Tag Archives: resource adequacy

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

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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.

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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).

On belief in the possibility of price spikes

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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.