Utility 2.0 or Just Utility 1.X

On Tuesday, 2013 October 29, I attended a discussion of the report “Utility 2.0: Building the Next-Gen Electric Grid through Innovation.”  I left feeling that the innovations discussed are just more of the same, just as I have often described the smartgrid as SCADA[1] on steroids.  The innovations are not creating Utility 2.0 as much as making slow changes to the existing utility structure, just varying the X in Utility 1.X.

Electric utilities began automating the electric system as soon as Edison started his first microgrid, the Pearl Street Station.  At one time, an operator would read a frequency meter to determine the balance between supply and demand.  In the earliest days, Edison had a panel of light bulbs that would be switched on and off to maintain that balance, which was a strange form of load management.  The operator would also be able to vary the generation by change the water flow to a hydro-turbine, the steam from the boiler, and the fuel into the boiler.  Edison invented control mechanisms that were cheaper than the labor costs of the operator, control mechanisms that his companies also sold to other utilities.  These control mechanisms can be considered to be some of the first SCADA systems.  As the control mechanisms and telephony got cheaper and labor become more expensive, more labor saving devices could be installed.  The policy of having an operator at every substation was replaced by remote devices, lowering the cost of utility service.  The smartgrid concept is just more of the same, as computers become cheaper and faster, remote metering less expensive, and remote control easier to accomplish.

The true quantum change in utility operations occurred in federal law.  PUHCA[2] effectively prohibited private individuals from selling electricity to a utility, by defining the seller to be a utility, subject to utility type regulation and to prohibitions on non-utility operations.  Because of PUHCA, Dow Chemical operated its chemical plants as the ultimate microgrid, running asynchronously and unconnected to local utilities.  Dupont installed disconnect switches that would separate its microgrid chemical plant from the local utility if power began to flow out of the plant.  International Power and Paper became International Paper.  Exxon intentionally underinvested in its steam plants, limiting its ability to produce low cost electricity.  PURPA[3] provided exemptions from PUHCA for cogeneration plants such as those mentioned here and for qualifying small producers using renewable resources.  The latter exemption was almost in anticipation to the growth of roof top solar photovoltaics (PV).  These facilities needed utility markets into which to sell their surplus, which generally resulted in individually negotiated contracts.  The creation of the ISO[4] concept could be considered to be an outgrowth of the desire by these large independent power producers (IPPs) for a broader, more competitive market, instead of the monopsony into which they had been selling.  ISOs now have a footprint covering about 2/3 of the lower US, excluding Alaska and Hawaii.

ISOs generally deal only with larger blocks of power, some requiring participants to aggregate at least 25 MW of generation or load.  ISO control generally does not reach down into the distribution system.  The continued growth of labor costs and the continued decline of automation costs has allowed the SCADA concept to be economic on the distribution grid, including down to the customer level.  This expansion of SCADA to the distribution system will soon require changes in the way the distribution system is priced, both for purposes of equity and for Edison’s purpose of controlling the system.

  • The growth in rooftop PV is dramatically reducing the energy that utilities transport across their distribution system.  This energy reduction generally reduces utility revenue and utility income.  Under conventional utility rate making, the result is an increase in the unit price charged by the utility for that service.  Some pundits point out that the owners of the rooftop PV panels are generally richer than the rest of the population served by the utility.  These solar customers are cutting the energy they consumer, though not necessarily their requirements on the utility to provide some service through the same wires.  The rate making dynamics thus result in other, poorer customers seemingly subsidizing the richer customers who have made the choice for rooftop solar.  This seems inequitable to some.
  • The growth in rooftop PV has outstripped the loads on some distribution feeders, with reports that the generation capacity has sometimes reached three times the load on the feeder.  These loading levels cause operating problems in the form of high voltages and excessive line losses.  During periods of high voltage and excessive line loss, prices can provide an incentive for consumers to modify their behavior.  The genie seems to be out of the bottle in regard to allowing the utility to exert direct physical control over PV solar, but real time prices could provide some economic control in place of the tradition utility command and control approach.

I have discussed the need for real time pricing of the use of the distribution grid in “Net Metering:  Identifying The Hidden Costs;  Then Paying For Them,” Energy Central, 2013September 20.[5] I have described a method in “Dynamic ‘Distribution’ Grid Pricing.”[6]

Changes in state regulations have also impacted this balance between labor costs and automation costs.  Some states now have performance incentives based on the number of outages and the typical restoration times.  The cost associated with the time of sending a line crew to close a circuit breaker now competes with the incentives to get that closure faster, through the use of automation.

