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.

Making Electricity Ubiquitous, Ubiquitous But Not Necessarily Cheap

I attended the 37th International Association for Energy Economics International Conference 2014 June 15-18 in New York City.  During the Wednesday “Dual Plenary Session: Utility Business Model” Michel Derdevet, Secretaire General, Electricite Reseau Distribution France, the French distribution utility, raised the issue of getting electricity to the billion people in the world who don’t have access to electricity.

During the audience discussion period, I raised the concept of a different business model, unregulated micro-grids owned by non-utilities.  I mentioned that a friend thought this concept could be applied to the nearly ubiquitous cell phone tower.  Cell phone towers require a power supply.  My friend thought that the provider of a cell phone tower should be granted a 10-year license to provide power on an unregulated basis.

My thought was that owner of the cell phone tower should be allowed to provide electricity and compete against anyone else that wanted to provide electricity.  Competition can better drive down prices than can regulation.  Regulation in terms of getting electricity to be ubiquitous would just stifle innovation.

Over the years, newspapers and newsmagazines have had pictures of the electric grid in some countries that look like a spider’s web on LSD.  Local entrepreneur’s buy their own diesel generators and provide “backup” electricity to their neighbors over wires strung in parallel or across the wires of the local utility.  The electricity is “backup” electricity in that it is used only when the local utility doesn’t have enough central station power to provide electricity to the entire national grid.  The utility then blacks out some neighborhoods.

The neighbors buy only a small amount of “backup” electricity from entrepreneur because the “backup” electricity is so expensive, being produced by diesel generators, which are less efficient and use a premium fuel.  The “backup” electricity is used for lights and a fan at night, perhaps for a refrigerator, not for those devices that might otherwise by electricity guzzlers.[1]  When the utility once again has enough power, competition drives the price down, putting the high cost entrepreneur out of business.

These micro-grids, whether run by the owner of the cell phone tower or by a neighborhood entrepreneur, can make electricity ubiquitous, even if the electricity is not cheap.  After all, Michel Derdevet said to me after his panel was done that some people were pushing for ubiquitous power supplies so they could make money selling electricity, not just for an eleemosynary purpose.  Thus, the power might not be cheap.

During the plenary session, Jigar Shah, Founder, SunEdison, LLC, claimed that California, with the highest electricity rates in the U.S., does not have the highest energy bills, because California residential consumers use less electricity. [2]  This is consistent with my comment about the lower usage of “backup” electricity relative to central station power.  However, elasticity may not be the only explanation for the lower consumption in California.  There is also the issue of climate and rate design.

Standard rate design practices also result in higher prices for customers with smaller consumption levels. The standard residential rate design has a monthly customer charge (say $10/month) and a commodity charge (say $0.09/KWH).  These rate levels nominally reflect the way that a utility will incur costs, a fixed cost per customer and then a cost that varies with the amount of energy the customer consumes.  A customer using 100 KWH per month would have a monthly bill of $19 and an average cost of $0.19/KWH.  A customer using 1000 KWH per month would have a monthly bill of $100 and an average cost of $0.10/KWH.  Thus, an area of the country with lower electricity consumption can be expected to have higher average cost and lower overall bills.

The micro-grid could be operated by the above mentioned owner of the cell phone tower or an entrepreneur.  I like to think of innovators who decide to install their own electric systems and then share with their neighbors, which is a form of the first type of owner.  The generation is put into place for a purpose other than selling electricity but if the sales are lucrative enough, the owner may decide to upsize his generating capacity until the owner looks like a utility.

A friend built such a system during the 1980s while in the Peace Corps in Africa.  He had an engineering degree from MIT.  So he took the concepts learned dabbling in the MIT labs in Cambridge, Massachusetts and applied the concepts in the field in Africa.  Later my friend worked for a Westinghouse subsidiary building power supplies for remote micro-wave towers (the same concept as a cell phone tower) and remote schools.  His company used mostly renewable energy, such as solar and wind, because diesel was so expensive in the remote areas he electrified.  Diesel was used to top off the associated batteries when there had been insufficient renewable energy supplies for extended periods of time.  It was during this period of his life that I met this fellow MIT alumnus.

Yes, we can make electricity ubiquitous.  But it will take competition to make it cheap, or at least not quite so expensive.

[1] As an aside, the consumption reduction during periods when “backup” electricity is being used demonstrates the concept of the elasticity of consumption.  When prices go up, consumption goes down.

[2] Looking at Table 6 of the EIA’s utility data for 2012, the average price to residential consumers in California was $0.153/KWH, or 8th most expensive.  The average consumption for residential consumers in California was 6,876 KWH/year, or the 3rd lowest after Hawaii and Alaska.  The average bill for residential consumers in California was $1,053/year, or the 10th lowest in the U.S.

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.

