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, http://www.livelyutility.com/blog/?p=233

[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,  http://www.livelyutility.com/blog/?p=83

The Electric Transmission Grid and Economics

Tuesday, 2013 October 8, I went to the MIT Club of Washington Seminar Series dinner with Anjan Bose of Washington State University talking about Intelligent Control of the Grid.  Anjan began with giving two reasons for the transmission grid but then seemed to ignore the predicate in explaining what the government has been doing in regard to the grid.

The first slide identified two reasons for the electric transmission system.  The first was to move electricity from low cost areas (such as hydro-electric dams) to higher cost areas.  This is an obvious reference to economics.  The second was to improve reliability.  Anjan did not get into the discussion of how that is an economics issue, but it is.  Reliability is greatly improved by increasing the number of shafts connected to the grid.  We can produce the same amount of electricity with five 100 MW generator or one 500 MW generator.  The five units provide greater reliability but also higher costs.  The higher costs are associated  with various economies of scale, including higher installed cost per MW, less efficient conversion of the fuel into electricity, and the need for five sets of round the clock staffs.  A transmission system allows dozens of 500 MW units to be connected at geographically dispersed locations, achieving the reliability of many shafts and the lower cost of larger generators.

But, the presentation had little to do with the economics of the power grid, and the investigations into those economics.  I noticed that much of the discussion during the question and answer period did talk about the cost of operating the grid, so people were indeed interested in money.

Anjan said that the financial people used different models than did the engineers who operate the system.  I have long said that we need to price the flows of electricity in accord with the physics of the system, by pricing the unscheduled flows.  The engineers and operators may plan to operate the system in a prescribed way, but the flows of electricity follow the laws of physics, not necessarily the same was the way some people have planned.

Anjan said that deregulation[1] has caused a dramatic decline in new transmission lines, especially between regions such as into and out of Florida.  My feeling is that new transmission lines would be added more willingly if the owners of the new transmission lines would be paid for the flows that occur on the transmission lines.  For instance, twenty years ago a new high voltage transmission line in New Mexico began to carry much of the energy that had been flowing over the lower voltage transmission lines of another group of utilities.  The group of utilities called the service being provided “vampire wheeling” and refused to make any payment to the owner of the new transmission line.  The new line provided value in the reduced electrical line losses and perhaps allowed a greater movement of low cost power in New Mexico, but that value was not allowed to be monetized and charged.

I note that a pricing mechanism for the unscheduled flows of electricity would have provided a different mechanism to handle the 2011 blackout in Southern California, which began with a switching operating in Arizona.  Engineers swarmed to the area to find data to assess the root causes but were initially blocked by San Diego Gas & Electric’s attorneys who feared that any data could be used by FERC to levy fines pursuant to the 2005 electricity act.  I remember a discussion at the IEEE Energy Policy Committee on that proposed aspect of the bill.  The IEEE EPC voted to suggest creating mandatory reliability standards.  I was the sole dissenting vote, arguing that the better way was to set prices for the unscheduled flows of electricity.  Thus, SDG&E and the Arizona utilities would have been punished by the market instead of risking a FERC imposed fine.

[1] I prefer to use the more accurate term restructuring, since the entire industry is still regulated, even though generation is often subject to “light handed regulation” by FERC, which approves concepts instead of specific prices.

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, http://www.livelyutility.com/blog/?m=201208


[2] ABT – Availability Based Tariff, http://abt-india.blogspot.com/2007/10/windpower-discussion-on-inpowerg.html

[3] Power Crisis: Revenue Accounting Needed, http://www.energycentral.com/utilitybusiness/businesscorporate/articles/521/Power-Crisis-Revenue-Accounting-Needed

[4] Wind Boondoggles, Posted on 2012 Feb 28 by Mark Lively, http://www.livelyutility.com/blog/?m=201202

[5] NCAC-USAEE.org

Price Pressure on Input Capital Costs

We all know about the high cost of building nuclear power plants.  However, the operating costs are so low that the total cost of power out of a new nuclear power plant is just about competitive in the US electricity market.  According to the World Nuclear Association, as of 2013 October 1[1], there are 100 operable nuclear reactors in the United States and 3 under construction, equivalent to just 3% of the existing fleet.   In overseas markets, where the cost of competitive fuels are much higher, the total cost balance seems to be swinging in favor of nuclear power.  Outside the United States, there are 332 operable nuclear reactors and 67 under construction, or 20% of the existing fleet.

