Risks of Going Solar

On February 22, 2016, Catherine Wolfram posted the blog Risks of Going Solar on the Energy Institute at Haas blog, part of the University of California Berkeley.  I posted the following, which I am adding to my blog.

Of the various regulatory Risks of Going Solar, Catherine Wolfram identifies two biggies, reducing the size of the net metering interval and shifting the rate design to include a smaller energy charge and a greater fixed charge.  But the risk of these two can be much larger than Dr. Wolfram suggests.  Reducing the size of the net metering interval exposes rooftop solar customers to the possibility of negative prices, while cost re-classification could result in (greater) demand charges instead of greater monthly customer charges.

In “Renewable Electric Power—Too Much of a Good Thing: Looking At ERCOT,” Dialogue, United States Association for Energy Economics, 2009 August,[1] I point out that a surplus of wind in West Texas forced the wholesale price for electricity below zero for about 25% of the pricing periods during that April, at least in West Texas.

Transmission constraints generally kept these negative prices from spreading to the rest of Texas.  Negative prices did spread to other parts of the state for just less than 1% of the rating periods.  As Dr. Wolfram well pointed out, these pricing periods are sometimes as short as 15 minutes (as they were in West Texas at the time), though are often one hour.

Many ISO do not seem to allow prices to go negative.  In West Texas, the combination of transmission constraints and the various credits[2] given to wind led to negative prices.  I believe that similar combinations elsewhere will force ISOs to allow negative prices in their dispatch programs.

I have long seen the need for utilities outside the footprint of an ISO to implement real time “value of solar” prices that are similarly negative.  Hawaii seems to be ripe for such negative solar prices.  Utilities outside the footprint of an ISO can implement “value of solar” prices using a Walrasian auction, as is discussed in many of my articles.

I actually disagree with the concept of a separate price for “value of solar.”  If we are to use prices to influence generation, there shouldn’t be a separate price for solar versus other spot generation imbalances.  A different price for unscheduled versus scheduled generation, yes, but not a separate price for just solar.

There will often be many prices during any pricing interval.  For instance, a single 15 minute period may be part of a 24×7 contracted delivery of power with one price and part of a 16×5 contracted deliveries with another price.  A third price might be applicable to variances.  Variances would include both solar that is dumped into the system and hiccups in the 24×7 or 16×5 deliveries, whether the hiccup is positive or negative.

Utility rate making often includes the concept of cost classification, where costs are identified as energy related, customer related, and demand related.  In the context of Risks of Going Solar, customer related and demand related are combined into the concept of a fixed charge.

The discussed increase in the monthly charge is only one way to reduce the energy charge.  The other way, and I believe a better way, to decrease the energy charge is to increase the demand charge, or to implement a demand charge when there is not a demand charge in place.

Customer charges impose greater burdens on small, often lower income, residential customers, while demand charges tend to protect these smaller customers, as is discussed in

  • “Curing the Death Spiral,” with Lori Cifuentes (Tampa Electric Company), Public Utilities Fortnightly, 2014 August;[3]
  • “Demand a Better Utility Charge During Era of Renewables: Getting Renewable Incentives Correct With Residential Demand Charges,” Dialogue, United States Association for Energy Economics, 2015 January;[4] and,
  • “Fairly Pricing Net Intervals While Keeping The Utility Financially Healthy,” 48th Annual Frontiers of Power Conference, cosponsored by The Engineering Energy Laboratory and The School of Electrical and Computer Engineering, Oklahoma State University, Stillwater, Oklahoma, 2015 October 26-27.[5]

Thus, as we see a continued growth in solar, I see a growing need for finer pricing intervals and a growing need for demand charges.  Fortunately, the huge growth in interval meters allow these better rate designs.  We just need to political will to implement something other than a monthly charge for energy.

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

[2] such as production tax credits and renewable energy credits

[3] https://www.fortnightly.com/fortnightly/2014/08/curing-death-spiral?authkey=54d8da5efd3f76661023d122f3e538b4b3db8c8d5bf97a65bc58a3dd55bb8672

[4] http://dialog.usaee.org/index.php/volume-23-number-1-2015/271-lively

[5] A copy is available on my website, www.LivelyUtility.com.

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.

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.

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.

Electricity Crisis in Japan—California 2000/2001 deja vu

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.

Grid Security in India

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.

“Too Much of a Good Thing” Revisited

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

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

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

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

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

 

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

Effect on Average Price of Spot Volumes and Spot Prices

Given 100 MWH Dispatched at $40/MWH

 

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

 

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

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

Socializing the Grid

A friend sent me a message overnight that asked me, since my friend says I have an understanding of utility issues, to identify the misstatements in a 2009 January 15 article “Browner: Redder than Obama Knows” by Steven Milloy. http://www.foxnews.com/story/0,2933,480025,00.html   My response is below.  Now, as I am posting this to my blog, I realize that the article is over two years old.  When I began writing my response, I had focused on the January 15 and thought that I was only 11 days behind the time instead of two years.  Oh, well.  The interest in the article is current even if the article isn’t.

Before I talk about the Fox article, “Browner: Redder than Obama Knows”, let me talk a little about the socializing of the electric system, an issue I have been trying to correct for over twenty years.

