Posts Tagged ‘power market design’

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On belief in the possibility of price spikes

November 1, 2011

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.

Posted in Electricity, Energy markets, Regulation | Tagged , , , | 2 Comments »

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Worried about too much demand elasticity in electric power markets

August 8, 2011

Michael Giberson

Will electric power consumers facing smart-grid enabled real time prices have the potential to accidentally destabilize the power grid and cause a blackout?  A paper presented at a recent IEEE conference says it is a possibility. The surprising culprit? Too much price elasticity in the market demand function.

It is a surprising culprit because consumer demand for electricity is currently notoriously inelastic (that is to say, not responsive to changing prices) in the short run, in part due to the way standard regulatory rate structures end up with consumers being presented with relatively unchanging prices reflecting a longer-term average cost of production. Prices don’t change much, so consumers don’t watch prices much. But this price inelasticity of demand doesn’t mean the quantity of electricity consumers want to consume is unchanging – consumers want more or less electricity throughout the day in response to ordinary household schedules and in response to outside temperatures and building heating and cooling demands. Consumer demand for power responds to a lot of things, but rarely to changes in the price of power itself.

Because of the way the current grid is designed, the quantity of energy supplied and demanded must be balanced continuously. Therefore, the grid is typically operated to take the quantity of power demanded as a given and make whatever adjustments in the quantity supplied to maintain system balance. (In brief, because prices can’t do much work coordinating supply and demand in the short-run, all of the coordination must be done by adjusting quantities. Grid operators can typically control suppliers but not consumers, so quantity-based supply side adjustment does most of the work of keeping the market balanced.)

The authors, three engineers at MIT, worry that if too many consumers facing real time prices pick similar high price points at which to cycle off appliances (or low prices as which to charge electric vehicles), that the market demand function will acquire highly price elastic segments in which quantity demanded will suddenly drop off (or spike up) at rates faster than the supply side can safely accommodate. Therefore, a blackout risk. To counter this possible risk, the authors suggest diversifying price signals sent to consumers, or employing hourly instead of 5-minute price signals, or using rolling-average prices to consumers rather than location-specific current marginal price. They admit their safeguards would hamper the efficiency of market results, the efficiency loss essentially the price paid to mitigate the possibility of a price-responsive demand shock to the system.

In my view, the idea of having so many real-time price-aware consumers responding in the market remains so far-fetched that I’m not willing to worry about that so many of them will coordinate their home energy management systems on the same price points and unwittingly bring down the system.

And well before this possibility of too-much consumer responsiveness comes about, I suspect most RTOs will be paying suppliers for ramping capability and charging consumers for using it in ways that will enable sufficient short-run system responsiveness. So I’m not ready to worry now about this problem, and don’t think that I’ll need to worry about it later, either.

(See MIT media relations summary here, HT to Scientific American via Economist’s View.)

Posted in Complexity, Electricity, Energy markets | Tagged | 4 Comments »

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Economics of power market design compared unfavorably to climate science

June 16, 2011

Michael Giberson

From the Harvard Electricity Policy Group meeting in February 2011. By convention the meetings are off-the-record, so the speaker’s name is not identified in the summary:

I think the most important distinction between the fields of climate science and economics for me is the question of evidence. Science is characterized by a subtle interplay between conceptual models and the evidence that supports or contradicts them. There’s a rigorous process of analyzing and evaluating evidence and improving or discarding the conceptual models as the evidence dictates. In economics, evidence can often be harder to come by and more ambiguous in nature. This instance is a strong case in point. There is no real precedent. The markets are brand new. And with a few exceptions, the RTO regions have been basically in capacity surplus since the markets came into being for reasons having nothing to do with the capacity markets themselves.

Where evidence is lacking, theorists can find themselves somewhat less constrained. Under these circumstances, whichever side has the loudest voices or the most money or the most impressive resumes can dominate the conversation. This should never be mistaken as proof that their position are correct.

[...]

