Did ERCOT’s shift from zonal to nodal market design reduce electric power prices?

Jay Zarnikau, C.K. Woo, and Ross Baldick have examined whether the shift from a zonal to nodal market design in the ERCOT power market had a noticeable effect on electric energy prices. The resulting article, published in the Journal of Regulatory Economics, and this post may be a bit geekier than we usually get around here. I’ll try to tone it down and explain the ERCOT change and the effect on prices as clearly as I can.

The topic is important because the shift from zonal to nodal market structure was controversial, complicated, expensive, and took longer than expected. Problems had emerged shortly after launch of the initial zonal-based market and the nodal approach was offered as a solution. Some market participants had their doubts, but rather quickly ERCOT began the move to a nodal design. Note that phrasing: “rather quickly ERCOT began the move.” It took several years for ERCOT to actually complete the process.

In part the shift was promoted as a more efficient way to run the market. Zarnikau, Woo, and Baldick looked at the effect on prices as one way to assess whether or not the resulting market has worked more efficiently. They conclude energy prices are about 2 percent lower because of the nodal market design.

Don’t get hung up on the 2 percent number itself, but think of the shift as having a modest downward pressure on prices.

The result is consistent with an understanding one would gain from the study of power systems engineering as well as with what power system simulations showed. The point of the Zarnikau et al. study was to investigate whether data analysis after the fact supported expectations offered by theory and simulation. Because there is no better empirical study (so far as I am aware) and because their results are consistent with well-founded expectations, I have no reason to doubt their result. I will contest one interpretation they offer concerning the current resource adequacy debate in Texas.

Some background (which beginners should read and others can skip).

The delivery of electric energy to consumers is a joint effort between the generators that create the power and the wires that bring it to the consumer. The wires part of the system are not simple links between generators and consumers, but rather complicated network of wires in which consumers and generators are connected in multiple ways. The added flexibility that comes with networking helps the system work more reliably and at lower cost.

The network also comes with a big coordination problem, too. Power flows on the network are not individually controllable. With many generators producing power for many consumers, parts of the power grid may become overloaded. One key job of the power system operator is to watch the power flows on the electric grid and intervene as needed to prevent a transmission line from being overloaded. The intervention generally takes the form of directing a generator (or generators) contributing to the potential overload to reduce output and directing other generators to increase output. In areas outside of regional system operators, this function is done on a piecemeal basis as problems arise. A significant benefit coming from full-scale regional power markets integrated with system operations (such as ERCOT in Texas after the switch to a nodal market and in other similar ISO/RTO markets) is that such coordination can be done in advance, with more information, mostly automatically, and more efficiently than piecemeal adjustments.

Described in simpler terms, the regional power system operator helps generators and consumers coordinate use of the power grid in the effort to efficiently satisfy consumer demands for electric energy. A zonal market design, like ERCOT started with, did minimal advance coordination. The nodal market design and related changes implemented by ERCOT allowed the market to do more sophisticated and efficient coordination of grid use.

About data challenges.

In order to assess the effects on prices, the authors couldn’t simply average prices before and after the December 1, 2010 change in the market. The power system is a dynamic thing, and many other factors known to affect electric power prices changed between the two periods. Most significantly, natural gas prices were much lower on average after the market change than during the years before. Other changes include growing consumer load, higher offer caps, and increasing amounts of wind energy capacity. In addition, the prices are generated by the system has been changed, making simple before and after comparisons insufficient. For example, rather than four zonal prices produced every 15 minutes, the nodal market yields thousands of prices every 5 minutes.

One potentially significant data-related decision was a choice to omit “outliers,” prices that were substantially higher or lower than usual. The authors explain that extreme price spikes were much more frequent in 2011, after the change, but largely due to the summer of 2011 being among the hottest on record. At the same time the offer caps had been increased, so that prices spiked higher than they could have before, but not because of the zonal-to-nodal market shift. Omitting outliers reduces the impact of these otherwise confounding changes and should produce a better sense of the effect of the market change during more normal conditions.

Their conclusion and a mistaken interpretation.