In light of some of these and other statistics, a cynical friend has suggested that the high construction costs are only tolerated because of the low nuclear fuel costs.  He suggested that as we see other fuels become more competitive with the cost of nuclear fuel, we will see price pressure put on the manufacturers of nuclear plants and of their component parts.  For those working in the electric industry, this is almost heresy.  The electric industry and their suppliers have a cost of doing business, a cost that is then recovered in the prices charged to their customers.  A lower price would mean a loss to the manufacturer, a loss they cannot afford.  Thus, the conventional wisdom is that there is little, if any, ability for competition to force prices lower, especially for the prices of capital equipment such as a nuclear power plant.  At least that is the conventional wisdom.

However, the electric industry has always had some competition.  Even small isolated utilities with two or more generators have competition in that the generators have to compete against each other to produce electricity at the least total cost.  This is the ancient concept of joint optimization.  The internal competition carried over with the formation of power pools and now with independent system operators.

The competition was not just an internal optimization but was also external.  Utilities buy and sell electricity with their neighbors on a competitive basis.  Most investor owned utilities are interconnected with two or more other utilities, with the interconnected utilities always attempting to sell electricity to their neighbors, which requires the selling utility to be cheaper than the price being offered by other utilities.  These prices would often be quoted for large blocks of power[2], and until recently didn’t have the finesse that has been attributed to power pools and independent system operators.  But the external transactions are still forms of competition.

So the concept of competition is not foreign to electric utilities, competition in the construction of nuclear power plants just hasn’t been in the forefront of the minds of utility executives, perhaps because of the small number of power plants that have been built.

Another friend, perhaps also a cynic, claims that drilling rig operators set their prices to extract much of the consumer surplus out of gas and oil fields.  He claims that the charge for drilling wells is greatly influenced by the expected profitability of the well.  Quoted prices are always low enough so that the field owner can expect to earn a return of his investment in about five years but are high enough so that the field owner can’t expect a return of his investment in less than three years.  My gas and oil friend’s claim is essentially the same as my cynical nuclear friend, that the construction costs go up and down based on the investment level needed for the facility to be profitable, whether it is a nuclear plant or a well expected to produce oil or natural gas.

This cynicism suggests that the United States should defer committing to new nuclear plants until the overseas rush as died down.  The nuclear industry has some limits on the ability to build new power plants.  The high price of fuel in overseas locations has made these locations to be more tolerant of high capital costs, more tolerant than in the United States, explaining some of the disparity mentioned above between the 3% growth in the United States versus the 20% growth overseas.  As the overseas nuclear building boom declines, maybe the cost of new nuclear power plants will decline, making them once again very competitive in the United States.

[1] http://www.world-nuclear.org/info/Facts-and-Figures/World-Nuclear-Power-Reactors-and-Uranium-Requirements/#.Uk2PQ1vD_IU

[2] “Electricity Is Too Chunky:  The Midwest power prices were neither too high nor too low.  They were too imprecise,” Public Utilities Fortnightly, 1998 September 1.

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 http://livelyutility.com/documents/USAEE-ERCOT%20Aug%2009.pdf

[3] Availability Based Tariff and Unscheduled Interchange

[4] http://abt-india.blogspot.in/2007/10/windpower-discussion-on-inpowerg.html 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 http://www.livelyutility.com/blog/?p=135, 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.

Goldman’s ReNew Says India Wind-Forecast Rule Will Erase Profits

In regard to “Goldman’s ReNew Says India Wind-Forecast Rule Will Erase Profits”, Bloomberg News, July 28, 2013, (http://www.businessweek.com/news/2013-07-28/goldman-s-renew-says-india-wind-forecast-rule-will-erase-profits) the problem is not the forecast rule but that the Central Electricity Regulatory Commission (CERC) has begun moving away from the competitive market concepts that it installed 11 years ago, moving toward a system of penalties.

Under a competitive market, if one wind generator was 10 MWH over forecast and anther was 10 MWH under forecast, both would see the same price, though with opposite but offsetting financial effects.  The price might be very high which would please the generator that was over and displease the generator that was under.  Or the price might be very low which would please the generator that was under and displease the generator that was over.  But both would see the same price.  The utility would pay one wind generator the same amount for the overage that the utility collected from the other wind generator for the underage.