NCAC-USAEE Overnight Field Trip of 2013 October 4-5

Friday and Saturday I went on a overnight bus trip with NCAC-USAEE to visit energy facilities in Western Pennsylvania and Maryland.  The trip included a visit to the Conemaugh coal fired generating plant near Johnstown, PA, the EDF Renewable Energy Chestnut Flats wind farm near Altoona, PA, and a family owned open pit coal mine near Frostburg, MD.  It was wonderful to visit these different technologies, seeing how they work, and getting some quality time with other people interested in the topic of energy economics.

The National Capital Area Chapter (NCAC)of the US Association for Energy Economics (USAEE) is one of the largest chapters of USAEE.  USAEE is in turn one of the largest members of the International Association for Energy Economics (IAEE).  I started attending NCAC meetings in January 2001, was on the NCAC council for 2003-4, treasurer 2005-2011, secretary 2011-2012, vice president 2012-2013, and am now president for 2013-2014.  As president I receive great support from the other council members.  This trip was the result of that support.

Jim McDonnell of Avalon Energy Services has been an NCAC member for about 5 years.  Late this summer he called to tell of a visit he had made to an open pit coal mine in Western Maryland, suggesting it might be a good place for an NCAC field trip.  Rodica Donaldson, NCAC secretary, of EDF Renewable Energy had mentioned during the July NCAC council meeting the possibility of a field trip to a wind farm.  I introduced Jim and Rodica and the next thing I knew they had plans to combine those two field trips with a field trip to a coal fired power plant and we were off for an overnighter.

During the bus ride Friday morning to Conemaugh, the 20 people on the tour introduced ourselves.  We included two current officers of NCAC, two past presidents of NCAC, and a vice president of IAEE, who currently lives and works in the DC area.  Sarah McKinley, an NCAC past president, of the Federal Energy Regulatory Commission was one of the last people to introduce herself.  She told of the open meetings at FERC that facilitated discussions, including the meeting of the Asian Pacific Electricity Regulators (APER) forum 2012 August 1-2.  She told the group that I had attended the APER conference as a member of the public.  Sarah and I talked the rest of the ride to Conemaugh.

My memory of the APER forum included having lunch with two members of India’s Central Electricity Regulatory Commission (CERC), including its chairman.  During the two days prior to the conference, on July 30-31, the Indian electric grid had suffered two huge blackouts, which were highly publicized.  Sarah remembered the two CERC commissioners being interviewed by the press about the blackouts.  My view of the blackout was that India had an overly constrained market mechanism for unscheduled flows of electricity.  A less constrained market would have provided larger incentives for actions that might have prevented the blackout.  I had even written a blog entry on that issue.[1]

In 1998, I became a pen pal through IEEE’s PowerGlobe with Bhanu Bhushan, the principal architect of the Availability Based Tariff (ABT) which in 2002 began to govern wholesale transactions in India.  Bhanu and I visited over dinner in both 1999 and 2001 when he came to Washington, D.C.  He gave me his papers supporting the ABT concept including its provision for pricing Unscheduled Interchange (UI).  A pricing vector sets the UI price every 15 minutes based on the average frequency variation experienced during that 15 minute period.  The UI pricing concept was quite similar to my Wide Open Load Following (WOLF) concept, in that WOLF also sets a price for unscheduled flows of electricity based on concurrent frequency variation.  Just as he shared his private papers on UI pricing, I gave Bhanu some papers I had published on WOLF.  As suggested by the full name of Wide Open Load Following and by the WOLF acronym, the UI pricing mechanism is very constrained relative to the prices that WOLF can produce.

In 2003 January, after UI pricing became active, Bhanu introduced me to InPowerG, an Internet e-mail group of electric power engineering professionals, generally from Indian industry and academia. The group is currently administered by the Power Electronics and Power System group, Electrical Engineering Department, IIT-Bombay and has more than 500 subscribers.  Bhanu’s introduction of me to InPowerG was in regard to an extended discussion of UI pricing, with some people strongly opposed to the concept.  I ended up adding comments providing theoretical support of UI pricing.[2] Though I fault UI pricing as being overly constrained, especially in comparison to my WOLF, I note that the US has no mechanism for pricing the unscheduled flows that brought down the US grid in 2003.[3]

Conemaugh is an 1800 MW power plant near Johnstown, PA, with two 900 MW units.  Conemaugh’s low cost has generally resulted in it being operate 24×7 at full load.  The expanded PJM market place has changed sufficiently to provide incentives for Conemaugh to cycle down at night.  Its operators have made major modifications to allow each unit to have a minimum load of about 380 MW.  I was impressed that the ball mills used to crush limestone for the scrubbers are generally operated off-peak.  The plant has sufficient storage for crushed limestone that the operators shut down this major parasitic load during the day, moving the parasitic load to the night.