In conclusion, the increase in utility automation is not so much innovation as it is a continuation of the historic utility practice of the economic substitution of lower cost technology for the ever increasing cost of labor.  The 1978 change in federal law led to the growth of ISOs and bulk power markets, but did not reach down to the distribution level, perhaps of the lack of non-utility industrial support.  The growth in rooftop PV will provide the incentives for expanding the real time markets down the distribution grid to retail consumers.  Though computers indeed have gone from 1.0 (vacuum tubes), to 2.0 (transistors), to 3.0 (integrated circuits), I don’t see the current changes proposed for utilities to be much more than following the competition between labor costs and automation costs.  We are still Utility 1.X, not Utility 2.0.



[1] Supervisory Control And Data Acquisition.

[2] Public Utility Holding Company Act of 1935

[3] Public Utility Regulatory Policies Act of 1978

[4] Independent System Operator

[6] A draft of this paper is available for free download on my web page, www.LivelyUtility.com

A Romp Through Restructuring

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

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

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

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

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

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

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

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

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

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



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

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

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

The Electric Transmission Grid and Economics

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

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

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

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

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

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



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

NCAC-USAEE Overnight Field Trip of 2013 October 4-5

Friday and Saturday I went on a overnight bus trip with NCAC-USAEE to visit energy facilities in Western Pennsylvania and Maryland.  The trip included a visit to the Conemaugh coal fired generating plant near Johnstown, PA, the EDF Renewable Energy Chestnut Flats wind farm near Altoona, PA, and a family owned open pit coal mine near Frostburg, MD.  It was wonderful to visit these different technologies, seeing how they work, and getting some quality time with other people interested in the topic of energy economics.

The National Capital Area Chapter (NCAC)of the US Association for Energy Economics (USAEE) is one of the largest chapters of USAEE.  USAEE is in turn one of the largest members of the International Association for Energy Economics (IAEE).  I started attending NCAC meetings in January 2001, was on the NCAC council for 2003-4, treasurer 2005-2011, secretary 2011-2012, vice president 2012-2013, and am now president for 2013-2014.  As president I receive great support from the other council members.  This trip was the result of that support.

Jim McDonnell of Avalon Energy Services has been an NCAC member for about 5 years.  Late this summer he called to tell of a visit he had made to an open pit coal mine in Western Maryland, suggesting it might be a good place for an NCAC field trip.  Rodica Donaldson, NCAC secretary, of EDF Renewable Energy had mentioned during the July NCAC council meeting the possibility of a field trip to a wind farm.  I introduced Jim and Rodica and the next thing I knew they had plans to combine those two field trips with a field trip to a coal fired power plant and we were off for an overnighter.

During the bus ride Friday morning to Conemaugh, the 20 people on the tour introduced ourselves.  We included two current officers of NCAC, two past presidents of NCAC, and a vice president of IAEE, who currently lives and works in the DC area.  Sarah McKinley, an NCAC past president, of the Federal Energy Regulatory Commission was one of the last people to introduce herself.  She told of the open meetings at FERC that facilitated discussions, including the meeting of the Asian Pacific Electricity Regulators (APER) forum 2012 August 1-2.  She told the group that I had attended the APER conference as a member of the public.  Sarah and I talked the rest of the ride to Conemaugh.

My memory of the APER forum included having lunch with two members of India’s Central Electricity Regulatory Commission (CERC), including its chairman.  During the two days prior to the conference, on July 30-31, the Indian electric grid had suffered two huge blackouts, which were highly publicized.  Sarah remembered the two CERC commissioners being interviewed by the press about the blackouts.  My view of the blackout was that India had an overly constrained market mechanism for unscheduled flows of electricity.  A less constrained market would have provided larger incentives for actions that might have prevented the blackout.  I had even written a blog entry on that issue.[1]

In 1998, I became a pen pal through IEEE’s PowerGlobe with Bhanu Bhushan, the principal architect of the Availability Based Tariff (ABT) which in 2002 began to govern wholesale transactions in India.  Bhanu and I visited over dinner in both 1999 and 2001 when he came to Washington, D.C.  He gave me his papers supporting the ABT concept including its provision for pricing Unscheduled Interchange (UI).  A pricing vector sets the UI price every 15 minutes based on the average frequency variation experienced during that 15 minute period.  The UI pricing concept was quite similar to my Wide Open Load Following (WOLF) concept, in that WOLF also sets a price for unscheduled flows of electricity based on concurrent frequency variation.  Just as he shared his private papers on UI pricing, I gave Bhanu some papers I had published on WOLF.  As suggested by the full name of Wide Open Load Following and by the WOLF acronym, the UI pricing mechanism is very constrained relative to the prices that WOLF can produce.

