Electric Demand Charges: A Lesson from the Telephone Industry

The only ad with prices that I remember from 50 years ago was AT&T’s offering of a three minute coast to coast telephone call for $1.00.  With the inflation that we have seen over the last 50 years, one would expect that a coast to coast call would now be at least $10.00 for three minutes.  Instead, most telephone bills show a monthly service fee and no itemization for individual calls.  Automation has allowed the telephone companies to do away with most telephone operators, which was a significant portion of the variable cost of making long distance telephone calls.  The principal cost is now the investment in the wires, which doesn’t change with the number of calls that are carried.  So, most carriers now charge a monthly fee and little or no charge per call.  Perhaps it is time for the electric industry to go that way?

 

The restructuring of the electric industry has generally separated the distribution wires function from the generation[1] and transmission[2] function for most customers of investor owned electric utilities.  This restructuring puts such electricity customers into the same position as their counterpart customers of municipally and cooperatively owned utilities.  Municipally and cooperative owned utilities have generally been distribution only utilities, buying generation and transmission services from others, instead of being vertically integrated like most investor owned electric utilities.

 

The restructuring of the electric industry has resulted in most customers being served by a distribution company which has very little variable cost, much like the telephone companies.   A significant distinction is that telephone lines handle one call at a time.  The telephone line is either in use or is not in use.  In contrast, electric utilities provide a continuously variable service.  The customer may be taking 10 watts (a small light bulb) or 10 kilowatts (running the A/C, water heater, and stove at the same time), or any amount in between.  The telephone company has the wires to serve the customer’s demand, whenever that call occurs[3].  The electric distribution company similarly has the wires to serve the customer’s demand, whenever that demand occurs.  While the telephone company will have customers on a binary basis (they are either a customer or are not a customer), the electric distribution customer serves its customers on a continuous basis (they might be very small customers who never use more than 10 watts or a very large customer that might use up to 100 MW.)

 

The binary basis of telephony customers allows the telephone companies to charge their customers a specific amount on a monthly.  The continuous nature of the size of electric services suggests that electric distribution companies charge their customers a price based on the size of the electric service used by the customer.  For commercial and industrial customers, electric utilities have long included in their tariffs a demand charge that depends on the maximum power that the customer used during the billing period[4].  Typically such demand charges will be based on the average consumption for some 15 minute period.

 

Cost has been a significant factor that limited the use of demand charges to commercial and industrial customers.  Demand meters are more costly to manufacture, in that they do more than just accumulate the amount of energy that goes through the meter.  Demand meters are more expensive to read, in that the meter reader has to note two quantities and has to manually reset the demand register.  These two cost factors are lesser issues in regard to determining residential demand now that the industry has moved significantly to Advanced Meter Reading (AMR) and to Advanced Meter Infrastructure (AMI[5]), both of which automatically collect consumption data, including for 15 minute intervals.

 

Historically residential demand charges was thought to produce an insignificant shift of revenue among residential customers.  The reasoning was that, though residential customers are different in size, they have a similar load pattern.  A customer using 1,000 KWH a month would have ten times the demand as a customer using 100 KWH a month.  Implementing a demand charge that collected an amount equal to 20% of the energy revenue collected from the larger customer would also collect an amount equal to 20% of the energy revenue collected from the smaller customer.  There would be no revenue shift among these residential customer, at least for consumption.  However, the utility would have had to install more expensive meters, which would have increased the monthly customer charge of both customers without providing a significant benefit to the utility or to the customers.

 

The move to AMR and AMI has reduced the cost of determining the demand for residential customers.  Now the cost of determining metered demand is not an issue in differentiating between customers with different consumption patterns.  Customers who should be paying a demand charge equal to 30% of their energy payments can be distinguished from customers who should be paying a demand charge that is only 10% of their energy payments.  Further, on site generation has changed the paradigm that residential customers have similar load patterns, so that now the industry knows that there are the 30% customers versus the 10% customers and can bill them appropriately.  Indeed, for houses with sufficient on-site generation, the revenue from the demand charge could be several times the revenue from the energy charge, especially when the energy charge vanishes for a net zero home.

The growth in AMR and AMI along with the growth in residential on-site generation makes this an appropriate time for restructuring residential tariffs to include a demand charge to collect the cost of the distribution utility owning the power lines.  The energy charge should continue to collect the cost of generation and transmission, though the energy charge should be time differentiated to reflect the real time value of generation and transmission, as well as the associated energy losses.