One of our tour members subsequently ascribed the need for cycling to the growth of wind during the night.  I question attributing the need for cycling solely to wind since PJM has also experienced a huge shift in load patterns, with many fewer major loads, such as steel mills, that used to operate 24×7.  For instance, the river passing Conemaugh used to be reddish orange from the run-off at Johnstown Steel a few miles upstream.  Now the steel mill is gone.  I imagine that the shift in load shape could be having as big of an effect as the growth in wind.  Accordingly, I say that the jury is still out on the cause of the need for increased cycling of coal fired power plants.  I prefer to think that the cause of increased cycling is the increased transparency of the diurnal price of electricity, independent of the cause of that diurnal aspect of prices.

Another tour participant commented on the very large investment being made at Conemaugh to handle new environmental concerns, both NOX’s and mercury.  His analysis was that the investment is in excess of the original cost of the plant, at least according to his estimates.

EDF Renewable Energy’s Chestnut Flats wind farm is near Altoona, PA.  Seeing the wind mills operate up close, I could image Don Quixote tilting at wind mills in the 1605/1615 classic or the attack of the Martian machines in H.G. Wells “War of the Worlds” radio broadcast of 1938.  I have a blog entry combining Don Quixote and Robin Hood in regard to a proposal last year to mandate Maryland customers paying for off shore wind, which is an expansion of my “Letter to the Editor” published by The Washington Post.[4]

The output of Chestnut Flats is sold to Delmarva Power at a flat energy price.  There is no seasonality nor diurnal incentives, just that maintenance could not be planned during the summer.  After all, the summer is the high price period for PJM.  The SCADA system is operated in Spain, home to the company that provided much of the equipment and has the contract to provide operations and maintenance.  The Spanish company normally has three workers on site.  EDF Renewable Energy’s field manager at Chestnut Flats does have access to the SCADA information.  The SCADA system includes the ability to feather the blades after 6 seconds of continuous excessive wind speeds.

Our bus parked in the wind shadow of one of the wind mills.  Most of the time that we stood there I did not notice the noise created by the wind mills.  But when I thought about it, I could pick out a sound that I realized was the action of the blades.  The local township has zoned Chestnut Flats as residential, though the closest house is about 1200 feet from a tower.  A result of the residential zoning is that rain runoff ponds must be encircled by fences to protect children from drowning hazards.  But with the nearest house being 1200 feet from one of the towers and the land being fenced and at the top of a ridge, the zoning requirements seem excessive.  EDF Renewable Energy’s field manager very much accepted the regulations, providing very matter of fact responses to our questions, much like the old Dragnet line, “Just the facts, Ma’am, just the facts.”

The field manager had no impression that the wind was stronger during the night versus during the day.  His experience was that there was no significant difference.   Again, “just the facts” as he saw the facts and his personal observation of the movement of the wind mills.

On Friday morning we visited a family owned open pit coal mine near Frostburg, MD.  The owner described buying about 180 acres for his home so he could be away from everyone and then deciding to dig up coal from the abandoned drift mine about 100 feet under his property.  The entrance to the drift mine was about one mile away from the pit into which we walked.  Thus, the old underground miners eventually had to walk a mile into a hill side to get to the coal.  Initially the underground miners would have chipped at the coal at the hill side and then went deeper into the hill side to get to the remaining coal.  At the greatest extent, the walk was about a mile into the hill, at least for the underground mine.  Now, the mine was a pit 100 feet deep.

The owner had preserved, perhaps only temporarily, an area that included two wooden rails that had been used about 200 years ago to move coal cars into and out of the mine.  In the early 1800’s, miners would pull wagons into the mine, at an upward slope, through the coal seam to the face at which they were working.  The loaded wagons could almost drift down the rails to the exit.  Thus, empty coal cars were pulled up hill into the mine and loaded coal cars were pulled down hill out of the mine.  Jim McDonnell had given another explanation for working at an upward slope.  Water could not run upslope to fill the mine and did not need to be pumped out.  Both explanations work for me.

One of the mine workers seemed to express surprise that our group from Washington was “pro” coal, making the comment to Andy Knox, the other NCAC past president on the field trip, who works on energy projects for the Navy.  I didn’t hear Andy’s response but the worker’s comment led me to think that I am not “pro” coal, since that would imply that I am “anti” some other source of electricity.  Rather, I am “pro” keeping the lights on at the lowest reasonable cost to consumers.  As an engineer, I have learned that diversity of supply is generally good.  Having all wind, all nuclear, all gas, or all coal would make the electric system subject to great stress during political or environmental upheavals, such as has occurred in regard to nuclear, wind, coal, and gas.  Thus, I personally am “pro” diversity.  If NCAC is “pro” anything, NCAC is “pro” an open discussion of the issues.

