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 (  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.


A Romp Through Restructuring

Today I presided over the monthly lunch of the National Capital Area Chapter (NCAC) of the U.S. Association for Energy Economics, with Craig Glazer, Vice President-Federal Government Policy, PJM Interconnection.  Besides announcing future events and talking about the successful NCAC field trip of October 4-5[1], I got to ask questions and comment as the luncheon moderator and President of NCAC.  I include some of those questions and comments below, along with several that where beyond what I felt like imposing on the luncheon attendees.

I liked that Craig mentioned that code words were often used in the industry, though not the ones I sometimes point out.  But when one questioner commented about the growth in distributed generation (DG), I pointed out that I look at DG as a code word for non-utility generation.  Nominally DG should be any generation on the distribution grid, but is generally used to restrict the ownership options.

Craig identified “Rates significantly above the national average” as one of the issues that drove the restructuring movement.  Unlike the children of Lake Woebegone where children are all above average, retail rates can’t be above the national average everywhere.  Thus, there are some parts of the country where restructuring was not an issue and the utilities have not been restructured.

Craig used the term “Half Slave/Half Free” to address the case of Virginia, where the State Corporation Commission still regulates retail rates but the generation and transmission systems participate in the competitive PJM market.  I noted that the result of restructuring was that the market value of electricity in my home location of Eastern Kentucky went from very low prices to moderately low prices, at least according to one of Craig’s slides.  But Craig had already made me feel better about this by telling of his trips to Kentucky to persuade the regulators to let their utilities join PJM.  He told them that one result the Kentucky electric companies joining PJM would be higher utilization of Kentucky’s cheap power plants.

These power plants joining PJM could sell the very low cost generation (the pre-restructuring picture) at moderately low prices (the post-restructuring picture), with the differential being used to reduce the prices for Kentucky residents.  As I pointed out, this is an example of Craig’s term “Half Slave/Half Free” where he pushed the concept.  I also pointed out that a substantial portion of the country has not restructured, which was my initial thought when he mentioned the term.  So we went back to the issue that not all parts of the country would benefit from restructuring.

Craig stated that restructuring changed the risk allocation formula.  He made the point that there was no Enron rate case.  In other situations where utility investments were cratering, there were rate cases, but not with Enron in the restructured world.  Further, there was effectively not even a hiccup in the PJM bulk power market on the day that Enron collapsed, even though Enron had been a major player in the PJM bulk power market.

Craig says that capacity prices are too low.  I see capacity as being a multi-year issue, requiring a multi-year solution.  Pre-restructuring, the utilities handled the variations in the need for capacity, and the value of capacity, through long term rates.  They built what they thought was needed and didn’t worry that the bulk power market went up and down, the utilities kept on trucking as vertically integrated entities.  Indeed, one of the problems that caused the California debacle of 2000/2001 was that the entire market was forced to pay the spot price of electricity.  The Texas market seems to be greatly hedged in that when the bulk power market price went up by a factor of 10, on average, for the entire month of August 2011, the retail price hardly budged.

Craig made an excellent point in regard to the question of who decides what in the electric industry, providing a list of governmental entities.  I notice that he did not mention the U.S. Department of Energy (of course he was a substitute speaker who replaced Melanie Kenderdine, assistant to the Secretary of the U.S. Department of Energy, because Melanie thought she would not be allowed to speak because of the shutdown of the federal government that ended about 24 hours before the lunch.)  He also listed state legislatures but not Congress.  But then the other decision makers are the owners of the facilities.

A continuing issue that I have with regulation is tangential to Craig’s “Half Slave/Half Free” term.  His PJM operates in parallel with several other entities.  I have frequently pointed to the Lake Erie donut[2] , with is the path around Lake Erie that allows electricity to flow from Chicago to New York City along two major paths, north or south of Lake Erie.  I have said that when there is unscheduled loop flow, e.g., more going north of Lake Erie than has been scheduled, that there should be payment for that unscheduled flow.[3]  The same issue applies to PJM versus TVA, which have lines in parallel.  Sometimes one system is paid for the contract path but some of the electricity actually flows on the other system.  And just south of TVA is the Southern Company, providing a fourth east/west path for loop flows.  I say that a mechanism to pay for loop flows may be one of the ways to get around the transmission cost allocation and siting issues mentioned by Craig.