Zarnikau, Woo, and Baldick conducted their price analysis on four ERCOT sub-regions separately so as to see if the change had differing impacts resulting from the changeover. The West zone stood out in the analysis, largely because that zone has seen the most significant other changes in the power system. The two main changes: continued sizable wind energy capacity additions in the zone, and more substantially, dramatic electrical load growth in the region due to the recent oil and gas drilling boom in west Texas. Because the West results were a bit flaky, they based their conclusions on results from the other three zones. Across a number of minor variations in specifications, the authors found a price suppression effect ranging from 1.3 and 3.3 percent, the load-weighted average of which is right around 2 percent.

So far, so good.

But next they offered what is surely a misinterpretation of their results. They wrote:

[T]he reduction in wholesale prices from the implementation of the nodal market might be viewed by some as a concern. In recent years, low natural gas prices and increased wind farm generation have also reduced electricity prices in ERCOT which has, in turn, impaired the economics of power plant construction. … It appears as though the nodal market’s design may have contributed to the drop in prices that the PUCT has now sought to reverse.

Strictly speaking, the goal of the Public Utility Commission of Texas hasn’t been to reverse the drop in prices, but to ensure sufficient investment in supply resources to reliably meet projected future demand. Lower prices appear to be offer smaller investment incentives than higher prices, but there is a subtle factor in play.

The real incentive to investment isn’t higher prices, it is higher profits. Remember, one of the most important reasons to make the switch from a zonal to a nodal market is that the nodal market is supposed to operate more efficiently. Zarnikau, Woo, and Baldick notice that marginal heat rates declined after the shift, evidence consistent with more efficient operations. The efficiency gain suggests generators are operating at an overall lower cost, which means even with lower prices generator profits could be higher now than they would have been. It all depends on whether the drop in cost was larger or smaller than the drop in prices.

The cost and profit changes will be somewhat different for generators depending on where they are located, what fuel they use, and how they typically operated. I’ll hazard the guess that relatively efficient natural gas plants have seen their profits increased a bit whereas less efficient gas plants, nuclear plants, and coal plants have likely seen profits fall a little.

FULL CITE: Zarnikau, J., C. K. Woo, and R. Baldick. “Did the introduction of a nodal market structure impact wholesale electricity prices in the Texas (ERCOT) market?.”Journal of Regulatory Economics 45.2 (2014): 194-208.

Here is a link to a non-gated preliminary version if you don’t have direct access to the Journal of Regulatory Economics.

AN ASIDE: One modest irony out of Texas–the multi-billion dollar CREZ transmission line expansion, mostly intended to support delivery of wind energy from West Texas into the rest of the state, has turned out to be used more to support the import of power from elsewhere in the state to meet the demands of a rapidly growing Permian Basin-based oil and gas industry.

Texas wind power, the ERCOT power market, the Public Utility Commission

From SNL Energy, “Texas utility regulators expect to open investigation on wind ‘cost apportionment’“:

Having seen record wind output of more than 10,000 MW in March, ERCOT in the report also noted that Texas has gone well beyond its 10,000-MW capacity goal and far earlier than the 2025 target established in the state’s Public Utility Regulatory Act. …

And while wind energy continues to boom in Texas, the PUCT has been working with ERCOT on ensuring a reliable power grid amid wholesale prices that are not encouraging new fossil-fuel plant construction.

Perhaps, just perhaps, there is a connection between the “wind energy … boom” and the “wholesale prices that are not encouraging new fossil-fuel plant construction”?

The SNL Energy report noted the PUCT was beginning an investigation into cost apportionment issues surrounding wind energy and the recently completed CREZ transmission line additions.

Smart shopping for electric power just got easier in Houston

Michael Giberson

CenterPoint Energy, the Houston-area electric distribution company, has launched MyTrueCost.com to help area retail electric customers shop for electric power. Help may be needed: currently 43 companies offer a total of 239 different service options in the CenterPoint service territory according to data from Powertochoose.org, the Texas PUC’s retail power website.

The basic idea is pretty simple: customers sign up, TrueCost accesses their smart-meter based electric power consumption data and estimates bills, the customers provide some information on the kind of retailer and contract they want (low price, environmental characteristics, number of PUC complaints, years in service, etc.), and then the website identifies the contracts that appears most suited to the customer.

TrueCost doesn’t search through all possible contracts, however, just contracts from the several retailers that have agreed to participate. Currently 10 of the 43 companies in the area are participating. Customers should be aware that TrueCost gets paid a flat fee by the retailer for each customer that signs up through the service. (TrueCost noted in the Q&A that the flat fee means that the service doesn’t have an incentive to upsell customers to more costly contracts.)