I’m aware that many will argue, and have argued, that a focus on market efficiency will in the long run lead to the greatest consumer benefit. This may be true in a nonexistent, two-sided perfect market with no barriers to entry. But it is a tenuous article of faith when applied to real electricity markets. And given the untold billions in costs to get to that uncertain future, it’s no wonder that consumer advocates basically unanimously are not eager to take that bet.

The implementation of capacity markets based on these unproven theories has already led, predictably, to the transfer of tens of billions of dollars of ratepayer wealth to generation owners. I say predictably because this outcome was clearly anticipated by all parties and articulated by many. The whole point was to raise costs. On the other hand, there’s not a shred of hard evidence that this process has led to new generation where it is most needed, or to avoided retirements of needed capacity or to cost-saving transmission investments. These are the ostensible purposes of the construct. There is no reason to believe that it would. It’s just too good an arrangement for existing generation owners as it is.

The speaker observes that capacity markets have also spurred development of demand-side resources, but this “positive benefit … has come at an astronomical cost.”

As an alternative to capacity markets, the speaker suggests a combination of state-sponsored investments, long term contracts, and short term spot markets. Not that he presents any evidence that this approach will work better for consumers, it just seems good to him. I wonder, scientifically speaking, why not just examine the existing evidence on prices and investments in “energy only” power markets in Texas, Alberta, and Australia?

Posted in Economics, Electricity, Science | Tagged , | Comments Off

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Bonneville Power Administration says no to negative prices again

May 20, 2011

Michael Giberson

The Bonneville Power Administration (BPA) Administrator has adopted interim Environmental Redispatch and Negative Pricing Policies to deal with potential overgeneration conditions on the BPA power system. In brief, BPA plans to employ “Environmental Dispatch” rules for operating the power system in a manner conducive to BPA meeting various legal and regulatory constraints; the BPA Negative Pricing Policy is “we won’t allow it.”

Excepts from pages 10-12 of “BPA’s Interim Environmental Redispatch and Negative Pricing Policies: Administrator’s Final Record of Decision,” May 2011, below. I haven’t yet read the 68-page long section “Negative Pricing Policy,” but am adding it to my summer reading plans.

Related:

From the BPA report:

The events of early June 2010 illustrate how the increase in wind generation has influenced the ability to manage high flows on the Columbia River. … In early June, however, a strong Pacific jet stream brought storm systems with heavy precipitation and runoff. Snake River streamflows nearly tripled, and Columbia River streamflows nearly doubled. The resulting flows exceeded those needed to meet flow and spill objectives for fish passage. Federal water management staff focus shifted to developing strategies and modifying operations to reduce excess spill and minimize excessive TDG production to the extent practicable.…

During this time, most Northwest thermal generation shut down or reduced to minimum operating levels. These generation owners obtained low-cost or free Federal hydropower to replace thermal generation. Thermal generation normally finds it economical to displace their fuel with lower-cost hydropower since they can store or conserve their fuel while they receive hydropower.

However, due to differing economic considerations, the roughly 3,000 megawatts of wind power projects located in BPA’s Balancing Authority Area did not respond to the availability of free Federal hydropower. Wind power projects cannot store their fuel and are generally eligible to receive Federal Production Tax Credits (PTC) and/or state Renewable Energy Credits (REC). Wind power output ranged from zero to nearly full output, depending on wind conditions….

Unlike thermal operators, wind operators have an economic incentive to operate as much as possible, regardless of system conditions. The PTC is currently $21 per megawatt-hour (“MWh”) and state RECs are generally in the $8 to $20 per MWh range, so this incentive is significant. While all wind power projects are eligible to receive RECs for production, most new wind power projects have opted not to take the PTC and instead opted for the Investment Tax Credit (“ITC”) or other grants that provide up-front financial benefits tied to the cost of the project and not actual production. Wind power projects that opt for the ITC or other grants receive the full financial benefit of these incentives regardless of project output (pp. 11-12).

BPA believes that its statutory responsibilities and the objectives of the Northwest Power Act would be frustrated if BPA were required to pay negative prices in order to ensure compliance with BPA’s environmental responsibilities.