The trip back to Washington, DC, on Saturday from Frostburg included a stop at Sideling Hill, where I-68 goes through a manmade notch in a ridge.  Jim McDonnell is a geologist and had provided material on synclines (which look like a bowl) and anticlines (which look like an inverted bowl) that resulted in the folding of the earth’s crusts millions of years ago.  Sideling Hill is at a sharp syncline, showing dozens of strata in the manmade notch.  The upward slope of the strata in the syncline suddenly stopping on both sides of Sideling Hill, which is only obvious because of the manmade notch, is quite impressive.  That Sideling Hill is at such a sharp syncline shows the impressive results of erosion, in that the notch is several hundred feet about the base of the mountain.  The implication is that huge amounts of the upper portion of the syncline bowl had been washed away.  What was left, as revealed in the manmade notch, was a narrow bottomed bowl that had layers of different types of rocks stacked in its center.

For me, an important part of the field trip was the interaction with the other participants.  Some of that is described above in regard to my discussion with Sarah McKinley and hearing the questions asked by various parties, including the mine worker’s comment.  Andy Knox also talked about his personal experience of becoming a net zero energy household.  He has installed enough solar cells that he often has a surplus and exports electricity to the grid.  He believes he has enough solar power to offset not only the energy he takes when solar production is low but also to compensate for the gas he burns in his range.  Recently, the gross generation from the solar cells has become enough that he was able to sell a REC, or a Renewable Energy Credit, for the 1 MWH he has generated to date.  I believe that Andy has an impressive story to tell.

Pictures from the field trip are being posted to the NCAC web site.[5]  Jim McDonnell has already submitted his photos and I saw many other people with cameras.  We expect to have an article published in the next issue of USAEE’s Dialogue.  I hope that some of the other participants on field trip will add comments to this blog or that I can include their comments in the Dialoguearticle.  There is enthusiasm for another field trip, which NCAC had already been planning for the spring in the Philadelphia direction.  One participant expressed interest in a field trip dealing with the use of electricity, such as at a steel mill or an aluminum plant, which the Philadelphia trip would do only partially.  Another participant said he had contacts in the steel and aluminum industry and might be able to arrange such a trip.  Maybe more later.

[1] Economic Failures Contribute to Indian Grid Blackouts, Posted on 2012 Aug 06 by Mark Lively,


[2] ABT – Availability Based Tariff,

[3] Power Crisis: Revenue Accounting Needed,

[4] Wind Boondoggles, Posted on 2012 Feb 28 by Mark Lively,


Robin Hood vs Renewable Portfolio Standards

Do Renewable Portfolio Standards Reverse the Robin Hood Concept
 by Taking from the Poor and Giving to the Rich?


English literature has the legend of Robin Hood, who “stole from the rich and gave to the poor.”  Some people liken the graduated income tax as a government Robin Hood program to achieve some of this wealth transfer from the rich to the poor, a form of income redistribution.  In contrast, renewable portfolio standards seem to have the opposite effect of concentrating money in the hands of the few at the expense of the entire community, including the poor.

Most government programs serve a Robin Hood function, taking money from the rich and middle class and providing services to the poor or to the general public.  The Solyndra nightmare is different in that the money is going to the rich, not to the poor or the general public.  The Solyndra nightmare will serve to concentrate the wealth in the country, giving money to a relatively few people.  Given that the money is coming from the general taxes raised by the government, the Solyndra nightmare will concentrate the wealth to a few rich people at the expense of other rich people and the middle class.  The large number of people who don’t earn enough to pay income taxes avoid the wealth concentration aspects of the Solyndra nightmare.

Renewable Portfolio Standards are different.  Everyone pays for electricity, either directly to the utility or indirectly in the form of rent.  The money associated with Renewable Portfolio Standards is paid to a few individuals, often people with ties to the legislators who voted to enact the Renewable Portfolio Standards.  Thus, money is coming out of the pockets of everyone, including the poor who were supported by Robin Hood, and goes into the pockets of the rich, the people who own the projects mandated by Renewable Portfolio Standards, the people whom Robin Hood supposedly robbed.

So, should Renewable Portfolio Standards be considered to be a reverse of the Robin Hood concept?  Do Renewable Portfolio Standards take from the poor and give to the rich?

Ramping–Wind Data from Kodiak, Alaska

A growing concern about renewable resources, such as wind and solar, is that they can ramp down and then back up in a few seconds.  The requirement that electric utilities balance their sources and uses of electricity on a real time basis means that the utility must incur a cost by contra-cyclically ramping up and then down other sources of electricity, whether the other source is generation, load control, or a storage unit.

