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.

The case for allowing negative electricity prices – Benedettini and Stagnaro

Simona Benedettini and Carlo Stagnaro make the case for allowing negative prices in electric power markets in Europe. A few of the larger power markets in Europe allow prices to go negative, but others retain a zero price lower limit. Benedettini and Stagnaro explain both why it is reasonable, economically speaking, to allow electricity prices to go negative and the hazards of retaining a zero-price minimum in a market which is interconnected to markets allowing the more efficient negative prices.

It is all good, but I can’t resist quoting this part:

Negative prices are not just the result of some abstruse algorithm underlying the power exchange and the functioning of the power system. They are also, and more fundamentally, the way in which the market conveys the decentralized information that is distributed among all market participants, and that cannot be centralized in one single brain, as Nobel-prize winner Friederich Hayek would say. That information is translated into two major market signals, which are embodied in negative prices.

In the short run, negative prices show that there is a local condition of oversupply under which electricity is not an economic good which society is willing to pay for, but an economic bad for which consumers should be compensated. Therefore, negative prices create an economic incentive for consumers to shift their consumption patterns so as to capture the opportunity of being paid, instead of paying, to receive energy….

However, in the long run, negative prices talk to energy producers, not to energy consumers. The emergence of negative prices, although strongly conditioned by demand-side constraints, shows that the generating fleet encompasses too much “rigid” capacity (i.e. too much nuclear and coal-fuelled plants) and too little “flexible” capacity (for example CCGTs or turbo-gas power plants); or that grid interconnections are insufficient to properly exploit the spare, flexible capacity available within a market area.

So far as I know, all of the regional power markets in the United States now allow prices to go negative. The connections between wind power policy and negative prices have politicized the issue a bit in the United States. Benedettini and Stagnaro explain in a straightforward manner why, no matter what you think of renewable energy policies, you ought to favor allowing wholesale power market prices to go negative.

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.

Power demand in Texas grows more slowly than forecasted

From StateImpact Texas, a joint effort of radio station KUT Austin and KUHF Houston, a report that consumption of electric power in Texas isn’t growing as fast as expected:

As the Texas Public Utility Commission (PUC) considers changing the electricity market so there’s more money to build new power plants, a mystery has popped up: why aren’t Texans using as much electricity as predicted?

“There’s something that’s been going on recently with the forecasts, which affects a lot of things,” said PUC commissioner Kenneth Anderson at the commission’s open meeting last week.

Who Turned the Lights Out?

Anderson said forecasts from the Electric Reliability Council of Texas (ERCOT) had predicted electricity demand would increase in 2013 by 2.1 percent.

In reality?

“It’s been barely one percent, if it’s even hit one percent,” Anderson said.

As the story highlights, this is kind of a big deal. The Texas PUC is contemplating fairly substantive changes to the ERCOT power market design based on projections that power generation capability won’t grow fast enough to meet forecasted future demand. If the forecasts are overstating the problem, maybe regulators need not be quite so nervous.

EIA shows higher wind power output cutting into baseload power generation

The Energy Information Administration’s “Today in Energy” series shows with a couple of charts how growing wind power output in the Southwest Power Pool region is cutting into the income of baseload power plants.

U.S. EIA chart based on Southwest Power Pool data.

The effect matters because baseload power plants tend to have the lowest operating costs. As baseload plants get pushed off the system, more of system capacity will shift to more flexible “load following” plants, which tend to have higher operating costs. Power prices in the Southwest Power Pool and other ISO power markets tend to reflect the operating costs of load following plants, so the effect will be to increase average wholesale power prices.

Wind power advocates sometimes want to claim credit for driving down power prices, and in the short run the addition of wind power can push prices down (especially, of course, if wind power plants have their output subsidized as with the Production Tax Credit). In the long run, as output of cheap-to-run baseload power plants is squeezed from the system, average prices will rise again.

The ERCOT market in Texas faces this same problem — in fact I suspect it is a little further down this path than the Southwest Power Pool — and the state has been struggling over projected resource adequacy concerns on the horizon. Of course, as Texas PUC commission Kenneth Anderson has pointed out, an efficient “energy-only” market with growing consumption should always see resource adequacy problems about four or five years ahead. If it doesn’t see shortages in the future, it implies the system is currently overbuilt. Still, incentives to invest in generation appear weak, wind power capacity additions in Texas are expected to continue, and resource adequacy analysts in ERCOT are nervous.

NRG seeks capacity market for Texas

Michael Giberson

Joe Ragan, a VP at Power generation company NRG, recently opined in the Houston Chronicle in favor of a capacity market for the ERCOT power grid in Texas. A capacity market provides what you might call “being there” payments to generators, whether the generator’s power turns out to be demanded in the market or not.

I was struck by two things while reading the op-ed: first, no mention of the role of wind power in shaping prices and economic conditions for generation in Texas even though ERCOT has the highest wind penetration market-wide in the United States; and second, the way “prices” get invoked.

As any economics student knows, prices are the product of the interaction of supply and demand. In the op-ed, however, prices seem to be something driven by and driving the supply side of the market only. The demand side of the market has “needs” driven by the weather, but apparently not linked to the prices that consumers have to pay.

