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.

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.

“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.

Getting the Smart Grid to Make Sense

For the smart grid to make economic sense, we need a way to pay for it by reducing the cost of generation, as well as the cost of wires, not just increase the cost of wires by the investment in the smart grid. There has to be some cost offsets. To accomplish those cost offsets, we need to change the load profile of the customers behind the meter, the cash register of the electric system. To change that load profile means we must give the customers economic incentives, which means changing the prices that are being charged to the customer. Yes, that means higher prices when things are going bad, but also lower prices at other times, including some times when things are going so well that they are going bad.

How can there be too much of a good thing such that “things are going so well that they are going bad?” I wrote of that in “Renewable Electric Power—Too Much of a Good Thing: Looking At ERCOT,” Dialogue, United States Association for Energy Economics, 2009 August. Prices for electric generation in the “wind patch” of West Texas were negative for about 25% of the month of April 2009. Things got so good, with so much wind, that things got bad, with prices that seem so unusual. And it need not just be the “wind patch” of West Texas where there is too much power. If my neighbor puts in a 1 MW wind mill in my residential neighborhood, that will overload the wires and cause too much of a good thing, as I wrote in “Microgrids And Financial Affairs,” Industrial Fuels and Power, January 2008.

The same concept applies to charging electric vehicles, as I wrote in “Dynamic Pricing: Using Smart Meters to Solve Electric Vehicles Related Distribution Overloads,” Metering International, Issue 3, 2010. This article was my response to a pro-EV group which wrote

In a study conducted by EPRI, plugging in just one plug-in hybrid electric vehicle (PHEV) to charge at 220 V overloaded 36 of 53 transformers examined during peak hours and five of 53 transformers during off-peak hours. It is, therefore, important to identify where GEVs are parked and charged so that utilities can make the upgrades necessary to maintain reliable service. (Electrification Roadmap, November 2009, p. 102, emphasis added)

2010 World Energy Outlook by International Energy Agency

Yesterday, December 3, I went to the International Energy Agency’s presentation of its 2010 World Energy Outlook in Washington, D.C.  I ended up with two takeaways, a claim that the demand for petroleum was less price-responsive than it had been and a claim about the huge fossil fuel subsidies being provided around the world, especially by those governments that are major exporters of fossil fuel.  Iran was identified as the leading “offender.”  These takeaways were reinforced after the presentation in talking with people I knew in the audience.

I mentally challenged the issue of a lowering of the price responsiveness of petroleum demand.  During the great petroleum price spike of 2008, the US made a political decision to finish filling the Strategic Petroleum Reserve.  This political decision was likely to distort any estimation of the price responsiveness of petroleum demand.  This was part of the reason I mentally challenged the claimed lowering of the price responsiveness of petroleum demand.  As an aside, two days earlier a friend had commented about testifying against the decision to finish filling the SPR, so that nugget was in my mind.  Also, I remembered a presentation about that time that China had also been making political decisions during the same time period that could have influenced the demand for petroleum further distorting the price responsiveness of petroleum demand.

I believe that the use of storage has a major impact on the price of commodities, whether the petroleum discussed specifically in this blog entry, or natural gas, electricity, and wheat.  I remember the Soviet agricultural crisis in the 1970s (?).  The federal government allowed the Soviets to export US wheat in large quantities.  Our wheat storage was full, almost overflowing.  Too late it became known that much of the wheat in storage had already been bought by the Soviets, who just needed the export licenses.  The wheat prices soared once people realized that the wheat in storage was not owned by domestic speculators but was owned by the Soviets intent on exporting the wheat.  Thus, I am sensitive to the amount of a commodity in storage, as well as the amount going into and out of storage, in determining the price of the commodity.  And when those decisions on storage are political, should that be considered a change in the price responsiveness of demand?

After the presentation, an Iranian I know came up to me quite incensed.  He said that the claimed decline in the price-responsiveness of petroleum was in conflict with the call for Iran to reduce the “subsidies” for fuel.  Further, they had the numbers wrong. 