Determining the cost of the countervailing generation is an accounting nightmare.  An alternative approach is to set a dynamic transfer price, where the dynamic pricing mechanism reflects the degree of imbalance on the network.  A large shortage should result in a high price.  A large surplus should result in a low price.  I first wrote publicly about a dynamic pricing mechanism in “Tie Riding Freeloaders–The True Impediment to Transmission Access,” Public Utilities Fortnightly, 1989 December 21, and recently wrote again about the mechanism in regard to “Pricing Unscheduled Ramping,” released 2011 September 15.  The latter is available on my web site,

Chugach Electric Association (CEA) is planning a 17.2 MW wind farm just outside Anchorage, Alaska.  CEA is interconnected with Anchorage Municipal Light & Power (MLP).  MLP is concerned about the ramping of the wind farm, since the ramping will jerk around the MLP system.  MLP obtained second by second wind generation data from Kodiak Electric Association (KEA) for the 4.5 MW wind farm on the KEA system for October 2010.  KEA operates asynchronously to CEA and MLP but it is one system in Alaska with a wind farm and thus with data about wind farm operations.

During the 2,678,400 seconds that month, the KEA wind farm averaged 1,544 KW of generation.  The wind generators had auxiliary power needs, such that during 535,798 seconds (20.00% of the time), the power flow was negative, that is, the auxiliaries were using more power than the generators were producing, averaging 34 KW of net flow from KEA.  During another 6,852 seconds (0.26% of the time), the generation was zero.  For the 2,135,750 seconds when there was net power flow from the generators, the average net generation was 1,944 KW.  The median value is 988.3 KW, with half of the values being greater than or equal to 988.3 KW and half of the values being less than or equal to 988.3.

I used Excel to count the number of seconds during which the wind farm was within specified blocks.  The blocks were 100 KW wide.  The block containing the most seconds was for the range when the flow was negative, between -100 KW and 0 KW.  The next highest count was for the interval between 4,500 KW and 4,600 KW, roughly the capacity of the wind farm.

In “Pricing Unscheduled Ramping” I present graph of the Excel counts, including a presentation of the mean and median values.  The distribution has its maximum value for the 100 KW of negative value and for the interval between 4,500 KW and 4,600 KW.  This second highest count is roughly the capacity of the wind farm.  In “Pricing Unscheduled Ramping” I also present a cumulative distribution of the number of seconds during the month by the net generation during those seconds, including a presentation of the mean and median values.

Since I was concerned about the amount of ramping that the wind farm was imposing on the system, I then calculated the second to second change in power levels.  The maximum one‑second drop in power generation was 646.1 KW.  The maximum one second jump in power generation was 303.6 KW.  During 1,361,692 one second intervals (50.84% of the intervals), there was no change in the power level of the wind farm.  So, despite some large one second ramps that KEA experienced with its wind generation, most of the time (50.84% of the intervals) the wind farm was absolutely stable with no ramping at all.

Another measure of ramping is the summation of the ups and the downs.  Looking at just the instances when the wind farm ramped up, the amount of ramping was 8,351,700.90 KW.  Assuming a capacity of 4,500 KW, the wind farm during the month of October ramped the equivalent of its full load 1,856 times, or 2.5 times each hour.  Thus, on average, every 24 minutes the wind farms ramped the equivalent of going from zero to full load and back to zero.  Few fossil fired generators would be able to last very long if they had to react to a duty cycle of 2.5 times full load each hour.  Flywheels and batteries are likely to be the only devices that can react to the need for such a duty cycle.

In “Pricing Unscheduled Ramping” I present a cumulative distribution of the number of one second intervals during the month by the net generation ramp during those seconds.  As is apparent from the above discussion, the cumulative distribution had a large jump at a change of 0 KW.

FERC seems to be enamored with the way that Bonneville Power Authority (BPA) charges penalties for imbalances.  Under the BPA approach, the penalty price depends on the amount that the generator is out of balance, the greater the imbalance, the greater the unit charge for the penalty.  The pricing plan in “Pricing Unscheduled Ramping,” out of necessity, presents such a punitive pricing plan for ramping. 

I presented a non-punitive plan for pricing imbalances in “Reply Comments Of Mark B. Lively In Regard To Using Prices Instead Of Penalties For (1) Regulation And Frequency Response, (2) Energy Imbalance, (3) Generator Imbalance, And (4) Inadvertent Energy,” Preventing Undue Discrimination and Preference in Transmission Services, FERC Docket No. RM05-25-000 and RM05-17-000, 2006 September 20.

A non-punitive plan for pricing generation ramping (and generation imbalances) rewards those imbalances that are in synch with the ramping needs of the grid as a whole.  Thus, when the wind generators ramp up while the grid is ramping up, the wind generators would be rewarded for that ramp.   Conversely, when the wind generator is ramping down while the system is trying to ramp up to meet a ramp up in load, then the wind generator should be penalized.