In 2003 January, after UI pricing became active, Bhanu introduced me to InPowerG, an Internet e-mail group of electric power engineering professionals, generally from Indian industry and academia. The group is currently administered by the Power Electronics and Power System group, Electrical Engineering Department, IIT-Bombay and has more than 500 subscribers.  Bhanu’s introduction of me to InPowerG was in regard to an extended discussion of UI pricing, with some people strongly opposed to the concept.  I ended up adding comments providing theoretical support of UI pricing.[2] Though I fault UI pricing as being overly constrained, especially in comparison to my WOLF, I note that the US has no mechanism for pricing the unscheduled flows that brought down the US grid in 2003.[3]

Conemaugh is an 1800 MW power plant near Johnstown, PA, with two 900 MW units.  Conemaugh’s low cost has generally resulted in it being operate 24×7 at full load.  The expanded PJM market place has changed sufficiently to provide incentives for Conemaugh to cycle down at night.  Its operators have made major modifications to allow each unit to have a minimum load of about 380 MW.  I was impressed that the ball mills used to crush limestone for the scrubbers are generally operated off-peak.  The plant has sufficient storage for crushed limestone that the operators shut down this major parasitic load during the day, moving the parasitic load to the night.

One of our tour members subsequently ascribed the need for cycling to the growth of wind during the night.  I question attributing the need for cycling solely to wind since PJM has also experienced a huge shift in load patterns, with many fewer major loads, such as steel mills, that used to operate 24×7.  For instance, the river passing Conemaugh used to be reddish orange from the run-off at Johnstown Steel a few miles upstream.  Now the steel mill is gone.  I imagine that the shift in load shape could be having as big of an effect as the growth in wind.  Accordingly, I say that the jury is still out on the cause of the need for increased cycling of coal fired power plants.  I prefer to think that the cause of increased cycling is the increased transparency of the diurnal price of electricity, independent of the cause of that diurnal aspect of prices.

Another tour participant commented on the very large investment being made at Conemaugh to handle new environmental concerns, both NOX’s and mercury.  His analysis was that the investment is in excess of the original cost of the plant, at least according to his estimates.

EDF Renewable Energy’s Chestnut Flats wind farm is near Altoona, PA.  Seeing the wind mills operate up close, I could image Don Quixote tilting at wind mills in the 1605/1615 classic or the attack of the Martian machines in H.G. Wells “War of the Worlds” radio broadcast of 1938.  I have a blog entry combining Don Quixote and Robin Hood in regard to a proposal last year to mandate Maryland customers paying for off shore wind, which is an expansion of my “Letter to the Editor” published by The Washington Post.[4]

The output of Chestnut Flats is sold to Delmarva Power at a flat energy price.  There is no seasonality nor diurnal incentives, just that maintenance could not be planned during the summer.  After all, the summer is the high price period for PJM.  The SCADA system is operated in Spain, home to the company that provided much of the equipment and has the contract to provide operations and maintenance.  The Spanish company normally has three workers on site.  EDF Renewable Energy’s field manager at Chestnut Flats does have access to the SCADA information.  The SCADA system includes the ability to feather the blades after 6 seconds of continuous excessive wind speeds.

Our bus parked in the wind shadow of one of the wind mills.  Most of the time that we stood there I did not notice the noise created by the wind mills.  But when I thought about it, I could pick out a sound that I realized was the action of the blades.  The local township has zoned Chestnut Flats as residential, though the closest house is about 1200 feet from a tower.  A result of the residential zoning is that rain runoff ponds must be encircled by fences to protect children from drowning hazards.  But with the nearest house being 1200 feet from one of the towers and the land being fenced and at the top of a ridge, the zoning requirements seem excessive.  EDF Renewable Energy’s field manager very much accepted the regulations, providing very matter of fact responses to our questions, much like the old Dragnet line, “Just the facts, Ma’am, just the facts.”

The field manager had no impression that the wind was stronger during the night versus during the day.  His experience was that there was no significant difference.   Again, “just the facts” as he saw the facts and his personal observation of the movement of the wind mills.

