance capacity and demand, thereby serving both full-pay customers and carpoolers with three or more people who are offered discounted tolls.
  • Generate sufficient revenue to sustain the financial viability of the 91 Express Lanes.

“The effect of the toll policy has been an increase in customer usage with sufficient revenue to pay all expenses and also provide seed funding for general freeway improvements. Revenues generated by the toll lanes stay on the SR-91 corridor, a significant departure from past practices. Under the previous owner’s agreement with Caltrans, a “non-compete” provision restricted adding more capacity to the SR-91 corridor until 2030. When OCTA purchased the lanes, it opened the door for new improvements on SR-91 by eliminating the non-compete provision.[4]

The free flowing capacity of the 91 Express Lanes is 3400 cars per hour.  When average hourly volume exceeds 3200 cars per hour (about 94.1% of the free flowing capacity), the price increases by $0.75 at the beginning of the next six months.  When average hourly volume exceeds 3300 cars per hour (about 97.1% of the free flowing capacity), the price increases by $1.00 at the beginning of the next six months.  When average hourly volume is less than 2720 cars per hour (80% of the free flowing capacity), the price decreases by $0.50 at the beginning of the next six months.  The flow analysis is done for each hour of the week, producing 168 distinct prices each way on the 91 Express Lanes, that is, for 24×7 distinct hours each way.  But as of 2013 July 1, about 1/3 of the hours are charged the minimum price, that is, they are not considered to be super peak hours.   The flow analysis also is separately done for holidays, nominally as minor as Mother’s Day.

The 91 Express Lanes toll mechanism shows that some jurisdictions, including the notoriously protectionist State of California, allow incentive pricing for congestion management during critical periods, such as a wide spread blackout.  The 91 Express Lanes toll mechanism also provides a mechanism for automatic adjustment of the  price.  The 91 Express Lanes toll mechanism uses explicit measurements of the balance between supply and demand, much like the WOLF mechanism for electricity imbalances.  The 91 Express Lanes measurement is the fraction of the capacity of the 91 Express Lanes, changing the price when the hourly utilization is outside the band of 80.0% to 94.1%.

Based on a review of the 91 Express Lanes toll mechanism, there is some hope that gas stations will be able to afford the major investment in backup electrical supplies.  For gas stations, the measure of the imbalance between supply and demand can be as simple as the length of the line of cars waiting for gas or as complex as including the gasoline inventory compared to the desired level and the estimated time before the inventory is extinguished.



[1] Presentation of Adam Sieminski, Administrator of the U.S. Energy Information Administration at the 2012 October 19 lunch of the National Capital Area Chapter of the U.S. Association for Energy Economics (NCAC-USAEE.org).  Pursuant to its charter as an information agency, EIA created for Hurricane Sandy a real time display of gas stations with internet connectivity, a nominal measure of whether the gas station had electricity.

[2] PJM differentiates prices geographically.  Thus, one local price increased to $2,321.24/MWH and another fell to a negative $391.14/MWH because of transmission constraints.

[3] “Tie Riding Freeloaders–The True Impediment to Transmission Access,” Public Utilities Fortnightly, 1989 December 21.

[4] https://www.91expresslanes.com/policies.asp

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.