… While one purpose of the Northwest Power Act is to encourage the development of renewable power in the Pacific Northwest through BPA’s acquisition authority, that is one purpose among many that BPA must meet, including assuring the Northwest has an economical power supply, providing environmental quality, continuing to repay the U.S. Treasury on a current basis, and protecting, mitigating and enhancing fish and wildlife of the Columbia River and its tributaries. …

[P]aying negative prices to displace renewable generation to ensure BPA’s environmental responsibilities are met is neither socially optimal nor consistent with traditional principles of cost causation. BPA’s statutory preference customers would end up paying the costs of displacing renewable generation that is currently almost entirely serving the loads of utilities outside of the BPA Balancing Authority Area. The costs of Federal and state production incentives should be borne by a broad group of taxpayers and ratepayers receiving the wind power, not concentrated on smaller subsets of consumers with limited economic interest or benefits from the renewable generation.

Note that about 750 MW of wind capacity has been added to the BPA Balancing Authority Area since June 2010, to a current total of 3522 MW, and “as much as 3,000 MW of additional wind generation expected to come on line in the next few years” according to the report.

Posted in Electricity, Energy markets, Environmental policy | Tagged , , , | 1 Comment »

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Opportunities in power market design: wind power, capacity markets, optimization software

May 10, 2011

Michael Giberson

A handful of stories raising power market design issues:

  • The Oregonian, ”Northwest wind power to double but inconsistency creates nightmare“: “The value of BPA’s surplus power sales are already being undermined by wind energy sloshing into the market. That ultimately increases rates for its public utility customers, who are loathe to absorb any additional costs incurred by BPA for integrating wind output that isn’t serving them.”


  • Naturlig Energi, “Who owns the wind?“: “The valuation authority has agreed to take on the two Danish cases, not because it will accept ownership of the wind but because a wind turbine is considered real estate, and because a wind turbine, if the wind is influenced by new turbines, actually loses value.”


  • Next 100, “Who owns the wind?” (commenting on the prior item): “…as wind power developers dot the landscape with giant turbines, litigation is growing all over the world not just with NIMBY neighbors, but also with rival developers to answer the novel question: who owns the wind?”


  • News release, “Brattle study shows positive outlook for long-term sustainability of Alberta’s energy-only electricity market“: “The report analyzes a number of challenges to resource adequacy that the Alberta energy-only market will face over the coming decade … [but] concludes, however, that the current market design is generally well-functioning and should be able to support this higher and more challenging rate of generation additions, as long as large simultaneous retirements can be avoided.”


  • California ISO, “Compliance filing in Docket No. ER11-2256-000“: On December 1, 2010, the ISO proposed modifications to the California ISO Tariff to implement the Capacity Procurement Mechanism (CPM) to replace the expiring Interim Capacity Procurement Mechanism (ICPM) as the backstop mechanism that authorizes  the ISO to procure capacity to address a deficiency or supplement resource adequacy (RA) procurement by Load Serving Entities (LSEs) as needed in order to comply with  applicable reliability criteria and maintain reliability of the grid. The compliance filing responds to FERC’s March 17 order in the docket.


  • FERC Technical Conference, “Increasing market and planning efficiency through improved software“: “Take notice that Commission staff will convene a technical conference on June 28-30, 2011, from 8:30 AM to 4:30 PM, to discuss opportunities for increasing real-time and day-ahead market efficiency through improved software. This conference will bring together diverse experts from ISOs/RTOs, non-market utilities, the software industry, government, research centers and academia for the purposes of stimulating discussion and sharing of information about the technical aspects of these issues and identifying fruitful avenues for research.” (From official notice.)

(HT to Eric S. for pointing out the Alberta study.)

Posted in Economics, Electricity, Energy markets | Tagged | 1 Comment »

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Independent monitor finds no market abuse during ERCOT rolling blackouts on February 2

April 28, 2011

Michael Giberson

The ERCOT independent market monitor (IMM) has released its report on the February 2, 2011 rolling blackouts. Excerpts from the report introduction are below, but let’s get to the meat of the matter. The IMM was asked (1) whether there was any evidence that market participants tried to manipulate the market for financial gains during the period, and (2) whether markets operated efficiently and as expected during the period.