Under a penalty concept, both generators will be displeased, both facing an economic impact that was harmful to their financial interest.  The penalty would inure to the befit of the utility.  Even when the amount of wind forecast errors netted out to zero, the utility would make money because the penalties always flow to the utility.  Under a competitive market, the payments can balance out.

In the U.S., the Federal Energy Regulatory Commission (FERC) seems enamored with the imbalance penalty contained in Bonneville Power Administration’s tariff.  When a generator is too far out of balance (25%), penalties accrue, even if the imbalances of the various generators balance out.  The utility makes money on imbalances, just as is proposed by CERC.

I wrote about how to modify the BPA penalty concept 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.  (Go to http://www.livelyutility.com/library.php# and look for RM05-25.)  The result would be something like the imbalance mechanism that CERC is abandoning.

In 2002 and 2003, India implemented an imbalance mechanism that looked at the net imbalance on the network to set the price for imbalances at generators and loads.  When the system imbalance was a shortage, the price for generator and load imbalances would be high.  When the system imbalance was a surplus, the price for generator and load imbalances would be low.  Recently, CERC has been abandoning this competitive market for large imbalances and is moving toward the BPA penalty concept that FERC embraces.  I think this change is a step backwards and the wind scheduling issue is part of that backward movement.

I don’t think that the 2002 method for pricing imbalances is perfect.  The prices don’t get extreme enough.  The prices don’t change geographically.  The prices don’t reflect various market forces.  (See http://abt-india.blogspot.com/2007/10/windpower-discussion-on-inpowerg.html)  But the mechanism tries to create a competitive market structure instead of a penalty structure, a penalty structure that always rewards the utility.

FERC, Barclays, and Formulary Arbitrage

On 2013 July 16, FERC ordered Barclays bank to pay a half billion dollars for market manipulation.[1]  The next day Barclays responded by suing FERC in federal district court, forcing FERC to prove the allegations in a venue that Barclays feels would be a level playing field.  On July 22, a New York reporter called a friend of mine who is normally well versed in utility legal matters, having been a regulator and a utility executive, seeking to understand what Barclays did to get FERC upset, asking for a simplified explanation.  My friend suggested another industry expert and also called me.  I got back to my friend on July 23, heard the request, and wrote a message to him explaining what I understood Barclays to have done on a generic basis, without having read much more than articles in The Washington Post.  It is that message of yesterday that I am copying here.

Thanks for the call on Monday in response to a NYC reporter who was asking you for background or information about the Barclays spat with FERC.  I have not followed the details of the spat, but the way I find it easiest to describe is as a thinly traded formulary arbitrage.

An arbitrage is buying and selling related securities with the hope of making a profit on the difference.  For instance, one might buy oil for $90/bbl and sell at $100/bbl and make $10/bbl on the paired transactions.  If the transactions are for oil delivered in different locations, one might also have a transportation cost of $1/bbl, reducing the profit to $9/bbl.  There may be some insurance and other handling costs, but if they are minor, one makes a profit so long as the differential is greater than the cost of transportation.  The transactions can be for the same location but different times.  One might buy a May futures contract for $90/bbl and sell a June futures contract for $100/bbl and make $10/bbl on the paired transactions.  But one has to store the oil, which might again cost $1/bbl for going into and out of storage and for one month in storage.

My understanding is that futures contracts settle at the end of the month before at the average spot price of oil on the last few days of the month.  So, a May futures contract would be settled at the end of April based on the spot price on April 30, or some sort of average.  I call this a formulary settlement.

If one has bought a lot of May futures contracts, one would like to see them settle at a very high price.  So, one might buy lots of spot oil on April 30 to push up the price at which the May futures contracts would settle.  This would be a formulary arbitrage.

But considering that the spot market is very large, it is difficult to budge by buying a lot of spot oil on April 30.  One might need to buy enough oil to supply ExxonMobil.  That would be a thickly traded formulary arbitrage.

Some commodity exchanges offer electricity forwards markets which settle based on the actual spot price of electricity on some of the ISOs.  The ISO spot prices might be thinly traded.  A paired transaction on the electricity forwards market and the ISO market may be a thinly traded formulary arbitrage.  At least that is what I would have told the reporter had you directed him to me.

