Risks of Going Solar

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The 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.

Energy Interchange Markets–Often Designed to Fail

I participated on the NAESB IIPTF[1] while it met during 2003-2005.  I argued then that there should be a cash payment for inadvertent interchange and that the cash payment should be differentiated over time and across geography.[2]  About the same time I participated in the InPowerG discussion of ABT pricing of UI[3], making similar arguments.[4]

My concern before the IIPTF was that parties could game the market.  First the party could buying cheap electricity upstream of a constraint.  The party could then sell expensive electricity downstream of the constraint.  The party could then arrange a cheap but ineffectual parallel path around the constraint.  This issue was described in the title of my first published article[5] some 15 years earlier.

Most other markets would look at a set of transactions as forms of efficiency inducing arbitrage.  The purchases would raise the price in the cheap markets.  The sales would depress prices in the expensive market.  The transportation agreement would raise the price of transport, further lowering the price differential between the high priced area and the low priced area.  But, the rigid terms of most tariffs just produced a profit for those entities willing to operate in this shadowy market.  The name Enron evokes such shadowy images, especially when paired with the CaISO[6].

But CaISO was not the only advanced market that found itself subject to such arbitrage.  PJM suffered some of the same loop flow issues when Midwest generation contracted with AEP and VEP, effectively moving electricity south around the PJM internal constraints between low cost Pittsburgh and the high cost Washington/Baltimore area.  PJM provided a similar southern loop for marketers in New York, who bought cheap electricity at the Niagara frontier, moved it west and south and back east toward the New York City area.

In recent years, FERC has been advocating Memorandums of Understanding that create Energy Imbalance Mechanisms.  I believe these MOUs and EIMs will fail to improve the system, and could contribute to problems on the network unless the associated cash outs use geographically differentiated prices.  For instance, the disastrous 2012 July 30 & 31 blackouts in India have been attributed to the lack of geographic differentiation in India’s energy imbalance mechanism[7].  Customers and generators downstream of the constraint faced the same price (once high, once low) as customers and generators upstream of the constraint (again, once high, once low). [8]

From the discussions I have heard about the MOUs and the EIMs, they seem to be designed to fail, not learning from the experience in India of a similar pricing mechanism, ABT pricing of UI.  The MOUs and the EIMs need to price the energy imbalances on a geographically differentiated basis with a price that changes automatically with the spot conditions.

 



[1] North American Energy Standards Board Inadvertent Interchange Payback Task Force

[2] At least one party criticized my approach because I generally used an exponential formula, which nominally prevented the price from going negative.  My research for “Renewable Electric Power—Too Much of a Good Thing: Looking At ERCOT,” Dialogue, United States Association for Energy Economics, 2009 August, convinced me that negative prices could sometimes be appropriate.  Accordingly, I have recently used a hyperbolic sine as and a price adjustment factor.  The hyperbolic sine is the difference between two exponential formulas, one with a positive exponent, the other with a negative exponent.  See http://livelyutility.com/documents/USAEE-ERCOT%20Aug%2009.pdf

[3] Availability Based Tariff and Unscheduled Interchange

[4] http://abt-india.blogspot.in/2007/10/windpower-discussion-on-inpowerg.html for a partial digest of those discussions.

[5] “Tie Riding Freeloaders–The True Impediment to Transmission Access,” Public Utilities Fortnightly, 1989 December 21.

[6] California Independent System Operator

[7] See my blog http://www.livelyutility.com/blog/?p=135, which includes two separate comments added by Soonee, the CEO of the Indian grid operator.

[8] The price differential issues included reactive power generation and usage.  India’s ABT has a section that prices reactive energy, but not sufficiently to induce better responses from generators and loads.

Economic Failures Contribute to Indian Grid Blackouts

On 2012 July 30 and July 31, India experienced massive blackouts on its electricity grid. The first blackout was early in the morning of July 30 and affected only the Northern Region. The second failure was at midday on July 31 and affected the Northern Region, the Eastern Region, and the Northeastern Region. The Western Region, though interconnected with the Northern, Eastern, Northeastern Region in the NEW Area, survived, as did the Southern Region, which is not interconnected synchronously with the NEW Area.

Various comments have been made about the events that led up to the blackouts. This blog entry will only discuss some failures of the economic systems that contributed to the blackouts.

 

Prices of Inadvertent Didn’t Reflect Security Issues, That Is, No Locational Marginal Prices

Beginning in 2002, India implemented its Availability Based Tariff (ABT) that included the creation of a market for imbalances, Unscheduled Interchange (UI).  ABT pricing of UI has a geographically uniform price.  I said early on that the price in areas that could be at risk of a blackout due to a power deficit after a transmission failure should have higher prices than other regions, those that have a power surplus.

Other pundits have suggested that utilities in the Northern Region ignored operators’ requests to reduce load because the energy price was low enough, that there were no economic consequences of taking too much electricity. The economic system failed the Indian electric network by not providing sufficient monetary pain for ignoring operators’ request.

A rigorous locational pricing plan could have produced that monetary incentive. I have not heard that all of the NR utilities were drawing more power than the amount which had been scheduled. A feature of ABT pricing of UI is an incentive for some utilities to draw less power than the amount which has been scheduled, not just for utilities to reduce their draw to the scheduled amount. Thus, a locational pricing plan would have led to some NR utilities to under draw and help stabilize the system.

 

High Inadvertent Prices Could Not Incent Backup Generators to Assist the Grid

Customer owned back up generators can do double duty. The standard use of a back up generator is providing electricity to the owner when there is a rotating blackout that affects the owner. When rotating blackouts are not affecting the owner, stand by generators can provide electricity to the grid when the value of electricity on the grid is high enough to pay for the fuel cost of the back up generator.

This second use of back up generation requires

  • the back up generator being able to operate synchronously with the grid; and
  • metering to identify the amount of energy provided to the grid to displace the high value UI power that the utility would otherwise be purchasing on a real time basis.

 

Power Deliveries to Farmers Aren’t Structured so Farmers Can Help Save the System

Indian farmers do not participate in the market for electricity, generally receiving several hours of free service. Giving Indian farmers a fixed subsidy would allow them to participate in the UI market for the number of hours they need for electricity. This would give the farmers incentives to help the system when there is a larger shortage of electricity. From the farmer’s perspective, the farmer would be able to use electricity for more hours since the average price could be cheaper than that upon which the subsidy was predicated.