Simple. Smart. Cool. (And speaking of cool, the young people of Houston would like you to know that a Forbes real estate blogger has named Houston the #1 on its list of America’s Coolest Cities to Live.)

By the way, TrueCost also charts average retail power prices offered in Texas’s competitive retail power markets and provides commentary in an accompanying blog.

One-year plans keep momentum from summer price spike

One-year plans keep momentum from summer price spike (July 5, 2012)

INVITATION: If any of our Houston area readers have tried out MyTrueCost, send me an email and let me know what you think. My email address can be found here.

Hayek’s knowledge problem as an issue in electric power market design

Michael Giberson

Recently the Brattle Group submitted a study of resource adequacy issues within the ERCOT power system and the policy options available to ERCOT and the PUC of Texas, the regulatory authority overseeing the ERCOT system. As the Brattle report points out, ERCOT has so far stuck with a so-called “energy-only” market design while the other RTO markets have implemented some form of capacity markets to help assure the market will be adequately supplied with generating resources.

The Brattle report is available from the ERCOT website. The PUCT is taking comments on the report in Project No. 40480, “Commission Proceeding Regarding Policy Options on Resource Adequacy.” A workshop will be held to discuss the Brattle recommendations on July 27, 2012 at the PUCT offices in Austin.

BP Energy Company finds Hayek’s knowledge problem as a key issue in electric power market design. After quoting a segment from “The Use of Knowledge in Society,” BP Energy Company writes:

Hayek’s “Knowledge Problem” and its optimal solution – decentralized commercial markets – provide the best lens for regulators to see the fundamental issue in electricity market design in response to rapid technological change and increasingly diverse groups of willingly innovative buyers and sellers. As the procurement and use of electricity cross a complexity threshold, as a few customer classes are transformed into a multitude of individual market participants, electricity market design needs to move away from centralized planning to a decentralized procurement of resources, to be both sustainable and efficient in meeting the resource adequacy objectives for the bulk power system and society at large.

The unwieldy process of centralized procurement of resources in the organized markets within the Eastern Interconnection is not proving to be a healthy evolution for electricity markets; instead, these interventions have greatly interfered with the natural development of networks among market participants that can lead to a healthier market ecosystem. Utility economist Kenneth Rose, in a recent working paper that highlights the continuing problems of centralized procurement in the capacity mechanisms in the Eastern Interconnect, reprises the “Knowledge Problem” in the following analysis:

“…. They (RTOs and regulators) are attempting to create a final product market for something that is merely one input of many that are needed to generate electricity.

This may explain why the capacity construct that the RTOs are using has become so complex. Every aspect of the capacity market design has to be redesigned and readjusted to fit changing conditions, rather than allowing the market participants to adjust to market information over time, as happens generally in competitive markets…..

The complex mechanism of capacity markets is not self-sustaining since the RTOs and regulators will need to continuously update and fix the apparatus as conditions change…. A truly competitive market, in contrast, changes as circumstances change, without the stakeholders having to agree on changes and without the regulator having to insert its judgment by choosing and approving what it thinks will work. “

The result is that to date, regulators, not market participants, procure virtually all of new resources. Some of those resources, especially “demand resources,” are poorly designed and have questionable value. Incumbent technologies and business practices are favored over innovative ones, to the ultimate detriment of consumers and local businesses.

As might be obvious by the name of this blog, we at KP find Hayek’s identification of the knowledge problem a key discovery in the long history of the study of markets. It is no surprise that efforts to manage the growth of markets run up against knowledge problem issues, and regulators and other market designers would be wise to consider its significance.

NOTES: Hayek’s article, “The Use of Knowledge in Society,” was published in the American Economic Review (September 1945) (ungated here and here). Rose’s report is “An Examination of RTO Capacity Markets,” IPU Working Paper No. 2011-4, Michigan State University (September 2011). I mentioned the Brattle report on ERCOT resource adequacy issues in this earlier post, see also this earlier post on capacity market issues.

Competitive power market in Texas faces supply concerns. Now what?

Michael Giberson

The question troubling some folks in Texas’s competitive power market: Will Texas consumers want to consume more electric power than suppliers are able to supply? A resource adequacy review by ERCOT, the power system and market operator for most of the state, suggests that consumer demand may outstrip resources available as early as 2014. ERCOT officials have also warned that extreme temperatures this summer could result in reliability concerns, though the most recent review reveals resources will likely be adequate.