On Friday morning we visited a family owned open pit coal mine near Frostburg, MD.  The owner described buying about 180 acres for his home so he could be away from everyone and then deciding to dig up coal from the abandoned drift mine about 100 feet under his property.  The entrance to the drift mine was about one mile away from the pit into which we walked.  Thus, the old underground miners eventually had to walk a mile into a hill side to get to the coal.  Initially the underground miners would have chipped at the coal at the hill side and then went deeper into the hill side to get to the remaining coal.  At the greatest extent, the walk was about a mile into the hill, at least for the underground mine.  Now, the mine was a pit 100 feet deep.

The owner had preserved, perhaps only temporarily, an area that included two wooden rails that had been used about 200 years ago to move coal cars into and out of the mine.  In the early 1800’s, miners would pull wagons into the mine, at an upward slope, through the coal seam to the face at which they were working.  The loaded wagons could almost drift down the rails to the exit.  Thus, empty coal cars were pulled up hill into the mine and loaded coal cars were pulled down hill out of the mine.  Jim McDonnell had given another explanation for working at an upward slope.  Water could not run upslope to fill the mine and did not need to be pumped out.  Both explanations work for me.

One of the mine workers seemed to express surprise that our group from Washington was “pro” coal, making the comment to Andy Knox, the other NCAC past president on the field trip, who works on energy projects for the Navy.  I didn’t hear Andy’s response but the worker’s comment led me to think that I am not “pro” coal, since that would imply that I am “anti” some other source of electricity.  Rather, I am “pro” keeping the lights on at the lowest reasonable cost to consumers.  As an engineer, I have learned that diversity of supply is generally good.  Having all wind, all nuclear, all gas, or all coal would make the electric system subject to great stress during political or environmental upheavals, such as has occurred in regard to nuclear, wind, coal, and gas.  Thus, I personally am “pro” diversity.  If NCAC is “pro” anything, NCAC is “pro” an open discussion of the issues.

The trip back to Washington, DC, on Saturday from Frostburg included a stop at Sideling Hill, where I-68 goes through a manmade notch in a ridge.  Jim McDonnell is a geologist and had provided material on synclines (which look like a bowl) and anticlines (which look like an inverted bowl) that resulted in the folding of the earth’s crusts millions of years ago.  Sideling Hill is at a sharp syncline, showing dozens of strata in the manmade notch.  The upward slope of the strata in the syncline suddenly stopping on both sides of Sideling Hill, which is only obvious because of the manmade notch, is quite impressive.  That Sideling Hill is at such a sharp syncline shows the impressive results of erosion, in that the notch is several hundred feet about the base of the mountain.  The implication is that huge amounts of the upper portion of the syncline bowl had been washed away.  What was left, as revealed in the manmade notch, was a narrow bottomed bowl that had layers of different types of rocks stacked in its center.

For me, an important part of the field trip was the interaction with the other participants.  Some of that is described above in regard to my discussion with Sarah McKinley and hearing the questions asked by various parties, including the mine worker’s comment.  Andy Knox also talked about his personal experience of becoming a net zero energy household.  He has installed enough solar cells that he often has a surplus and exports electricity to the grid.  He believes he has enough solar power to offset not only the energy he takes when solar production is low but also to compensate for the gas he burns in his range.  Recently, the gross generation from the solar cells has become enough that he was able to sell a REC, or a Renewable Energy Credit, for the 1 MWH he has generated to date.  I believe that Andy has an impressive story to tell.

Pictures from the field trip are being posted to the NCAC web site.[5]  Jim McDonnell has already submitted his photos and I saw many other people with cameras.  We expect to have an article published in the next issue of USAEE’s Dialogue.  I hope that some of the other participants on field trip will add comments to this blog or that I can include their comments in the Dialoguearticle.  There is enthusiasm for another field trip, which NCAC had already been planning for the spring in the Philadelphia direction.  One participant expressed interest in a field trip dealing with the use of electricity, such as at a steel mill or an aluminum plant, which the Philadelphia trip would do only partially.  Another participant said he had contacts in the steel and aluminum industry and might be able to arrange such a trip.  Maybe more later.



[1] Economic Failures Contribute to Indian Grid Blackouts, Posted on 2012 Aug 06 by Mark Lively, http://www.livelyutility.com/blog/?m=201208

 

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

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

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

[5] NCAC-USAEE.org

Price Pressure on Input Capital Costs

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

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

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

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

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

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

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



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

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