  • If indeed the demand for petroleum is not price-responsive, why would a government’s decision to subsidy the price of petroleum products matter, such as in Iran.  His argument seems correct, at least if the concept of a decline in price-responsiveness had finally reached zero, which had not been the claim of the IAE, at least not that could be determined from the presentation.
  • IAE said that the price of gasoline in Iran was $0.08/liter.  The Iranian claimed the price was almost 40% higher, $0.11/liter.  In English units, these prices would be about $0.31/gallon and $0.40/gallon, perhaps an eighth of the price of gasoline in the US and much less than a tenth of the price of gasoline in Europe.  He didn’t seem to mind that his quibbling was about a factor of 1.4 when others were talking about factors of 8 or 10.

We also talked about “smuggling,” people buying tanker trucks full of gasoline in Iran (whether at the $0.08/liter price of the $0.11/liter price was irrelevant) and selling the gasoline across the Turkish border.  I thought that the transfers of a legal commodity across the border made sense, in that it should reduce the price of gasoline in Turkey, or at least that region of Turkey, and raise the price of gasoline in Iran, at least in that part of Iran.  The Iranian’s ire seemed to be directed toward the concept of violating government policy, one of not exporting gasoline from Iran, or at least not allowing small entrepreneurs to make money from the practice.  I guess his point was that the practice should be limited to licensed vendors.

This week Iran had shut down most of Tehran on three different days because of severe pollution, nominally caused by gasoline driven cars.  Shades of Los Angeles, Denver, and parts of China.  Eliminating the Iranian gasoline subsidies would reduce driving in Iran, including Tehran, at least if the IEA claim of reduced price sensitivity could be ignored.

During the presentation on subsidies, I began to wonder how subsidies should be defined.  My work on utility rate cases would often identify subsidies as relating to paying one’s fair share of the cost of the operating the utility.  Fair share included subjective decisions about cost allocations, so there were debates as to whether industrial customers were subsidizing residential customers or vice versa.  But these debates had as an underlying premise that the measurements were to be relative to the cost actually incurred by the utility.  Under that mind set, was the Iranian government recovering all of the cost it incurred in producing oil?  Yes, the world price for gasoline was much higher than the Iranian price, but did the enterprise as a whole lose money?

I have heard that Iran is currently considering raising the price of gasoline and of other energy supplies.  The revenue generated by this process would be used to provide Iranians with cash.  One thought is that the cash would be distributed equally per person, much as Alaska distributes cash to its residents from the taxes on oil production.  Last Wednesday, another friend had said that beneficiaries of the very low gasoline prices were those few Iranians driving huge gasoline guzzling SUVs.  Thus, the reform of gasoline prices, when coupled with an Alaskan style distribution, would hurt a few, the owners of the gas guzzlers, and benefit many, anyone who doesn’t own a car and uses little energy. 

The conversation about Turkey and the huge price differential between Turkish gasoline and Iranian gasoline made me think about the people who would really be severely hurt by an increase in Iranian gasoline prices, the smugglers.  It would make sense for them to be very adamant about keeping the status quo, much as the illegal gambling industry sought to prevent legislation legalizing sports gambling in the Bruce Willis movie The Last Boy Scout.

The IEA discussion about subsidizing fossil fuel commodity prices left undiscussed other subsidies that exist in the energy industry.  In the electric industry, renewable resources are heavily subsidized, whether by the tax credits offered by various governments, the renewable portfolio standards of various US states, or the feed-in tariffs that exist in many European countries.  My concern as an electrical engineer is that such subsidies are making the supply of electric energy to be less price responsive than it had been, perhaps even more so than the effect on the demand for petroleum.  Last year I looked at the prices paid for electricity generated in ERCOT, the Electricity Reliability Council Of Texas.  (See “Renewable Electric Power—Too Much of a Good Thing: Looking At ERCOT,” Dialogue, United States Association for Energy Economics, 2009 August available for free download on my web page.  Just register your name and data.)  For a quarter of the month of April 2009, the prices in West Texas, with a lot of renewable generation, were negative.  The wind generators had to pay ERCOT to take the electricity off their hands.  And the negative prices reached Houston for about 1% of the month.

The concept of negative prices in juxtaposition to the concept of subsidies leads to the issue of taxes on energy, essentially negative subsidies.  These negative subsidies have led to very high gasoline prices in Europe, though according to the IEA less sensitivity to price analysis, these high gasoline prices are no longer restraining the consumption of gasoline in Europe. 

I wonder!?