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.

Disruptions, Energy Markets and “Joseph and the Amazing Technicolor DreamCoat”

On 2014 April 22 as this year’s president of the National Capital Area Chapter (NCAC) of the U.S. Association for Energy Economics (USAEE), I will preside over NCAC’s 18th Energy Policy Conference, which this year has the title “Disruptive Technologies Shock All Energy Sectors.”[1]  These disruptive technologies will require additional infrastructures, such as pipelines, wires, refineries, and generators.  And, since we operate a free market economy in the United States, we will need dynamic markets to handle the effects of these disruptive technologies as we see a change in the way energy flows in North America.

Wind pockets in the Great Plains and West Texas need high capacity lines to transport the energy across space to areas where the need for electricity is greater.  We need ways to pay for those transmission lines.  In response to the intermittency associated with wind, we will need fast response generators and ways to pay those generators to operate only a small fraction of the year.

Some fast response generators will be storage devices.  A high price for storage devices providing electricity for a small fraction of the year will be meaningless unless there are low prices during the portion of the year that the storage devices are being recharged.  This will move electricity across time, using cheap electricity during periods of fat to provide electricity during later periods of lean.

Oil production areas in North Dakota and Montana need pipelines and rail cars to move oil across space to market.  For years, the availability of low cost oil pipelines has reduced the price differential across the U.S.  The lack of sufficient pipeline capacity has depressed the well head price of oil in the Bakken fields, reflecting the higher cost of rail transportation to refineries.  New oil pipelines will reduce this price differential.

The natural gas system has many storage fields.  I mentioned earlier electricity’s growing need for storage.  And petroleum and its refined products also need storage.  During January 2014, there was not enough propane in storage in the Midwest and prices soared.  The shortage could have been handled by more refined products pipeline capacity, but additional storage would also have been an option, perhaps a cheaper option.

Though the conference is about technological disruptions, the shortage of propane in January can be thought of as a weather disruption.  Some people say that we are experiencing climate change.  My first experience with a claim of climate change was in 1990, when Edith Corliss, a physicist with the National Institute of Standards and Technology, a bureau of the U.S. Department of Commerce, told me was that the weather at that time more variable than weather had been since the time of Christ.  Our summers were alternately either (A) hotter and dryer or (B) cooler and wetter.  Or to put it mathematically, we were seeing a greater statistical variance and standard deviation in the measured temperature and the measured rainfall.  The el Niños were getting more intense, as were the la Niñas.  We were not having more of one and fewer of the other, just seeing more intensity in each.

I am reminded of the stage musical  “Joseph And The Amazing Technicolor Dreamcoat.”  The DreamCoat refers to a vision by the pharaoh that Joseph interpreted as a climate disruption.  There were to be seven years of fat followed by seven years of famine.  Joseph then created a physical system and a market to handle this insider knowledge.  He stored grain during the years of fat and used the grain sparingly through the end of the years of famine.  In commercial parlance he bought low and sold high.  In legal parlance, he traded on insider information and made a killing.

We need new infrastructure to handle the growing disruptions created by technological changes.  But we also need dynamic markets and new market mechanisms in our free market economy.  At least that is my Technicolor dream.

[1] See the conference notice at WWW.NCAC-USAEE.org

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.

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

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

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

 

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

 

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

 

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

 

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

 

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

 

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



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

Wind Boondoggles

            Wind can fit into the electric grid.  But all too often wind projects are boondoggles, government programs to concentrate the wealth of the nation into the hands of the politically connected, all too often with the cachet of Keynesian economics.

            Robert McCartney’s column “Wind power is worth the investment of $2 a month for Maryland households” in the 2012 February 25 edition of The Washington Post obviously argues for a greater investment in wind farms in Maryland.  But I was more intrigued by his explaining the political machinations being taking by the governor and his associates, using the Keynesian arguments for a temporary bump in construction jobs, a temporary bump for which Maryland consumers would be paying for years, probably costing more jobs in the long run than are produced in the short run.

            Three days after McCartney’s column The Washington Post  published my letter to the editor, along with two others, each of which had been written in response to earlier articles and editorials in The Washington Post .[1]  I take a longer term view of such investments.  We eventually have to pay for them.  Further, how many times has the government underestimated the cost of a project?  Yes, we are told it is only $2 a month per customer.  But that is today’s promise.  And $2 a month per customer is a lot of money.  Further, I doubt that the boondoggle will stop there.