Admittedly, this way of thinking has 100+ years of tradition behind it in the electric power industry–that’s how it was done under the old cost-of-service, monopoly territory, regulated rate system in the electric power industry.

Texas has been trying something different, with more commercial risk to drive efficiency on the supply side, and potentially high price spikes to motivate an active and engaged consumer side of the market. A capacity market would kill the experiment before it has a chance to pay off.

Al Roth, Matchmaker

Michael Giberson

Stanford’s alumni association magazine has a good article on recent economics Nobelist Al Roth. Several things about the article will trigger resistance among some free market readers, beginning with the title (“The Visible Hand”) and the subhead (A new breed of economist, Alvin Roth brings an engineering sensibility to fixing markets.). Deep into the article, this too: “Thanks to guys like Al Roth and powerful software … we were able to put all our incompatible pairs in there and just hit a button and the computer would spit out the answer.”

In fact just this morning I was just re-reading James Buchanan’s remarks about differences between economics as a science of allocation versus economics as a science of exchange – Buchanan was definitely in the exchange camp – and perhaps Buchanan would wonder whether or not these game-theoretic algorithms constituted a kind of applied economics or perhaps were something more akin to mere logistics tools. But in that article (“General Implications of Subjectivism in Economics”) Buchanan does suggest that game theory, in that it can frame situations from the point of view of economic agents, might constitute a valuable tool for understanding economics as a science of exchange.

But it is clear enough from the Stanford Magazine article that more than logistics is going on in Roth’s efforts. In all of the matching schemes Roth has helped develop, the incentives created for participants are a key constraint. It isn’t a mere matter of minimizing fuels costs for a delivery fleet, Roth is using economics to meddle with the rules of particular kinds of economic systems in order to bring about better arrangements as valued by the participants themselves. These efforts are not about imposing allocations, they are about enabling better exchanges in complex environments.

[HT to Daniel Cole, who draws attention to the dwarf-tossing issues raised at the end of the article.]

 

‘Demand Response’ in Electricity: Economists vs. FERC on (Over)Pricing

Michael Giberson

As noted here at KP in August, a group of electric power economists (including me) filed an amicus brief on FERC’s demand response pricing rule.

At the Master Resource blog, Travis Fisher examines the issue with some detail. Here is a bit:

In Order No. 745, FERC reasoned that, “when a demand response resource has the capability to balance supply and demand as an alternative to a generation resource,” the demand response resource should be paid the full LMP. Some commenters agreed – some not so much. As FERC stated:

In the face of these diverging opinions, the Commission observes that, as the courts have recognized, ‘issues of rate design are fairly technical and, insofar as they are not technical, involve policy judgments that lie at the core of the regulatory mission.’ We also observe that, in making such judgments, the Commission is not limited to textbook economic analysis of the markets subject to our jurisdiction, but also may account for the practical realities of how those markets operate. (Order No. 745 at P 46, emphasis added)

Then Order No. 745 wades beyond ignoring textbook economics into the murky waters of justifying full LMP with the infant industry argument (with market power thrown in for good measure). As FERC argues:

Removing barriers to demand response will lead to increased levels of investment  in and thereby participation of demand response resources (and help limit potential generator market power), moving prices closer to the levels that would result if all demand could respond to the marginal cost of energy. (Order No. 745, at 59)

I wonder out loud whether FERC commissioners actually had anyone (1) estimate price levels that would result if all demand could respond to the marginal cost of energy, then (2) estimate what will happen to the actual wholesale price of energy in a world in which officially-registered-demand-response resources are overpaid, and finally (3) determine whether result 2 is closer or further from result 1 than current wholesale energy prices.

My guess it that the majority simply assumed that it must be the case that subsidized demand response will behave like unsubsidized demand response would have behaved but for the restraints of state retail ratemaking practices.

Fisher’s conclusion quotes Bastiat to good effect:

The economists and the FERC minority make valid points – get incentives right, examine unseen or unintended consequences (regulatory rent-seeking, gaming, the stifling of new generation), and don’t provide any “free” lunches.

Sadly for the economists, the Administrative Procedure Act sets a low bar for “reasoned decision-making,” meaning the Court of Appeals would have to find FERC’s ruling “arbitrary and capricious,” etc., to order reconsideration. Further, the DC Circuit has a penchant for explicitly granting agencies like FERC Chevron deference, which means it substantially defers to agency interpretation, especially on nuanced or ambiguous issues.

It strikes me, though, that the FERC majority would do well to return to “textbook economic analysis” on this issue, and I would recommend Bastiat as one of the textbooks. As Bastiat said in 1848:

“[N]ot to know political economy is to allow oneself to be dazzled by the immediate effect of a phenomenon; to know political economy is to take into account the sum total of all effects, both immediate and future.”

Demand response is the next new thing. It may have very positive effects now and in the future, but in the case of the FERC Order Nos. 745 and 745-A, the agency let itself be dazzled by the immediate effects and pulled into a misguided policy.