For a more complete discussion of the non-punitive pricing for unscheduled flows of electricity see “Tie Riding Freeloaders”, “Pricing Unscheduled Ramping”, or my reply comments in FERC Docket RM05-17-000.

Heads I Win, Tails You Lose: What to Do When Wind Doesn’t Perform as Promised

Wind generation is unpredictable.  Many like to use the term intermittent.  Some say that the term intermittent is inaccurate.  I prefer to talk about unscheduled flows.  The wind operator makes a commitment to produce power at a specified rate.  Sometimes the production exceeds that specified rate.  Sometimes the production is less than the specified rate.  Seldom is the production exactly equal to the specified rate.  It reminds me of Goldilocks and the three bears,  “Too hot, too cold, but seldom just right.”

Most utility approach unscheduled flows of electricity by punishing the provider for any imbalance.  If production exceeds the specified amount, then the price for the surplus is less than the standard price.  If production is less than the specified amount, then there is a high price changed for the shortage.  “Heads the utility wins.  Tails the generator looses.”

Utilities are used to the concept of “Too hot, too cold, but seldom just right” in the way they control their operations using the metric of Area Control Error (ACE).  Until about a decade ago, the operating paradigm was that ACE should pass through zero at least within 10 minutes of the last time it passed through zero.  ACE never was quite equal to zero, sometimes it was “too hot”, sometimes it was “too cold”, but never was it “just right.”  ACE just passed through being just right.

These “seldom just right” concepts can be combined into a financial model.

  • When ACE is positive and there is “too much electricity,” we can set a very low price for unscheduled amounts of wind.
    • If the wind is producing too much, then the wind operator will be disappointed with the price. 
    • But if the wind is operating below the specified rate, the charge for the shortfall will be the same very low price.
  • Conversely, when ACE is negative is there “isn’t enough electricity,” we can set a very high price for unscheduled amounts of wind.
    • If the wind is producing too much, then the wind operator will enjoy the high price for its surplus generation.
    • If the wind is producing less than specified, then the wind generator will face a penalty rate for the short fall. 

Since ACE is nominally a continuous variable, the price can vary continuously around some set point, such as the utility’s announced hourly price for electricity.

I call this pricing concept WOLF, for Wide Open Load Following.  You may want to read an old paper of mine or recent comments

  • “Tie Riding Freeloaders–The True Impediment to Transmission Access,” Public Utilities Fortnightly, 1989 December 21,
  • “A Pricing Mechanism To Facilitate Entry Into The FCAS Market” Investigation Of Hydro Tasmania’s Pricing Policies In The Provision Of Raise Contingency Frequency Control Ancillary Services To Meet The Tasmanian Local Requirement, Office of the Tasmanian Economic Regulator, 2010 July 9
  • “Ratemaking To Facilitate Contra-Cyclical Operations” FERC Docket RM10-17-0000 Demand Response Compensation In Organized Wholesale Energy Markets, 2010 December 27.

Socializing The Grid: The Reincarnation of Vampire Wheeling

            The common aphorism is that electricity flows along the path of least resistance.  But that aphorism is just the shorthand way of describing the way electricity flows along all available paths, loading those available paths such that the marginal losses on the various paths are the same.  A scheduled transaction from Pittsburgh to Philadelphia will change the loading of the lines in Tennessee and Ontario, maybe not much, but at least an amount that can be calculated.  Of course, loading lines in Tennessee or in Ontario will change the loading on the PJM lines between Pittsburgh and Philadelphia.  The lines in Tennessee and Ontario can be considered to be parts of parallel paths for moving electricity between Pittsburgh and Philadelphia.

            It should be noted that the loading of lines in one region changes the loading of lines in another region, not necessarily increasing the loading, but changes the loading.  For instance, moving electricity from Pittsburg to Philadelphia loads lines from west to east.  If before this movement Ontario had been moving electricity from east to west, the Pittsburgh to Philadelphia transaction would tend to lower the loading on the wires in Ontario.  Thus, Ontario would benefit from the parallel path flow associated with a contract to move electricity from Pittsburgh to Philadelphia.

            The effect of a Pittsburgh to Philadelphia transaction on Ontario is part of a paradigm known as the “Lake Erie Loop Flow.”  A search of the FERC electronic library for 2009/2010 reveals 80 different documents with the term “Lake Erie Loop Flow” in several different dockets, including one docket (ER08-1281) that is effectively on the results of market manipulations associated with the “Lake Erie Loop Flow.”

            When I published my first paper, “Tie Riding Freeloaders–The True Impediment to Transmission Access,” Public Utilities Fortnightly, 1989 December 21, I was concerned that the contract path methodology would reward those transmission owners who were aggressive in signing transmission contracts to the detriment of the Ontario’s and the Tennessee’s in the above Pittsburgh to Philadelphia transaction, that is, the other transmission owners who were supplying the parallel path.