The longer-term resource review has attracted a number of media reports, including this morning’s story by Rebecca Smith in the Wall Street Journal, “Power Shortage Vexes Texas: Report Urges Price Increase to Spur Industry to Build More Generating Plants.” See links to other stories at the end of this post.

The “report urging price increases” is that of the Brattle Group, “ERCOT Investment Incentives and Resource Adequacy,” June 1, 2012. ERCOT asked Brattle to study generator investment criteria, the connections between incentives, investments, and resource adequacy, and policy options to support resource adequacy. The Brattle report will bear further study, but for now a few comments about it and the WSJ article.

The newspaper story, following the main thrust of ERCOT’s request and therefore the main part of Brattle’s response, is focused almost entirely on price incentives to potential investors in additional generation resources. The story mentions several of the relevant factors: demand growth, low power prices due to low natural gas prices, ERCOT’s “energy-only” market design, and the lack of significant connections to neighboring grids. The rest of the story plays out as expected: generators say the current offer cap is too low and consumer representatives express horror at the prospect of paying extreme prices to generators who might refuse to expand.  The story entirely misses the possibility that consumers are not complete idiots willing to sit idly by in their air-conditioned palaces and pay 100 times the usual power prices.

Consumers have two easy ways of avoiding any potential $9,000 MWh price: (1) have a fixed price contract with a retailer or (2) simply cut power consumption during pricing peaks. Few consumers actually paid $3,000 MWh last year during February 2011’s few hours of rolling blackouts or the summer’s infrequent emergency conditions. Instead what happened in February and summer 2011 is that retailers who did not secure all of the power their customers wanted by short- or long-term contracts ended up paying the $3,000 price (but just for the additional supplies they needed) AND power generators under contract to supply power who found themselves unable to meet their commitments also ended up paying the $3,000 price (for any committed capacity that they could not deliver). The market risks are divided up between retailers and generators and very little of it is pushed out directly onto the consumer.

Obviously, whatever risks generators take on will be reflected in the prices they’ll seek in contracts with retailers, and whatever risks retailers take on will be reflected in the prices that retailers offer to consumers. But competition among generators to contract with retailers and competition among retailers to sell to consumers should work to do well one thing that the usual rate-regulated monopoly power systems do poorly: competition should shift risks onto the market participant who can most efficiently manage the risks. Consumers typically are not the best able to handle the risks, so competitive markets usually won’t stick them with the risks.

The Brattle report makes a couple of additional valuable points. First, the study assumes only the current level of demand response activity, but additional price-responsiveness on the consumer side of the market would provide additional resource adequacy support. Second, the “1-in-10″ reliability standard typically employed in power systems reliability analyses has rarely been studied from an economic standpoint. The report suggests that overall reliability of delivered power to consumers could be improved and costs reduced by shifting some of the expense away from the bulk power system and toward distribution systems.

So far as I have noticed, the report itself doesn’t recommend a particular policy course, but simply reports on some of the likely advantages and disadvantages of several resource adequacy policy options. The Brattle press release accompanying the report does, however, indicate a clear preference for adding a centralized forward capacity market (similar to that employed by PJM; though note not everyone is happy with PJM’s capacity market).

One last bit of perspective. It is the goal of a resource adequacy study to be excessively cautious. Things probably will not turn out as bad as projected, in part because suppliers, retailers, and consumers will continue to adjust to changing conditions.  But things could be as bad as projected, and that is exactly what the study is intended to highlight.

RELATED:

NOTE: Prices above are all quoted in $ per Megawatt Hour (MWh), a typical price metric for wholesale markets, but consumer bills are usually quoted in cents per kilowatt hour (kwh). Typical wholesale prices in ERCOT have been running between $20 and $50 MWh, the equivalent of between 2 and 5 cents kwh. Typical consumer prices in ERCOT range between 8 and 14 cents kwh. The $3,000 MWh price cap is equal to $3 kwh (so $9,000 MWh is the same as $9 kwh or about 100 times  typical retail prices).