Electric systems improve reliability by increasing the number of generators connected to the grid.  More generators with enough capacity and we are more likely to have enough electricity for everyone.  Electric generators have great economies of scale.  Larger units mean less steel and concrete per KW or KWH.  Perhaps more importantly, fewer power plant employees.  Manning an operating room 24×7 for a 2,000 MW plant takes not many more people than for a 300 MW plant.

So, eighty years ago electric systems were in a quandary.  To maintain high reliability, electric systems needed more units.  To keep costs low and improve profit margins relative to a fixed price, electric systems needed larger units.  So the trade off was between more, therefore smaller, units versus larger, therefore fewer, units.  The solution was to interconnect with one’s competitors which increased the number of units connected to the grid and allowed utilities to build larger, less costly, units.  In the summer of 1969 and from 1971 to 1976 I worked for American Electric Power (AEP).  In perhaps ten years times, AEP went from building 280 MW generators, to 800 MW, to 1300 MW, being able to achieve those economies of scale by having more interconnections with its neighbors than almost any other utility in the US.

Those interconnections created a form of socialism.  The utilities did not figure out how to charge each other for the increased reliability provided by the interconnection.  Reliability came to be considered to be a public good, not to be charged for.  Reliability regions created rules for their interconnected utilities, such as having a 20% reserve margin for each utility or having spinning reserves equal to the size of the largest unit.  If we assume only the 20% reserves, then a very small utility could build one large unit to enjoy the economies of scale and rely on the large number of interconnected units for reliability.  If an industrial facility builds and operates a cogeneration plant (whose per KWH fuel costs because of the steam usage is half of the per KWH cost of a conventional plant), then the industrial facility will not want to have a spinning reserve requirement that reduces the generation by on the cheapest unit on the system.

Over twenty years ago I wrote “Tie Riding Freeloaders–The True Impediment to Transmission Access,” Public Utilities Fortnightly, 1989 December 21 arguing for a de-socialization of the electric system, both of the generation component discussed above and of the transmission component.  I say that we need a system to pay for unscheduled flows of electricity on very small time increments.  That way the small utility with the single large unit would pay the current value of electricity whenever the unit went down.  If the unit always failed during the summer peak, then the prices would be very high.  If the utility did sloppy maintenance and the unit was out more than the average for the rest of the grid, then the utility would be making frequent payments.  The reliability regions were not able to devise a reserve rule to penalize the sloppy maintenance practices or the bad timing issues.  I say that pricing the unscheduled flows achieves the appropriate grid discipline, or at least better grid discipline.  India put into place such a pricing mechanism and improved its grid discipline.

The physical interconnection created a form of socialism of the generating system.  Real time pricing of the imbalances would remove some of that socialism.

For the transmission system, socialism comes in the form of loop flow.  Engineers often use the short hand of saying electricity flows through the path of least resistance.  But, when there are several paths of relatively low resistance, the electricity divides among those paths such that the marginal line losses on each path are the same.  Thus, two parallel identical lines will split the load equally between them.  Attach something to one of the lines and the load will split in some slightly different way, but not all going to the one line with the least resistance despite the short hand.

Higher voltage lines have lower resistance than do lower voltage lines.  Higher voltage lines are more expensive per mile of wire but less expensive per KW-mile, with much lower line losses.  Consider this another example of economies of scale.

Consider a small utility that has a low voltage transmission line connecting its customers over a long corridor.  Consider a large utility serving roughly the same corridor that builds a high voltage transmission line parallel to the other line.  If the lines are connected to each other at each end, total line losses are reduced when some of the power from the small utility travels on the wires of the large utility.  If there is a scheduled transaction for the flow, the small utility will pay a wheeling fee to the large utility.  Generally there is no scheduled transaction and the small utility gets a free ride, a form of socialism.  Some describe the claim by the large utility for a wheeling fee to be “vampire wheeling.”  My article says that the network needs to price this unscheduled flow by differentiating the price geographically in addition to the temporal differentiation discussed above.

In regard to the Fox article, the aiding and abetting has taken the form of support for carbon taxes that would impact utilities differently.  A utility with a large nuclear fleet would see its competitors costs go up.  That would competitively advantage the nuclear fleet owner and in restructured markets, such as those operated by ISOs, the price of energy from the nuclear fleet would go up by the carbon tax without the cost of the nuclear fleet going up.

In regard to decoupling, some utilities will weatherize my home, with little or no charge to me.  That will lower the amount of electricity that I consume for HVAC.  The utility will treat the cost it incurred to weatherize my home as a legitimate rate case expense.  This raises the price that everyone, including me, pays.  If the utility has 100 customers, then I end up paying in higher rates less than 1% of the cost that the utility incurred to pay for weatherizing my home.  With a thousand customers, I pay less than 0.1%.  But I will pay for weatherize other peoples’ homes.  Except, that my new, green and economy minded, wife and I already spent a fortune on new double paned windows and other weatherizing features.  So my costs will not get socialized but I would pay the cost incurred by the utility for weatherizing others.

The Fox article presents three ways for decoupling, different ways for the utility commission to treat the weatherization costs as a legitimate rate case expense.  Or the government could use stimulus money for the same purpose, a different form of socialization.

My comments above don’t actually identify and explain misstatements, just explain some of the statements.