The short answers are (1) no evidence of manipulation was found, and (2) the markets operated efficiently and outcomes were consistent with the market design.

While these may seem like excessively upbeat conclusions given the failings in the ERCOT region that day, the key is to distinguish between the physical systems – which did fail and created significant hardships that day – and the market systems – which appeared to work as intended. The market review concluded market participants faced increasing incentives to have generation available before the event, companies responded to incentives by taking many preparatory steps (nonetheless, inadequate as we see in hindsight), during the emergency companies faced substantial incentives to bring generation to the market, and companies responded to those substantial incentives by engaging in extraordinary efforts to bring offline generators back online.

A key image on the manipulation question is Figure 5, which shows the relationship between generation outages and net market position for February 2. In brief, every generation company that was able to keep their forced outages below 10 percent (i.e. 90 percent or higher generator availability) netted a positive revenue flow from the market that day. Those generation companies with forced outages of 20 percent or higher ended up owing money to the market for February 2. It is highly unlikely that a firm profited by withholding generation capability from the market that day. (See the report, pp. 12-14, for additional details on the figure.)

Figure 5: Generation Availability and Net Financial Position on Feb. 2, 2011

Figure 5: Generation Availability and Net Financial Position on Feb. 2, 2011

The Texas Reliability Entity, reliability monitor for ERCOT, will also be issuing a report on the event directed at generator compliance with ERCOT reliability protocols and related rules. The North American Electric Reliability Corporation (NERC) and the Federal Energy Regulatory Commission (FERC) are also investigating outages in Texas and elsewhere in the Southwest and may publish reports.

For background, here is the introductory section of the IMM’s “Investigation of the ERCOT Energy Emergency Alert Level 3 on February 2, 2011“:

In the early morning hours of February 2, 2011, the Electric Reliability Council of Texas (“ERCOT”) region experienced extreme cold weather conditions, record electricity demand levels, and the loss of numerous electric generating facilities across the ERCOT region. These events combined to result in the declaration of Energy Emergency Alert (“EEA”) Level 3 at 5:43 a.m., with the initial interruption of 1,000 MW of firm load at that time, and reaching 4,000 MW of firm load shed by 6:30 a.m. Subsequently, firm load was restored in 500 MW increments beginning shortly prior to 8:00 a.m., with all firm load restored shortly after 1:00 p.m. on February 2nd . Prior to the declaration of EEA Level 3, load resources contracted to provide responsive reserve service were deployed at approximately 5:20 a.m., and Emergency Interruptible Load Service (“EILS”), another contractual demand response service, was deployed concurrent with the declaration of EEA Level 3, at approximately 5:46 a.m.

On February 4, 2011, the Executive Director of the Public Utility Commission of Texas (“PUCT” or “Commission”) directed Potomac Economics as the Commission’s Independent Market Monitor (“IMM”), and the Texas Reliability Entity (“TRE”) as the Commission’s Reliability Monitor, to investigate the ERCOT EEA Level 3 that occurred on February 2, 2011, and subsequent related events and developments on February 3-4, 2011, including all preparations leading to the emergency event, as well as action taken once the event occurred, and focusing on the actions of ERCOT and the ERCOT market participants to determine whether all appropriate laws, rules, requirements and processes were followed.

The primary role of the IMM as the Commission’s market monitor is to: (1) detect and prevent market manipulation strategies and market power abuses; and (2) evaluate the operations of the wholesale market and the current market rules and proposed changes to the market rules, and recommend measures to enhance market efficiency.

The primary role of the TRE as the Commission’s reliability monitor is to monitor and investigate material occurrences of non-compliance with ERCOT procedures that have the potential to impede ERCOT operations, or represent a risk to system reliability.