Austin Energy wants an electric power rate hike

Michael Giberson

Deep in the heart of the competitive wholesale and retail electric power market that is (the ERCOT system in) Texas lies a little island of small-scale socialism: the municipal electric utility called Austin Energy. While power prices are dropping all around the state due to low natural gas prices, in the Texas state capital Austin Energy is seeking a rate increase.*

Austin has long been a bit out of step with the rest of the state, so this could serve as just another opportunity for “real Texans” to poke fun at the aging hippies that have taken control of the capital’s city government.

Instead, however, you should read Martin Toohey’s excellent article in the Austin American-Statesman, “As natural gas prices dip, Austin Energy rates still to increase.” For many years the city utility has pursued a policy of fuel-source diversification. As the article explains, it is easier to see the value of a diversification plan when natural gas prices spike, and harder to see the value when natural gas prices drop sharply.

*Note that the link goes to a live (i.e. periodically updated) price chart which shows the average prices of one-year fixed rate prices in the Houston area. Similar price effects are present elsewhere in the state. Currently the price chart shows a drop from just over 10 cents/kwh during most of 2011 to about 9.5 cents/kwh in April 2012.

On belief in the possibility of price spikes

Michael Giberson

Laylan Copelin, reporting for the Austin American-Statesman, documents the power system resource issues currently troubling state utility regulators in Texas: “State set to grapple again with question: How to encourage more private-sector power generation?

Texas suffered one rolling blackout last winter and narrowly avoided another this summer.

The weather extremes might have exposed an Achilles’ heel to the Legislature’s decade-long embrace of a deregulated market approach to electricity generation: Investors are reluctant to invest in new power plants because they can’t make money despite rising demand that is testing the state’s electricity capacity.

Power generators are urging state officials to tweak the rules to raise wholesale prices, while consumers are arguing that they would face higher prices with no assurance that the new generation would be built. They say let supply and demand work, but that butts heads in some instances with the overriding concern to keep the lights on.

In areas of the country with traditional regulated privately-owned utilities this isn’t much of a problem. The regulator determines a resource adequacy goal and prudent expenses undertaken by the utility in pursuit of that goal get folded into electric power rates. The arrangement is, by design, low risk and profit enhancing for the utility. (And I suppose you could say it works, at least in the sense that none of the major regional blackouts have resulted from a shortage of generating resources. Critics would complain about costs and efficiency, but not the efficacy of the regulated approach.)

In ERCOT’s market only the wires companies remain fully regulated and the state regulator has limited tools available to direct additional generation resources to be built. Instead the theory behind the decade-old market re-design was that prices were to be relied upon to incent investment. As part of the “energy only” market design approach, Texas selected a price cap at about $3000/MWh as compared to the $1000/MWh price cap that most other similar markets impose in the United States. The idea is that the prospect of occasionally earning extraordinary returns would help prompt sufficient investment.

In short, according to one generation company rep, “The ERCOT market requires the developer to believe in the possibility of price spikes.” The problem is, she added, “it is difficult to get banks to finance ‘possibility.'”

Yes, maybe, but in a world in which an Australian cricket player can insure his mustache for £200,000, it seems difficult to belief that no one can figure out how to estimate the likelihood of price spikes. Maybe the banks are not the best financial players to take the action, yet someone should be able to work it out. Right?

Of course, there are a pair of big players in the market that add a further dose of uncertainty to anyone trying to run the numbers: the ERCOT market itself and the Public Utility Commission of Texas. ERCOT is tasked with both ensuring reliable operations of the power system and running an efficient power market. Sometimes actions taken by ERCOT to ensure reliability – like paying uneconomic generators to stay online just in case needed – depress prices in the wholesale market.

The PUCT, just by contemplating a number of policies that could suppress prices in the futures, will inadvertantly cast a shadow over any current investment decision. Generator investments are built to last 20-, 30-, or 40 years. No one counts on 40 years of policy stability in making an investment decision, but the prospect that things may change this year or next in ways you can’t quite pin down will certainly make a prospective investor nervous.

The investment side of the ERCOT power market requires belief in the possibility of price spikes, but it is not at all clear how rational that belief is in a world in which the market operator and regulator feel pressured and empowered to eliminate such spikes. The PUCT should do two things to clear up the matter. First, to the extent possible PUCT should oversee ERCOT market reforms needed to limit the price-supressing effects of emergency reliability actions. Second, PUCT should affirm in the strongest voice possible that price spikes are a natural, infrequent but important part of the commercial wholesale power market environment that generators and retailers participate in, and therefore generators and retailers should get on with the business of managing the inherent price risk.