During the 1990s, the General Agreement on Parallel Paths (GAPP) proposed a sharing of wheeling revenue among the transmission owners just to the west and south of PJM.  GAPP only dealt with wheeling revenue.  A direct sale by one of the participants into PJM did not produce wheeling revenue and thus was outside the settlement provisions of GAPP.  The GAPP experiment lasted about three years.  GAPP contrasted with my proposal that the transmission owners cash out unscheduled flows on a real time, geographically differentiated basis.

            About the time of “Tie Riding Freeloaders”, El Paso Electric Company built a new high voltage (345 KV) transmission line that roughly paralleled an existing low voltage (115 KV) transmission line owned by Plains Electric Generation & Transmission Cooperative (now a part of Tri-State Generation and Transmission Association).  The lower impedance of the El Paso line resulted in substantial amounts of Plains electricity flowing on the El Paso line instead of on the Plains line.  El Paso sought to obtain revenue from Plains for the loop flow that was occurring on the network.  Plains called the concept Vampire Wheeling and fought the El Paso claim for compensation.  The issue was eventually settled in a transmission planning forum.

            Twenty years later the claim of Vampire Wheeling has re-arisen, but with the name of transmission cost allocation.  Owners of new high voltage transmission to be built in the footprint of large RTOs are seeking an investment driven revenue requirement that will be paid by all parties within the RTO footprint, whether or not the parties have agreed to the line or believe that they will benefit from the line.

The most egregious example of this unfairness is MISO relative to Michigan.  MISO transmission owners are planning major transmission lines to move electricity (much of it generated by wind) from the Great Plains to the Midwest, to the part of the MISO footprint that is south of Michigan but does not include Michigan.  Most of the electricity is likely to be sold to utilities even further east along the Atlantic Seaboard.  The current plan is to socialize the cost of the transmission lines by requiring all customers in MISO to pay based on their retail load.  Michigan objects for several reasons, including

  • Michigan’s law that obligates Michigan utilities to source a large amount of wind generation in-state.
  • Much of the wind generation will be going on to PJM and then to the East Coast, without Michigan being on the path.
  • Though Michigan is currently an integral part of MISO, a situation that will soon change when FirstEnergy changes from being part of MISO to being part of PJM, making Michigan connected to the rest of MISO only through PJM.

I believe that a suitable alternative approach is to cash out on a real time basis all unscheduled flows of electricity between and among the transmission owners, with the RTO’s frequently being treated as the transmission owner for those lines that have been socialized.   The price differentials across a transmission system would reflect the marginal line losses.  Since marginal costs are greater than incremental costs, the burdened system would earn greater revenue than it would incur in line losses.  Conversely, since marginal costs are less than decremental costs, the paying system would pay less than the line losses it saved by the loop flow on the neighboring system.

Reliability issues would be addressed by having the prices respond appropriately.  When lines are congested, the marginal line losses nominally increase, resulting in greater price differentials across the congestion point.  Similarly, when generation plants are strained, then all prices would increase.

In the Plains/El Paso example, the differences between the scheduled flows at the interfaces between the two utilities would have real time prices that change frequently.  The differences between scheduled and metered flows would be priced, with one utility effectively paying the other for fuel at each location, at least most of the time.  When the generation systems become strained, the prices would together float up when there is a shortage and float down when the constraint is minimum load conditions, such as those I discussed in

  • “Renewable Electric Power—Too Much of a Good Thing: Looking At ERCOT,” Dialogue, United States Association for Energy Economics, 2009 August; and,
  • “A Pricing Mechanism To Facilitate Entry Into The FCAS Market: Comments Of Mark B. Lively, Utility Economic Engineers,” Investigation Of Hydro Tasmania’s Pricing Policies In The Provision Of Raise Contingency Frequency Control Ancillary Services To Meet The Tasmanian Local Requirement, Office of the Tasmanian Economic Regulator, 2010 July 9.

The prices at the various interconnection points would disperse when the lines were constrained.

“Too Much of a Good Thing” Revisited

In “Renewable Electric Power—Too Much of a Good Thing: Looking At ERCOT,” Dialogue, United States Association for Energy Economics, 2009 August, I looked at the impact that wind was having on the dispatch prices in ERCOT, the Independent System Operator for much of Texas.  Prices were negative during about 23% of the month of April 2009 in West Texas, the region dominated by wind generation and during about 1% of the month in the rest of ERCOT, a region dominated by fossil generation.

This week my Dialogue article was brought back to mind by two messages I received, one on the IEEE list server PowerGlobe the second a ClimateWires article sent to me by a friend.  Both dealt with the issue of “grid operation during very high levels of wind energy”, the subject line of the IEEE PowerGlobe message.  The ClimateWires article deals with Bonneville Power Authority’s reaction to such situations.