I note that I did not raise all of these issues during the lunch Question and Answer period, I spoke enough as it was.  Craig is certainly welcomed to comment on this blog, as are others.

[1] See “NCAC-USAEE Overnight Field Trip of 2013 October 4-5,” 2013 Oct 07,

[2] See my “Wide Open Load Following,” Presentation on Loop Flow to NERC Control Area Criteria Task Force, Albuquerque, New Mexico, 2000 February 14/15, on my web site, under publications under other publications.

[3] See my blog entry “Socializing The Grid: The Reincarnation of Vampire Wheeling,” 2011 Mar 17,

Energy Interchange Markets–Often Designed to Fail

I participated on the NAESB IIPTF[1] while it met during 2003-2005.  I argued then that there should be a cash payment for inadvertent interchange and that the cash payment should be differentiated over time and across geography.[2]  About the same time I participated in the InPowerG discussion of ABT pricing of UI[3], making similar arguments.[4]

My concern before the IIPTF was that parties could game the market.  First the party could buying cheap electricity upstream of a constraint.  The party could then sell expensive electricity downstream of the constraint.  The party could then arrange a cheap but ineffectual parallel path around the constraint.  This issue was described in the title of my first published article[5] some 15 years earlier.

Most other markets would look at a set of transactions as forms of efficiency inducing arbitrage.  The purchases would raise the price in the cheap markets.  The sales would depress prices in the expensive market.  The transportation agreement would raise the price of transport, further lowering the price differential between the high priced area and the low priced area.  But, the rigid terms of most tariffs just produced a profit for those entities willing to operate in this shadowy market.  The name Enron evokes such shadowy images, especially when paired with the CaISO[6].

But CaISO was not the only advanced market that found itself subject to such arbitrage.  PJM suffered some of the same loop flow issues when Midwest generation contracted with AEP and VEP, effectively moving electricity south around the PJM internal constraints between low cost Pittsburgh and the high cost Washington/Baltimore area.  PJM provided a similar southern loop for marketers in New York, who bought cheap electricity at the Niagara frontier, moved it west and south and back east toward the New York City area.

In recent years, FERC has been advocating Memorandums of Understanding that create Energy Imbalance Mechanisms.  I believe these MOUs and EIMs will fail to improve the system, and could contribute to problems on the network unless the associated cash outs use geographically differentiated prices.  For instance, the disastrous 2012 July 30 & 31 blackouts in India have been attributed to the lack of geographic differentiation in India’s energy imbalance mechanism[7].  Customers and generators downstream of the constraint faced the same price (once high, once low) as customers and generators upstream of the constraint (again, once high, once low). [8]

From the discussions I have heard about the MOUs and the EIMs, they seem to be designed to fail, not learning from the experience in India of a similar pricing mechanism, ABT pricing of UI.  The MOUs and the EIMs need to price the energy imbalances on a geographically differentiated basis with a price that changes automatically with the spot conditions.


[1] North American Energy Standards Board Inadvertent Interchange Payback Task Force

[2] At least one party criticized my approach because I generally used an exponential formula, which nominally prevented the price from going negative.  My research for “Renewable Electric Power—Too Much of a Good Thing: Looking At ERCOT,” Dialogue, United States Association for Energy Economics, 2009 August, convinced me that negative prices could sometimes be appropriate.  Accordingly, I have recently used a hyperbolic sine as and a price adjustment factor.  The hyperbolic sine is the difference between two exponential formulas, one with a positive exponent, the other with a negative exponent.  See

[3] Availability Based Tariff and Unscheduled Interchange

[4] for a partial digest of those discussions.

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

[6] California Independent System Operator

[7] See my blog, which includes two separate comments added by Soonee, the CEO of the Indian grid operator.

[8] The price differential issues included reactive power generation and usage.  India’s ABT has a section that prices reactive energy, but not sufficiently to induce better responses from generators and loads.

System of Governance

On 2013 February 27 & 28, I attended the National Research Council’s workshop on “Terrorism and the Electric Power Delivery System.” Though “terrorism” was in the title of the report issued November 2012, the issues were as applicable to natural disasters as to terrorist attacks. In regard to problems on the electric delivery system I was reminded of the Yogi Berra quip, “It’s déjà vu all over again.” Except, I kept thinking, “It’s déjà vu all over again, and again, and again… .”