[1] The creation of Independent System Operators (ISOs) is alleged to have brought competition to the generation sector of the electric industry.  However, many distributed generators, such as roof top solar, do not experience the real time market prices set by their local ISO.  This distorts the market for distributed generation.

[2] The creation of ISOs is also alleged to have brought competition to the transmission market.  But ISOs compensate many transmission lines on a cost of service basis, through a monthly fee, though they charge geographically differentiated prices based on line losses and line congestion and generally don’t compensate for loop flow or parallel path flows, such as PJM imposes on TVA and on the Southern Company, both of which have lines in parallel to PJM>

[3] Telephone customers occasionally receive a business signal, indicating that the called party is using his/her phone.  More rarely, customers will receive a circuits business signal, indicating that intermediate wires are in full use, not that the called party is using his/her phone.

[4] Demand charges come in a variety of forms including contract demand, thermal demand, and ratcheted demands, a distinction beyond the scope of this discussion.

[5] AMI is generally distinguished from AMR in that AMI generally includes the ability to communicate both ways, from the meter to the utility and from the utility to the meter/customer location.  The ability to communicate from the utility to the meter allows the utility to control devices that the customer has opted to put under the utility’s control such as electric water heaters, air conditioning compressors, and swimming pool pumps and heaters.

A Romp Through Restructuring

Today I presided over the monthly lunch of the National Capital Area Chapter (NCAC) of the U.S. Association for Energy Economics, with Craig Glazer, Vice President-Federal Government Policy, PJM Interconnection.  Besides announcing future events and talking about the successful NCAC field trip of October 4-5[1], I got to ask questions and comment as the luncheon moderator and President of NCAC.  I include some of those questions and comments below, along with several that where beyond what I felt like imposing on the luncheon attendees.

I liked that Craig mentioned that code words were often used in the industry, though not the ones I sometimes point out.  But when one questioner commented about the growth in distributed generation (DG), I pointed out that I look at DG as a code word for non-utility generation.  Nominally DG should be any generation on the distribution grid, but is generally used to restrict the ownership options.

Craig identified “Rates significantly above the national average” as one of the issues that drove the restructuring movement.  Unlike the children of Lake Woebegone where children are all above average, retail rates can’t be above the national average everywhere.  Thus, there are some parts of the country where restructuring was not an issue and the utilities have not been restructured.

Craig used the term “Half Slave/Half Free” to address the case of Virginia, where the State Corporation Commission still regulates retail rates but the generation and transmission systems participate in the competitive PJM market.  I noted that the result of restructuring was that the market value of electricity in my home location of Eastern Kentucky went from very low prices to moderately low prices, at least according to one of Craig’s slides.  But Craig had already made me feel better about this by telling of his trips to Kentucky to persuade the regulators to let their utilities join PJM.  He told them that one result the Kentucky electric companies joining PJM would be higher utilization of Kentucky’s cheap power plants.

These power plants joining PJM could sell the very low cost generation (the pre-restructuring picture) at moderately low prices (the post-restructuring picture), with the differential being used to reduce the prices for Kentucky residents.  As I pointed out, this is an example of Craig’s term “Half Slave/Half Free” where he pushed the concept.  I also pointed out that a substantial portion of the country has not restructured, which was my initial thought when he mentioned the term.  So we went back to the issue that not all parts of the country would benefit from restructuring.

Craig stated that restructuring changed the risk allocation formula.  He made the point that there was no Enron rate case.  In other situations where utility investments were cratering, there were rate cases, but not with Enron in the restructured world.  Further, there was effectively not even a hiccup in the PJM bulk power market on the day that Enron collapsed, even though Enron had been a major player in the PJM bulk power market.

Craig says that capacity prices are too low.  I see capacity as being a multi-year issue, requiring a multi-year solution.  Pre-restructuring, the utilities handled the variations in the need for capacity, and the value of capacity, through long term rates.  They built what they thought was needed and didn’t worry that the bulk power market went up and down, the utilities kept on trucking as vertically integrated entities.  Indeed, one of the problems that caused the California debacle of 2000/2001 was that the entire market was forced to pay the spot price of electricity.  The Texas market seems to be greatly hedged in that when the bulk power market price went up by a factor of 10, on average, for the entire month of August 2011, the retail price hardly budged.