My reaction to both messages is that we need a true spot price for electricity.  I once heard that a spot commodity price was for the commodity delivered on the spot out of inventory, before more of the commodity can be produced.  We don’t have an inventory of electricity, but we do have an inventory of production plant.  So, combining the concepts, the spot price of electricity would be applicable to deliveries made before we can change the operating levels of our production plants.  That may mean a different price for each second.  Certainly a different price for each minute.

But a spot price should apply to a different quantity than might the dispatch prices developed by independent system operators (ISOs) like ERCOT.  The dispatch prices should apply to quantity specified by bidders in the ISOs.  Any variation from that quantity, up or down, should be priced at the spot market.  Further, the spot price should be allowed to vary greatly from the dispatch price.  Otherwise the weighted average price of the total delivery might be seemingly insignificantly different from the dispatch price, as shown in the following table.

Description MWH Price Extension
Dispatch 100 $40.00  $     4,000.00
Spot -5 $30.00  $      (150.00)
Metered 95 $40.53  $     3,850.00


The basic assumption is that the generator committed to providing 100 MWH at a price of $40.00/MWH, and that the ISO accepted that price.  As it turned out, there actually was a surplus, such that the spot price was reduced to $30.00/MWH.  For some reason, which irrelevant for this analysis, the generator only delivered 95 MWH through the meter during this period.  Thus, the generator effectively bought 5 MWH in the spot market to achieve its dispatch obligation of 100 MWH.  The effect was that the 95 MWH that were actually delivered had a unit price of $40.53/MWH.  Some would say that the generator got lucky in this situation.  An arrogant generator might say that he was smart and dispatched down his generator.  The point that I am trying to make with the table is that the average price experienced by the generator is only 1.3% different from the $40.00/MWH dispatch price.

Effect on Average Price of Spot Volumes and Spot Prices

Given 100 MWH Dispatched at $40/MWH


  -$50 $30 $40 $200 $2,000
-10 $50.00 $41.11 $40.00 $22.22 -$177
-5 $44.74 $40.53 $40.00 $31.58 -$63.16
0 $40.00 $40.00 $40.00 $40.00 $40.00
5 $35.71 $39.52 $40.00 $47.62 $133.33
10 $31.82 $39.09 $40.00 $54.55 $218.18


The next table shows the effect of making a variety of spot transactions at a variety of prices, including negative prices and prices many times the dispatch price.  I note that the average price stays at the $40.00/MWH dispatch price when the spot price stays at $40.00/MWH or when the spot delivery stays at 0 MWH.  The average price from the first table appears in this table at the price of $30.00/MWH and a spot delivery of -5 MWH.

Generators prefer to be in the top left portion of the table or the bottom right, first where they are short when prices are low and second when they are long when prices are high.  Consumers prefer to be in the top right portion of the table or the bottom left, first where they consume less than the amount entered into the auction and the auction price is high and second where thy consumer more than the amount entered into the auction and the auction price is low.

Integrating Wind and Electric Vehicles

I see two issues in regard to integrating renewable resources and electric vehicles, one physical and one financial.

Renewable resources and electric vehicles are both intermittent, requiring some sort of storage to get them to interact with the “normal” part of the grid.  There are many types of storage, including batteries, pumped storage, and load management.  I call load management storage because I can use the electricity now to heat water or I can store the hot water by having heated the water last night.  Perhaps one of the oldest forms of storage is the flywheel.  Think how essential the potter’s wheel is as part of the infrastructure used by a potter.  In essence, flywheels keep the electric system running in that the rotating mass of the generators and the motors are flywheels. When there is a shortage, energy is extracted from the flywheels/rotating equipment and system frequency declines. When there is a surplus, energy is stored in the flywheels/rotating equipment and system frequency increases.

We need more storage devices, such as flywheels built just to be flywheels instead of as part of a motor or of a generator. And we need to pay the owners of these storage devices for their use. Their use should be similar to the use of the flywheel aspects of the grid. When system frequency is increasing or is high, we want storage devices to be absorbing energy. When system frequency is decreasing or is low, we want storage devices to be discharging energy. The incentives for the storage devices to act like this should be low prices (or even negative prices) when the frequency is high and high prices when the frequency is low.

I wrote “Renewable Electric Power—Too Much of a Good Thing: Looking At ERCOT,” Dialogue, United States Association for Energy Economics, 2009 August, to report on the negative prices experienced by the wind farms in Texas, about ¼ of the month of April 2009. And electric vehicles have the additional potential issue of overloading distribution transformers, at least if they are allowed to charge on an unfettered basis. My “Dynamic Pricing: Using Smart Meters to Solve Electric Vehicles Related Distribution Overloads,” Metering International, Issue 3, 2010 deals with that issue.