Wind Boondoggles

Posted on 2012 Feb 28 by Mark Lively

            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

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

Posted on 2011 Nov 29 by Mark Lively

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?

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Robin Hood vs Renewable Portfolio Standards

Posted on 2011 Sep 30 by Mark Lively

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

 

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

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

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

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

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Ramping–Wind Data from Kodiak, Alaska

Posted on 2011 Sep 30 by Mark Lively

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.

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

Posted on 2011 May 09 by Mark Lively

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.
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Electricity Crisis in Japan—California 2000/2001 deja vu

Posted on 2011 Mar 29 by Mark Lively

About three weeks ago Japan was severely ravaged by an earthquake.  From half the world away, it seemed as if what the earthquake didn’t devastate, the ensuing tsunami did.  In addition to the immediate damage, the long term suffering has been made worse by inadequate supplies of electricity, so inadequate that there are reports of rotating blackouts.  Some friends whose son lives near Tokyo worry about him being stuck in the subway if a rotating blackout hits the subway.

Economists say that the best way to ration a commodity when there is a shortage is through price.  Of course, economists deal with prices, so it is expected that an economist would suggest prices.  The economists view on economic rationing reminds me of the concept that if the only tool in your toolbox is a hammer then everything looks like a nail.

But I question whether there should be a shortage.  When California was experiencing a shortage of electricity and introduced rotating blackouts, a friend provided me data on backup generators in the Western US.  My analysis appeared in “Saving California With Distributed Generation: A Crash Program To Use Small, Standby Diesel Generators To Keep The Lights On,” Public Utilities Fortnightly, 2001 June 15.  California’s backup generating capacity was about 80% of its peak load.  I suspect that Japan has a comparable amount of backup generation, perhaps more because of Japan’s greater history of earthquakes.

But getting backup generators to operate is problematic.  First, they are notoriously inefficient and burn premium fuels.  Thus, the fuel cost alone from a backup generator is likely to be 3-10 times the fuel cost of the best central station power plant.  But, if you want to avoid blackouts, connecting thousands of backup generators to the grid will help.  Further, since the backup generators are distributed around the country, their operation will reduce electrical losses on the grid though not by enough to pay for the higher fuel cost.

India has implemented a pricing plan that could be used for the purpose of paying backup generators.  India’s Availability Based Tariff (ABT) has a pricing component for unscheduled interchange (UI).  The price for UI changes every 15 minutes, indexed on system frequency.  When frequency is low, the price is high.  When frequency is high the price is low.  UI pricing would be ideal for paying backup generators who are connected to the grid.

The physics of electricity results in a uniform frequency within a grid, uniform across geographic areas at any instant, but changing instant by instant as the balance between supply and demand changes.  A shortage will push system frequency down, as system operators are contemplating rotating blackouts.  Backup generators operating in parallel with the system will help hold the frequency up, at least if enough backup generators are operating.  The data from California suggest that Japan is likely to have enough backup generators.  The uncertainty relates to Japan’s willingness to pay these generators enough money to get them to generate.

The dynamic ABT price is for UI.  But it can also be used to price retail customers who have been requested to curtail consumption, at least for the amount by which the retail customer has not achieved the requested curtailment.  At the same time, the ABT price can be paid to retail customers who have surpassed the curtailment request.  This concept will require some improved metering or serendipitous use of distribution station metering and load profiles.  Perhaps I will write more on that later.

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Socializing The Grid: The Reincarnation of Vampire Wheeling

Posted on 2011 Mar 17 by Mark Lively

            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.

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Grid Security in India

Posted on 2011 Feb 28 by Mark Lively

On 2011 February 26, S.K. Soonee, CEO at India’s Power System Operation Corporation Limited posted on LinkedIn’s Power System Operator’s Group a link to a paper written by the staff of India’s Central Electricity Regulatory Commission.   “Grid Security – Need For Tightening of Frequency Band & Other Measure” can be accessed at      http://www.cercind.gov.in/2011/Whats-New/AGENDA_NOTE_FOR_15TH_CAC_MEETINGHI.pdf  Through LinkedIn I provided the following comments.

 I am dismayed that the simple elegance of the UI pricing vector, as shown in the two diagrams for 2002-2004 and 2007-2009, will be replaced by the convoluted vectors on 2011 May 3. It seems that there is a potential for mischief with having the multitude of simultaneous prices, with an undue accumulation of money by the transmission grid as some UI out of the grid is priced at very high prices at the same instant that other UI into the grid is being priced at a lower price. This is an unwarranted arbitrage for the transmission system.

The HVDC links between S and NEW could provide a warranted arbitrage situation where the grid with lower frequency delivers to the grid with the lower frequency. The different frequencies would result in different prices, with the price differences providing some financial support for the HVDC links.

I was surprised that there was no mention made in regard to Figures 1 and 2 as to when UI pricing started, and how that UI onset resulted in a narrowing of the spread between daily high frequency and daily low frequency. I believe these figures could be well supplemented by a presentation of histograms of the monthly frequency excursions, and how those histograms have changed over time. A numeric approach would include monthly average frequency and monthly standard deviation from 50 Hertz, a statistic for which you have a special name that I forget.