During the final session of the workshop, Granger Morgan of Carnegie Melon University, the NRC panel chair, said that microgrids could only work if local utilities were disenfranchised. I had just moved up from the audience to the panel table to pass a note to Richard Schuler of Cornell University and took advantage of sitting at a microphone to challenge the need to disenfranchise local utilities in order to have effective microgrids. My thesis is that the benefits of microgrids can be achieved by real time pricing of electricity imbalances within the footprint of the microgrid, where that real time market for imbalances is operated by the local wires company. I wrote about the concept four years ago in “The WOLF in Pricing: How the Concept of Plug, Play, and Pay Would Work for Microgrids”, IEEE Power & Energy Magazine, January/February 2009[i] and in “Microgrids And Financial Affairs – Creating A Value-Based Real-Time Price For Electricity,” Cogeneration and On-Site Power Production, September, 2007[ii]. The benefits of self generation such as a combined heat and power plant can be retained by the participants within the footprint through bilateral hedging, with the actual transactions being with the franchised utility. I note that Granger Morgan’s Carnegie Mellon University is in Pennsylvania, a retail access state, and is in the footprint of PJM, an ISO that operates such a real time market. “Déjà vu.”

I wanted to pass a note to Richard Schuler because he had commented that Australian industrial consumers had noticed that bulk power prices varied inversely with frequency, mentioning a study that he had seen from the mid 1990s. I wanted to get a reference to that study because in the 1980s I had proposed to automate the concept of pricing unscheduled flows of electricity, setting the price the same way, by the price varying inversely with frequency.  The concept of prices varying inversely with frequency is simply illustrated in the first figure, which somewhat replicates the graph Richard Schuler drew for me to illustrate his memory of the findings in Australia.  My first published paper on the topic was “Tie Riding Freeloaders–The True Impediment to Transmission Access,” Public Utilities Fortnightly, 1989 December 21.  So, “Déjà vu all over again.”

Inverse Relation between Prices and Frequency

Richard Schuler made an aside to me after my comment on microgrids about the need to increase the capacity of the wires between pairs of participants on the microgrid because of the size of some distributed generation projects. Such upgrades are part of the responsibility of a franchised utility, but until such upgrades are made and paid for, there needs to be a way to extend the dynamic pricing to include the dynamic use of wires, as I wrote in “Dynamic Pricing: Using Smart Meters to Solve Electric Vehicles Related Distribution Overloads,” Metering International, Issue 3, 2010. Now, truly, “Déjà vu all over again, and again.”

Terry Boston of PJM Interconnection (and perhaps others) repeatedly commented on the need to control frequency and voltage.  When FERC was investigating the concept of ancillary services in the mid 1990s, one pundit said there were 31 flavors of ancillary services.  I wrote “Thirty-One Flavors or Two Flavors Packaged Thirty-One Ways: Unbundling Electricity Service” The National Regulatory Research Institute Quarterly Bulletin, Summer 1996.  The two flavors I identified were active and reactive power which respectively control frequency and voltage. “Déjà vu all over again, and again, and again.”

I believe that microgrids would have the most value during the islanding of the electricity system, which might be the result of terrorism or a natural disaster. Sue Tierney of Analysis Group said that we need a system of governance.  I say that a real time pricing system would provide such a system of governance while the system is stressed, such as by a terrorist attack or by a natural disaster.

David Kaufman of DHS/Federal Emergency Management Agency asked what private actors need from the government, after all, 44 of the top 100 economies in the world are private companies and during emergencies private actors often provide much of the relief.  I believe that the government needs to allow and perhaps operate a system of real time prices while electric systems are operating on an island mode.  David Kaufman also told the story of visiting Haiti after the earthquake and being amazed by the entrepreneurship of kids.  They took batteries from abandoned cars and provided a cell phone charging service.  Batteries could be used on a microgrid during an emergency if appropriate real time prices were available for charging and discharging the battery.

Miles Keogh of the National Association of Regulatory Utility Commissioners said that better competitive markets are very important over short periods of time, after which other systems need to take over.  The real time pricing mechanism that I described in many of my papers could function well on an island electric system, at least until the island was reconnected to the grid and another pricing mechanism could take over.