Hope this helps for the next time.

[1] The Federal Energy Regulatory Commission (FERC) today ordered Barclays Bank PLC and four of its traders to pay $453 million in civil penalties for manipulating electric energy prices in California and other western markets between November 2006 and December 2008. FERC also ordered Barclays to disgorge $34.9 million, plus interest, in unjust profits to the Low-Income Home Energy Assistance Programs of Arizona, California, Oregon, and Washington. FERC News Release https://www.ferc.gov/enforcement/market-manipulation.asp

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, LivelyUtility.com.

[ii] http://www.cospp.com/articles/article_display.cfm?ARTICLE_ID=307889&p=122

CO2 Crusade Excesses Begin

The analysis of the global climate change has become quite contentious.  We seem to be focusing on issues that seem to have a minor impact on the climate and taking actions that are reminiscent of the various religious debates that have occurred over the centuries.

The current focus of climate change debate seems to be on carbon dioxide (CO2), almost to the exclusion of other issues.  Though CO2 may have a role in the change of weather patterns, CO2 seems to have a very minor role, perhaps insignificant role compared to some major cosmological issues.

  • Sun spots—The sun goes through a period of apparent warming and cooling, approximately every 11 years.  The cycle was noticed by a count of sun spots.  This cycle of sun spots was noticeably interrupted during the Maunder minimum (1645-1717) which was during the depth of the Little Ice Age (1550-1850)
  • Volcanic activity—Volcanoes often spew ash and sulfur into the atmosphere, which reflect the sunlight that would otherwise reach the earth.
    • The 1815 eruption of Mount Tambora in the Dutch East Indies was followed by the 1816 year without a summer, during which Boston experienced a July snow fall
    • The 1600 eruption of Huaynaputina in Peru was followed by the Russian famine of 1601-1603 which led to the decline of Tsar Boris Gudonov.

Both of these extended winters occurred during the Little Ice Age and may have contributed to the Little Ice Age as much as the Maunder minimum.

  • Earth’s axial tilt—The tilt of the earth’s axis is changing slightly, such that the Tropic of Cancer and the Tropic of Capricorn are both moving toward the equator by about 50 feet a year, and the Arctic and Antarctic Circles are shrinking by a similar amount.
  • The ocean bed—Earthquakes and landslides change the shape of the ocean bed, which determines the circulating currents of the ocean
  • Ice cover on the Arctic Sea—The Northwest Passage, which would provide a channel for shipping between the Atlantic and the Pacific, would also provide a new path for circulating currents of the ocean

These cosmic effects may dwarf the impact of the change in the amount of CO2 in the atmosphere.

The crusade for CO2 production abatement has led to excesses, some of which have historic precedents in the religious disputes of the past.

  • Indulgences—The Roman Catholic church has long had its members confess their sins and then undertake acts to show their remorse.  For a while the Roman Catholic church sold indulgences that covered sins that people anticipated performing, essentially getting permission to do bad things ahead of time.  Many people look at CO2 emissions in the same way.  Their extravagance in emitting CO2 can be forgiven by buying emission offsets, such as planting a tree.  This indulgence purchasing process was most notably demonstrated by former vice president Al Gore.
  • The Mob—The Washington Post reported 2013 January 22 that the Italian mob has moved into the wind industry, torching competitive wind farms and obtaining sweetheart contracts with the government for the sale of electricity from wind farms owned by the mob.  Similar sweetheart contracts have been negotiated in the U.S., though there have been no allegations of mob influence, just prices that will raise the price of electricity to consumers.
  • Forced conversions—Some religious groups have forced non-members to become members.  The practice of forcing consumers to obtain a portion of their total electricity consumption as renewable energy effectively forces all consumers to convert to a belief that renewable energy is the only way to save the planet from climate change.

Storage/Pricing — Chicken/Egg

On Tuesday, 2012 November 27, I attended the Heritage Foundation’s discussion of Jonathan Lesser’s 2012 October paper “Let Wind Compete: End the Production Tax Credit.” The only philosophical statement on which there seemed to be agreement was that improved storage systems could improve the market for wind.

But who would own the storage systems necessary to make wind even more viable? Unless the ownership is in common with the wind systems, how would these storage systems be compensated?