Parts of the Agenda Note discuss the serious impact of very short periods of frequency excursions. These short periods of concern are much shorter than the 15 minute periods used for determining UI. The various parts of the Agenda Note could be harmonized by reducing the size of the settlement period for UI from 15 minutes to 5 minutes or 1 minute.

There is a discussion of limits on the amount of UI power that a participant can transact. I question the need for such limits. As a participant increases the UI power being transacted, the price will move in an unfavorable direction, providing an additional financial incentive for the participant to reduce UI power transactions. For example, a SEB that is short of power and is buying UI faces higher prices as the UI transaction amount increases. These higher prices provide a multiplicative incentive for the SEB to reduce its shortage and its purchase of UI.

Many systems plan for the biggest credible single contingency, which the report treats as the single largest unit. The report shows that entire plants have gone out at a same time, suggesting that the biggest credible single contingency is a plant not a generating unit.

As an aside, in the listing of the generating capacity by size of generating unit, my experience in the US suggests that the list understates the number of generators. There would be many times the identified number of plants if the list included captive generators such as backup generators, which may be as small as a few KW. Again, based on my experience in the US, the total capacity of those unidentified generators will rival the total capacity of the identified generators.

I wonder why the under frequency relays in the East are set lower than the relays in the other regions.

I don’t understand the terminology that “Nepal has several asynchronous ties with the Indian grid (AC radial links).” My interpretation is that Nepal has a disjoint system with each section tied synchronously to different locations of India, making the sections synchronous to each other through their links to India.

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“Too Much of a Good Thing” Revisited

Posted on 2011 Feb 25 by Mark Lively

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

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

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

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

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

 

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

Effect on Average Price of Spot Volumes and Spot Prices

Given 100 MWH Dispatched at $40/MWH

 

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

 

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

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

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The Oil Spill Commission–Lessons Learned

Posted on 2011 Feb 02 by Mark Lively

I attended a dinner last night that included a presentation by William Reilly, co-chair of the Oil Spill Commission, who discussed their report, which is available with the following URL

http://www.oilspillcommission.gov/final-report

Reilly almost began with a comment that the Three Mile Island Commission report had effectively killed nuclear power in the US, in that the US has not built a nuclear power plant in over 30 years.  He didn’t want the Oil Spill Commission report to have a similar effect on drilling in the Gulf of Mexico.  We will see if it does.  I guess that the appropriate metric for that would be the number of new drilling rigs that are added in the Gulf, which would be the metric comparable to the metric of the number of new nuclear power plants added (or not added) over the last 30 years.

Reilly discussed a Report Card mechanism that the nuclear industry now has in place, with the power plant operators evaluating each other, a peer review program.  The executives of the plants that have the worst performance evaluation are effectively the subject of ridicule by the rest of the operators while the executives of the plants with the best performance evaluation are effectively given bumper stickers that say “My child is an Honor Roll student at . . .”  So they have created a system of bragging rights.

From what I have heard about the nuclear power industry, their performance metrics have dramatically improved over the last thirty years.  Plants are operating at much higher capacity factors.  That improvement could be attributed to the Report Card process.  I have also heard people say that the industry restructuring has given better (more) financial incentives to operators.  I am sure that the answer lies at neither extreme of this spectrum and probably includes other dimensions as well.  Whatever is the source of the improvement, the economy is better off with the improvement, even though we have not yet built a new nuclear power plant.

I commented during Q&A that the electric control area operators used to have such an Honor Roll system (they even identified utilities as being on the Honor Roll, using that term) for Area Control Error (ACE).  ACE is a metric brought about by the socialization associated with interconnecting competing power systems, about which I have written on my blog.  I then commented that the Energy Policy Act of 2005 instituted mandatory performance standards which are administered by NERC.  Reilly was unaware of the control area Honor Roll concept.  I haven’t participated in the process run by NERC, but have heard intimations of a peer review process for electric operations, which could be another Honor Roll.

I found interesting parallels between Reilly’s comments on the Mineral Management Service (now Bureau of Ocean Energy Management, Regulations, and Enforcement) and the three companies involved with the process.  MMS (now BOEMRE) did not have the budget to develop the expertise and manpower to do in depth inspections, seeming to accept the reports produced by drill rig operators.  Indeed, MMS (now BOEMRE) has many fewer inspectors per hundred wells in the Gulf than does California for wells on land in that state.  Similarly, BP seemed to accept the expertise of Halliburton and the drill rig owner. Both MMS (now BOEMRE) and BP relied heavily on the expertise of the group doing the work.  Afterwards an attendee commented to me that he was disappointed that Reilly did not identify a black hat or evil doer.  Maybe that reflected Reilly’s bent to avoid destroying the industry or major players in the industry.  I am reminded that the indictment of Arthur Anderson killed that company in the Enron fiasco of 2001.

During Q&A, Reilly compared prescriptive regulation with the peer review process.  After two or three years rules and regulation will be out of date and could actually be detrimental instead of just ineffectual.  In contrast, the continuing peer review process is always using best practices as those practices change continually.

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