Following Terry Boston’s admonition to control frequency and voltage and using the concept mentioned by Richard Schuler, I say that we can have a system of prices that vary inversely with frequency.  As I discuss in various papers including “Markets Instead of Penalties: Creating a Common Market for Wind and for Energy Storage Systems,” 8th CMU Electricity Conference: Data-Driven Management for Sustainable Electric Energy Systems, Carnegie Mellon University, Electrical & Computer Engineering and Engineering Public Policy Departments, Pittsburgh, Pennsylvania, 2012 March 12-14, my current thinking is that the shape of the inverse relation between prices and frequency should be a negative hyperbolic sine, such as presented in the next figure.  The hyperbolic sine is symmetrical about a price of zero and in this case a frequency of 60 Hertz.  The price needs to be offset from zero, such as with a price that varies inversely with time error.


The hyperbolic sine gets the price high enough to incent private actors who own backup generators to dump electricity into the island grid when frequency is perilously low.  I note that backup generators are notoriously expensive to operate, especially when the replacement of fuel is problematic.  If the price is changing every minute or every five minutes, the price will also drop when there are too many such backup generators or too many solar voltaic systems on the line.  The hyperbolic sine will also push the price negative when system frequency gets to be too high.  This swing in prices between high and low (or negative) would provide an incentive for the batteries to discharge and charge, as I wrote last year in “Reply Comments Of Mark B. Lively, Utility Economic Engineers, On The Need To Create A Program To Price Imbalances,” Rulemaking 10-12-007: Order Instituting Rulemaking Pursuant To Assembly Bill 2514 To Consider The Adoption Of Procurement Targets For Viable And Cost-Effective Energy Storage Systems, Public Utilities Commission Of The State Of California, 2012 February 13.

As I said, “It’s déjà vu all over again, and again, and again … .”

[i] Most of the articles, papers, and comments identified in this blog are available on my website,


The Smart Grid Needs Real Time Pricing of the Distribution Grid

When I read the January-February edition of IEEE Power & Energy Magazine earlier this week, I got hung up on figure 1 on page 53, “The price of energy in the PJM market.”  Figure 1 shows 6 hours of prices every 5 minutes.  There appears to be five prices for each time point which would represent 5 locations on the PJM system.  There is the obligatory price spike to $210/MWH and a price suppression to minus $40/MWH.

Curiously, the prices for the 5 locations seem always to fall almost on top of each other, even during the price spike.  Except during the price suppression period.  There, two of the prices actually went up slightly and were not suppressed, one dropped to the previously stated minus $40/MWH and the other two dropped significantly though not to minus $40/MWH, though one did go slightly negative.

My analysis is that the price spike was a generation related issue while the price suppression was a transmission related issue.

This edition of IEEE Power & Energy Magazine focuses exclusively on the smart grid.  Since the related article was about demand response in Chicago, I thought that there should be more about using demand response to handle constraints on the distribution grid, the section of the wires that most people discuss in regard to the smart grid.  Thus, the geographic price differentials should be on the distribution grid, which would be a issue for Exelon’s Commonwealth Edison instead of a transmission issue for PJM.

Using demand response to address generation issues is old hat, the load management programs of a few decades ago.  And though figure 1 shows some geographic dispersion of prices and thus, perhaps, demand response being worthwhile for the transmission portion of the wires associated with the smart grid concept, my experience with PJM suggests that the price suppression was probably most severe in the Chicago area, suggesting that there was too little load in that area instead of the need for demand response.

I believe we need more demand response, not just to handle the G&T issues associated with figure 1, but more especially to handle overloads on the distribution grid.  Electric vehicles (according to EPRI) will overload the majority of the transformers that EPRI studied. 

  • The presence of figure 1 in the IEEE P&E Magazine suggests that many people believe that we can use real time prices to get more demand response.
  • The EPRI study tells me we need demand response to handle distribution issues. 

Putting it together, we need a way to price the use of the distribution grid on a real time basis, just as PJM has put into place a way to price the G&T on a real time basis.

I came to this distribution pricing conclusion last January while speaking at the IEEE/NIST smart grid conference.  My paper on the subject is “Dynamic Pricing: Using Smart Meters to Solve Electric Vehicles Related Distribution Overloads,” Metering International, Issue 3, 2010, which came out last Fall.