  • And, can we expect entrepreneurs to build these storage systems and then expect FERC to set an appropriate price? Beacon Power produced a flywheel storage system but couldn’t get FERC approval of a tariff before it ran out of operating cash and is now bankrupt.
  • Or should FERC put into place a pricing mechanism that could compensate storage systems when they arrived on the scene? I look at this as the Field of Dreams mantra of “If you build it (a competitive market appropriate for storage systems), they (storage systems) will come.”

Truly, a chicken and egg issue.

Wind has been accused of having two failings. Wind often provides a lot of power at night, when electricity is not highly needed.  Wind provides less power on the hot mid-summer afternoon, when electricity is needed the most. This is an intra-day issue for storage to handle. Wind power also follows the wind speed. A wind gust can push power production up to great heights. A wind lull can suddenly drop power production. Storage could be useful for handling this intra-hour issue.

Not all storage can handle both the intra-day and the intra-hour issues well. For example, the storage part of the Heritage Foundation discussion mentioned only pumped storage hydro as a representative storage technology to help wind. Pumped storage hydro has been used for decades to transfer power from the nighttime and weekends to the midweek daytime periods. That is, pumped storage is known as a way to handle the intra-day issue. I like pumped storage. My first job after getting a Masters from MIT’s Sloan School was with American Electric Power which owned a pumped storage plant. This perhaps accounts for some of my bias of liking pumped storage hydro.  (Actually I like to have a variety of generation options available, not just pumped storage.) Pumped storage hydro is excellent for intra-day transfers of power.

I have never seen anyone use pumped storage hydro for intra-hour transfers of power, or even propose it for such purposes. The absence of a historical use of pumped storage to provide intra-hour storage doesn’t mean that pumped storage could not be used for that purpose. After all, many people tout pumped storage for its ability to respond in seconds to changes in the need for electricity.

Pumped storage is often touted as being about 75% efficient. For every 100 MWH used for pumping, 75 MWH can be subsequently generated. We can model the effect of shorter duty cycles by beginning with the assumption that 0.5 hours in the pumping mode is ineffective. Under this modeling assumption, for 13 hours of pumping, there is the equivalent storage of 12.5 hours. With the 75% efficiency assumption, the system can generate for 9.375 hours, for a revised efficiency of 72% (9.375/13). Reduce the pumping time to 5 hours will reduce the generating time to 3.375 hours and the revised efficiency to 67%. Reduce the pumping time to 1 hour will reduce the generating time to 0.375 hours and the efficiency to 37%. This is not a very good efficiency ratio but we normally don’t think of running pumped storage on an intra-hour basis. I don’t know that pumped storage can run with just one hour of pumping, just that trying to do so will be costly, indeed very costly.

The intra-hour situation has been handled by batteries, flywheels, magnetic storage devices, and theft of service. Theft of service is a harsh term. When an electric utility faces the intra-hour problem associated with rapid changes between wind gusts and wind lulls, the physics of the electric system results in inadvertent interchange, electricity moving into and out of the utility.  With the inadvertent interchange going both ways, which utility is providing a service to the other utility?

If the wind gust occurs first, the power is stored on a neighboring utility system. If the lull occurs first, the utility is borrowing electricity and then gives it back. There is no systematic payment mechanism associated with this storage or borrowing of electricity. It is a free service as I described over two decades ago in “Tie Riding Freeloaders–The True Impediment to Transmission Access,” Public Utilities Fortnightly, 1989 December 21.

Most of the currently operating pumped storage systems were put into place by vertically integrated utilities. AEP often looked at its coal fired generating system as providing cheap, efficient capacity, allowing AEP to make large sales to its neighboring utilities. But the pumped storage system also helped AEP with its minimum load issues. The large AEP generating units were very efficient. The investments made to achieve these efficiencies hampered the ability of generators to cycle down at night, during minimum load conditions. Pumped storage systems helped AEP with that situation. Now many pumped storage systems operate in advanced markets operated by ISOs/RTOs, where their value can be assessed based on their interaction with the advanced market.