I’ve left out quite a bit of Fisher’s analysis and cut out the useful links, so please do go read the whole thing.

Trying to fix FERC’s demand response pricing mistake

Michael Giberson

Last year the Federal Energy Regulatory Commission ruled that RTO and ISO markets should pay retail consumers an amount equal to the market’s real-time marginal price when consumers reduce consumption at peak periods. Economically speaking, it is the wrong price.

Parties opposed to FERC’s action have taken the issue to court. A group of “leading economists and educators” have filed an amicus brief in the case (and somehow I got invited to be part of this group). Here is the introduction:

Amici curiae (listed in Addendum A) are leading economists and educators who have designed, studied, taught, and written about the electricity markets affected by the Federal Energy Regulatory Commission Final Rule under review here, Demand Response Compensation in Organized Wholesale Energy Markets, Order No. 745, 76 Fed. Reg. 16,658 (Mar. 24, 2011), FERC Stats. & Regs. ¶31,322 (2011), reh’g denied, Order No. 745-A, 137 FERC ¶61,215 (Dec. 15, 2011). That Rule establishes the rate wholesale market participants must pay retail customers for reducing purchases of electric energy during peak-demand periods. In particular, FERC now requires market participants to pay the full “locational marginal price” (“LMP”) for electricity that is not consumed, treating non-consumption of energy as the equivalent of costlessly producing energy. See Pet. Br. 45-61.

Although the views of amici may diverge on market-design issues in other contexts, they all agree that FERC’s Rule creates a counterproductive demand response mechanism that produces economically undesirable behavior and wasteful outcomes that will injure consumers and society in the long run. Although FERC invokes economics to justify its course, the Final Rule is economically irrational. Retail customers that reduce their consumption should not be paid as if they generated the electricity they merely declined to buy. Instead, retail customers should be compensated as if they had entered into a long-term contract to purchase electricity at their retail rate but instead, during a peak demand period, resold the electricity to others at the market rate (LMP). In other words, they should be paid “LMP-minus-G,” where G is the rate at which the retail customer would have purchased the electricity. Simply put, the customer must be treated as if it had first purchased the power it wishes to resell to the market.

FERC never adequately explains its decision to adopt its contrary approach. Nor could it. By overcompensating reductions in retail purchases, the Final Rule encourages retail customers to reduce demand even when society would be better off if they continued purchasing electricity needed to engage in productive activity. It encourages inefficient self-supply of electricity. And it leaves market participants paying for the delivered electricity more than once—first to the generator that created it and then to the user who provided the demand reduction. That overpayment harms both suppliers and non-demand-response consumers, to whom the cost of the subsidy ultimately will be passed on.

So far as I can tell, the case Electric Power Supply Association v. Federal Energy Regulatory Commission hasn’t been heard yet at the U.S. District Court of Appeals. The full name of the brief is: “Brief of Robert L. Borlick, Joseph Bowring, James Bushnell, and 18 other leading economists as Amici Curiae in support of petitioners.”

Does EPSA support capacity markets? For power markets, yes; for gas pipeline markets…

Michael Giberson

The Electric Power Supply Association, “the national trade association representing competitive power suppliers,” supports the use of electric power capacity markets to ensure sufficient generation capacity is available to reliably serve peak consumer load. See, for example, EPSA’s policy paper on the topic:

Well-functioning forward capacity markets are a critical component of organized wholesale competitive electricity markets in many parts of the country. These markets provide the capacity needed for the continued reliable operation of the grid through the commitment of existing supply, investment in new generation when needed and participation by consumers to manage their demand (demand response).

So you might expect that when the issue is securing sufficient natural gas pipeline capacity to ensure continued reliable operation of gas delivery at peak times, EPSA would favor a capacity market-style solution.

If you expected that, you would be wrong.

In EnergyWire Peter Behr reports industry viewpoints on coordination between natural gas and electric power markets. From the gas pipeline side of the business:

Generally, across the board, the electricity market is not stepping up … to contract for the reliability that they seek from the gas-fired generators,” said Richard Kruse, vice president of regulatory affairs for Spectra Energy Corp., which operates 19,000 miles of natural gas pipelines….

“We hear all the time from gas-fired generation in New England, ‘We cannot afford pipeline capacity if we don’t get paid to hold that capacity,’” Kruse told reporters at a press briefing Friday sponsored by the Interstate Natural Gas Association of America (INGAA).

“When people step up and say they want to sign up for contracts, that’s when we’ll start working on the infrastructure that they need,” Kruse said.

EPSA’s John Shelk offers the power generators viewpoint, stating they don’t need firm capacity rights on gas pipelines all of the time, just those times the power plant will be dispatched in the power market. He adds that a power generator that pays for firm capacity it can’t use will not be competitive in the power market.

I can see his point, which mirrors in a way, how many power consumers feel about electric power capacity markets. Power consumers don’t want to pay for a lot of extra generation all of the time since they only actually need those extra bits of generating capacity for, typically, just a few hours out of a year.

NOTE: In August the Federal Energy Regulatory Commission will be holding five regional technical conference to explore interactions between natural gas markets and electric power markets.