            Keynes was a big proponent of the government spending its way out of recessions, which seems to be part of the governor’s calculus.  But I have to wonder about the payback.  Greece and a few other European nations are learning about the old adage, “Paybacks are Hell.”  They spent in a Keynesian manner and their economies are now being depressed by much more than the Keynesian spending had provided benefits.

Similarly, what will be the payback for the governor’s preferred method for adding more green electricity to the grid?  The benefits to limited parts of the current economy will be paid back at $2 a month per customer for years, sucking money out the Maryland economy, money that would otherwise have been able to provide jobs in the future.  I am sure that the response in the future will be more Keynesian economic investment, digging us into mess similar to the Greek hole.

            One aspect of the governor’s approach is a concentration of wealth into the hands of a few.  Though some might call it robbing Peter to pay Paul, I think of Robin Hood, the English folk hero brought to life by Hollywood, and his mantra of “Rob from the rich and give to the poor.”  Except as I say in my The Washington Post letter, the governor’s approach is the opposite of Robin Hood.  The governor is taking from everyone, especially the poor, and giving it to a few people, making the rich or richer. 

Yes, the governor talks about the working class people in Baltimore getting jobs.  But those same people will be the ones who will be short of jobs in the future when the $2 a month per customer payments are sucked out of the Maryland economy.  But that will be some other governor’s problem, just as the Greek hole is the problem of a different Greek government than the one that spent Greece into debt.

            But the wealth concentration is not just the temporary jobs given to the working class people of Baltimore.  The wealth concentration also shows up in payments to the manufactures of the wind turbines and in payments to the owners of the wind turbines.  In many respects these are the real beneficiaries of the governor’s wind program.  I am pretty sure that Robin Hood wouldn’t like this major, long term, part of the governor’s wind program, this legislative boondoggle.

            And as to the benefits of getting Maryland into the ground floor of manufacturing wind turbines, I seem to remember the same argument being made by the federal government about its loan guarantees to Solyndra, a manufacture of solar cells.  But these green generating devices were made more inexpensively by China, and Solyndra went under, with no long term benefit to the US for the investment in these manufacturing jobs, jobs that vanished with Solyndra’s bankruptcy.

            I would pull out my copy of Cervantes’s Don Quixote and begin tilting at windmills, but windmills do have a place in the electric grid, just not the way being proposed for Maryland.


[1] http://www.washingtonpost.com/opinions/which-way-wind-power-in-maryland/2012/02/25/gIQAXipbeR_story.html

Reporting the Effect of Wind on Consumer Costs—A Subtle Averch-Johnson Effect

On 2011 November 18, I received a link to a reply commentary published in Echo Press, The Official Newspaper of Douglas County, and then sought out the original commentary.  The two are

  • “Commentary – State energy policies should reflect market realities” by Mark Glaess, manager, Minnesota Rural Electric Association, Maple Grove, MN and
  • “Commentary – Wind energy isn’t increasing costs” by Beth Soholt, executive director, Wind on the Wires, St. Paul, MN, which is the reply.

 These commentaries were driven by a Minnesota requirement that utilities report on the effect that wind is having on the cost of electricity to consumers.  The reports filed in Minnesota PUC Docket No. E-999/CI-11-852 showed mixed results.  A quick read of some of the reports left me with the impression that the cooperatives bought wind power and found that the wind power increased their costs while the investor owned utilities owned wind generators and claimed a reduction in the wholesale cost of electricity.

I am reminded of the Averch-Johnson thesis that rate regulated investor owned utilities have an incentive to gold plate their facilities, in that the allowed return on investment is often slightly above their actual cost of money.  This thesis supports the current trend of utilities to invest in transmission systems that are regulated by FERC on an incentive basis, the incentive being an extra 1% in the allowed return versus the returns that FERC would otherwise allow the utility.

Might the Averch-Johnson effect have led the Minnesota investor owned utilities to a decision to own wind generators instead of buying their output?  Might the Averch-Johnson effect have led the investor owned utilities to choose an analytic method that showed tended to minimize the cost effect that wind has on rates, to the extent that the minimization led to numbers less than zero?

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, www.LivelyUtility.com.

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.