Given this division of responsibilities, this IMM report addresses the following two issues related to the ERCOT EEA Level 3 on February 2, 2011 and subsequent related events and developments on February 3-4, 2011: (1) whether market manipulation strategies or market power abuses were a cause or played a role in these events; and (2) whether the operations of the wholesale market and the existing market rules produced efficient market outcomes.

The review and analysis performed by the IMM and described in this report yields the following findings related to the events in the ERCOT wholesale market on and around February 2, 2011:

  • Based on our review of the cause of each generating unit outage and/or capacity de-ration, as well as the financial positions of market participants, we do not find any evidence of market manipulation or market power abuse in relation to the widespread generating unit outages that resulted in the EEA3 event on February 2nd .
  • Given the system conditions that materialized on February 2nd and 3rd, we find that the ERCOT real-time and day-ahead wholesale markets operated efficiently and the outcomes are consistent with the ERCOT energy-only wholesale market design.

Finally, because the review of the EEA3 event on February 2, 2011 is the subject of review by multiple entities and the IMM report is but one facet of this review, we have not at this time provided recommendations that may be beneficial in preventing a reoccurrence of the events experienced on and around February 2nd . We anticipate and are looking forward to participating in the development of a comprehensive set of actions that will serve to significantly improve the future reliable operation of the ERCOT grid in manners consistent with the competitive ERCOT market structure.

Previous Knowledge Problem posts on the ERCOT’s rolling blackout:

Cold snap brings rolling power outages to Texas; is ERCOT policy of isolation at fault? (February 4, 2011)

Texas Observer: Some Companies Made Millions Off the Texas Blackouts (February 4, 2011)

The natural gas that didn’t come in from the cold (February 7, 2011)

Transmitting power from Mexico to Texas (February 8, 2011)

More cold for Texas and a test of my conjecture on preparedness (February 9, 2011)

Roundup of news and commentary on the Texas rolling blackouts (February 11, 2011)

Good news and bad news from price-spike induced failure of retail power company in Texas (February 12, 2011)

ERCOT blackout hearings underway in Texas State Senate (February 15, 2011)

ERCOT rolling blackout news: Powerful market forces already at work (February 16, 2011)

Posted in Electricity, Energy markets | Tagged , , , | 1 Comment »

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Meanwhile, more “power market and the state” battles in New Jersey and Maryland

March 23, 2011

Michael Giberson

And if Andrew Kleit thinks that the Pennsylvania state government is toying with a bad idea (see previous post), look what is going on next door in New Jersey and Maryland.

In New Jersey: “Utilities challenge New Jersey law while preparing to reap its benefits.”

In January the Governor signed a law which is intended to facilitate long-term capacity agreements between the state’s electric distribution companies and generators. As the linked story explains, PSEG is considering building power plants that would benefit from the law – the long term guarantees will help the utility secure lower-cost finance – and “allowing [developers] to build facilities or undertake projects that would not have been feasible otherwise.” At the same time, PSEG is among the members of a coalition of companies that have protested the state’s law at FERC and a member of another group which has filed a challenge to the law in federal court.

Dow Jones Newswire explains: “PSEG and other power producers say this program undermines the U.S.’s largest competitive-electricity market by skewing market prices. They are in the process of suing the state over the legislation in a U.S. District Court and filed a complaint with the Federal Energy Regulatory Commission. Just in case those efforts fail, PSEG is preparing to work under the program.”

Do they contradict themselves? Very well, they contradict themselves. PSEG is large, like one-time New Jersey resident Walt Whitman, they contains multitudes.

In Maryland: “PSC, generation firms debate auction rule.”

The Maryland Public Service Commission on Friday [March 4, 2011] filed a protest with the Federal Energy Regulatory Commission over efforts to do away with breaks at wholesale power auctions that given to new plants that are built with state subsidies. Two groups, P3 Power Providers Group and PJM Interconnection LLC, don’t want those subsidized plants to be allowed to bid less than an administratively set benchmark price.

In both the New Jersey and Maryland cases, among other things the generators are concerned that state involvement in subsidies or guarantees for new investment would undermine operation of the PJM capacity market.