Craig made an excellent point in regard to the question of who decides what in the electric industry, providing a list of governmental entities.  I notice that he did not mention the U.S. Department of Energy (of course he was a substitute speaker who replaced Melanie Kenderdine, assistant to the Secretary of the U.S. Department of Energy, because Melanie thought she would not be allowed to speak because of the shutdown of the federal government that ended about 24 hours before the lunch.)  He also listed state legislatures but not Congress.  But then the other decision makers are the owners of the facilities.

A continuing issue that I have with regulation is tangential to Craig’s “Half Slave/Half Free” term.  His PJM operates in parallel with several other entities.  I have frequently pointed to the Lake Erie donut[2] , with is the path around Lake Erie that allows electricity to flow from Chicago to New York City along two major paths, north or south of Lake Erie.  I have said that when there is unscheduled loop flow, e.g., more going north of Lake Erie than has been scheduled, that there should be payment for that unscheduled flow.[3]  The same issue applies to PJM versus TVA, which have lines in parallel.  Sometimes one system is paid for the contract path but some of the electricity actually flows on the other system.  And just south of TVA is the Southern Company, providing a fourth east/west path for loop flows.  I say that a mechanism to pay for loop flows may be one of the ways to get around the transmission cost allocation and siting issues mentioned by Craig.

I note that I did not raise all of these issues during the lunch Question and Answer period, I spoke enough as it was.  Craig is certainly welcomed to comment on this blog, as are others.



[1] See “NCAC-USAEE Overnight Field Trip of 2013 October 4-5,” 2013 Oct 07, http://www.livelyutility.com/blog/?p=233

[2] See my “Wide Open Load Following,” Presentation on Loop Flow to NERC Control Area Criteria Task Force, Albuquerque, New Mexico, 2000 February 14/15, on my web site, under publications under other publications.

[3] See my blog entry “Socializing The Grid: The Reincarnation of Vampire Wheeling,” 2011 Mar 17,  http://www.livelyutility.com/blog/?p=83

The Electric Transmission Grid and Economics

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

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

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

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

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

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



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

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.

Load Profiles and Unscheduled Flows of Electricity

In response to my earlier comments about a Fox News article equating decoupling with socialism, I received a question about time of use rate making and how my comments regarding unscheduled flows of electricity picked on small utilities. My response follows.

Most utilities group customers by their consumption patterns. You are grouped with McMansions and with hovels. Not because you have the same consumption, but the same pattern. Let’s say that a McMansion uses 10 times the energy that you use each month. Then, if you look at the consumption for the period defined as “on peak”, the McMansion will use about 10 times the amount of electricity that you use “on peak”. Similarly during any other well defined period. TOU pricing will not differentiate your average price from his average price, or at least not much.

Not much unless you or the utility invest in devices that control your consumption patterns. Thirty five years ago I worked for American Electric Power (AEP) in its New York City office. I helped investigate ceramic storage, a concept then in use in England. Turn on electricity to these “hot rocks” at night and then during the day just blow a fan across them to get heat into the room. Conversely, there is ice storage. Connect your A/C unit to a tank that looks like a water heater. At night dump refrigerant through the Ice Bear (a commercial brand I have heard of) and create ice. During the day, put the refrigerant through the Ice Bear instead of running your compressor. This creates huge swings in the multiplier between you and McMansion. During the night the multiplier might be down to 5 or less. During the day, the multiplier might be up to 20. The result is that you pay a lower average rate using TOU if you manage your load.

Dynamic pricing means to me a moment by moment change in the price of electricity. During the hottest day of the year, the price might soar by a factor of 100. Avoid 7 hours at that high rate and you have reduced your average price by 1% (730 hours on average in the month) or more, at least if I have done the math correctly. Many utilities have equipment that they attach to your AC compressor to allow them to turn it off during such periods. The standard pricing approach is to pay you $5/month. They save money by avoiding some of the energy at the 100 times multiple.

Pricing is considered by many to be a form of rationing. Economists say that pricing is the best way to ration a commodity. It gets people to give up lower valued uses when there is a scarcity. I like to think of it as a way to soak those who can afford it so I can put in my controllers that allow me to store energy thermally. In some jargons, my thermal storage can be considered to be a form of supply side, though most just look at it as demand side.

As to whether the small utility gets the free ride or the large utility, it depends on the circumstance. My employer AEP, one of the largest in the country, may have been getting a free ride by building fewer very large generators. That lowered their average cost but they got reliability by interconnecting with other utilities that had many, though smaller, generators. Even the transmission example is not clear cut either way, especially when the high voltage line fails and the low voltage line experiences huge electrical line losses.

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.