The thought process of testing how a pumped storage system would operate on an intra-hour basis also provides some information about profitability issues. For 13 hours of pumping and 9.375 hours of generation requires the off-peak price to be less than 72% of the on-peak price to achieve breakeven revenues, that is revenue from the sales to be equal or exceed the payments for pumping energy. The off-peak price has to be even less for the pumped storage system to have book income, that is the ability to cover its investment and other operating costs. The shorter the operating period, the smaller the break-even off-peak price relative to the on-peak price. A competitive market for storage systems needs to have very low “off-peak” price relative to its “on-peak” prices.  In this context, off-peak price and on-peak prices could be better described as storage prices versus discharge prices.

The advanced markets have hourly pricing periods that are consistent with the dispatch periods of pumped storage.  But for rapid response storage, hourly energy prices do not provide any incentives for the storage system to operate on an intra-hourly basis.  Indeed, if storage systems are to operate on an intra-minute period, then prices need to be differentiated on an intra-minute basis, not just on an intra-hour basis.  Area Control Error (ACE) is an intra-minute utility metric that can be used to set an intra-minute price for storage systems that are expected to be operated on an intra-minute basis.  India has developed a very simplified pricing vector that uses ACE to set the price for Unscheduled Interchange on an intra-dispatch period basis.

In India, the regional system operators set hourly schedules for the utilities and for non-utility owned generators.  Though the schedules are hourly, the utilities and non-utility owned generators are nominally required to achieve an energy balance every 15 minutes.  Each 15 minute energy imbalance is cashed out using a pricing vector that indexes the price for all imbalances against system frequency.  In India, system frequency is the equivalent of ACE.

There are ongoing discussions in India about modifying the pricing vector to reflect the hourly settlement price, to expand the pricing vector for more extreme values of ACE, to geographically differentiate the price, etc.  Though there are discussions about revamping the pricing vector, the pricing vector concept has greatly improved the competitive system against which the utilities and non-utility owned generators have be operating.  The pricing vector concept could be used to price intra-dispatch period storage to provide the competitive market from which the storage systems could draw power and into which the storage systems could discharge power.

Utilities, including ISOs/RTOs, use ACE to determine dispatch signals for their generators.  ACE is calculated every three or four seconds using the frequency error on the network and the interchange being delivered inadvertently to other utilities on the network.  Generally, the convention is that a positive ACE means that the utility has a surplus, while a negative ACE means that the utility has a shortage.

  • A surplus means that the utility is giving away energy, not getting any money for the surplus energy.  Under the situation of a positive ACE, the utility will want its generators to reduce their generating levels and would want storage systems to store energy.  As demonstrated by the earlier thought experiment, the market price for unscheduled energy into the storage system would have to be low for the storage system to absorb the energy economically.  When the utility is giving the energy away and not getting any money for the giveaway then any price, even a low price, for the energy going into storage can be appropriate.
  • A shortage means that the utility is taking energy from its neighboring unities, without paying for the shortage.  This is one form of the theft of service I mentioned facetiously above.  Under the situation of a negative ACE, the utility will want its generators to increase their generating levels and would want storage systems to produce energy.  As demonstrated by the earlier thought experiment, the market price for unscheduled energy coming out of the storage system would have to be very high for the storage system to produce the energy economically.  When the utility is stealing energy, then any price, even a very high price, for the energy coming out of storage can be appropriate.

For an explanation of the Indian mechanism for pricing Unscheduled Interchange, I recommend “ABT – Availability Based Tarrif”,[1] a completion of postings on InPowerG, the Indian equivalent of IEEE’s PowerGlobe and “ABC of ABT: A Primer On Availability Tariff,”[2] written by Bhanu Bhushan, the developer of the Indian pricing vector concept.  For a discussion of advanced pricing vectors that could be used for pricing storage, see the papers on my web site,[3] especially those filed recently with FERC.

The advanced markets have prices for generators that respond to the dispatch programs in a rectangular manner. For instance, consider a 5 minute dispatch period.  The price does not differentiate between those generators that are ramping versus those that are constant or those that move up and down to counteract ACE excursions.  An intra-dispatch period price for generation excursions would reward those generators (and loads) that help with ACE excursions and charge those generators (and loads) that cause the ACE excursions.  A pricing plan that achieves such a concept would be worthwhile even before fast acting storage systems came on line.

[1] http://abt-india.blogspot.com/2007/10/windpower-discussion-on-inpowerg.html

[2] http://www.nldc.in/docs/abc_abt.pdf

[3] http://livelyutility.com/library.php