Also see: Court Rules PJM Capacity Market Prices Adequately Protected from Seller Market Power, but Others Contend Not Protected from Buyer Market Power. (Energy Legal Blog).

Posted in Electricity, Energy markets, Politics, Regulation | Tagged , , | 1 Comment »

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An experimental test of automated market power mitigation finds the procedures work

February 15, 2011

Michael Giberson

The new International Journal of Industrial Organization is a special issue devoted to experimental analysis. Among the articles is research into automated market power mitigation procedures similar to the rules employed in the New York Independent System Operator. In brief, the authors find that automated conduct- and impact-based screening of offers succeeded in mitigating the effects of attempts to exercise market power on power prices, at least when suppliers don’t have market power during periods that transmission lines are not congested. (Reference offer prices are determined by offers made during non-congested periods, so if generators have significant market power in these periods the reference offer prices can be manipulated upwards.)

The article, “An experimental test of automatic mitigation of wholesale electricity prices,” was authored by Daniel Shawhan, Kent Messer, William Schulze, and Richard E. Schuler.

ABSTRACT: In several major deregulated electricity generation markets, the market operator uses an “automatic mitigation procedure” (AMP) to attempt to suppress the exercise of market power. A leading type of AMP compares the offer price from each generation unit with a recent historical average of accepted offer prices from that same unit during periods when there was no transmission-system congestion to impede competition. If one or more units’ offer prices exceed the recent historical average by more than a specified margin, and if these offer prices raise the market-clearing price by more than a specified margin, the market operator replaces the offending offer prices with lower ones. In an experiment, we test an AMP of this type. We find that it keeps market prices close to marginal cost if generation owners have low market power in uncongested periods. However, with high market power in uncongested periods, a condition that may apply in many parts of the world, the generation owners are able to gradually raise the market price well above short-run marginal cost in spite of the AMP. We also test the effect of the AMP on the frequency with which high-variable-cost units are used, inefficiently, in place of low-variable-cost units.

Interested readers should also note related research by Lynne Kiesling and Bart Wilson, “An experimental analysis of the effects of automated mitigation procedures on investment and prices in wholesale electricity markets,” Journal of Regulatory Economics, 2007.

(HT to Al Roth and his Market Design blog.)

Posted in Economics, Electricity | Tagged , | Comments Off

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United States v. KeySpan Corporation antitrust case settles for paltry $12 million

February 2, 2011

Michael Giberson

The Justice Department of the United States has agreed to a $12 million settlement with KeySpan Corporation on a Sherman antitrust act claim. The allegation was that KeySpan manipulated the New York ISO capacity market price in its part of the state from May 2006 through February 2008, reaping an estimated $49 million in excess revenue. More specifically, the allegation was the KeySpan entered into a contract in restrain of trade. The $12 million settlement agreed to between Justice and KeySpan reflects the estimated excess profits that KeySpan gained by the scheme.

KeySpan held market power in the NYISO capacity market for the New York City and Long Island area, and for years they used their market power to keep the price they were paid for capacity at the highest level the market rules allowed. However, market entry by a new competitor in 2006 threatened their price-maximizing strategy.

In response, KeySpan entered into a contract with Morgan Stanley that gave KeySpan a significant economic interest in the capacity market revenues of the new competitor. Morgan Stanley agreed to the contract with KeySpan only on condition it could engage with another counterparty to offset the risk; the counterparty Morgan Stanley secured turned out to be KeySpan’s competitor. (In fact, the competitor was the only party well suited to the deal Morgan Stanley needed to balance its risk, something that KeySpan knew would be the case.)  With the deal arranged, KeySpan could continue to profit by offering its own capacity at the maximum allowed price, pushing the capacity price to its upper limit. So it did.

Complaints filed with the Federal Energy Regulatory Commission lead to rulings in KeySpan’s favor. FERC concluded that while KeySpan clearly used its market position and financial positions to maximize the capacity price it was paid, KeySpan had not violated NYISO market rules in doing so. A rule that established a maximum offer cap is not violated when a party offers capacity at the allowed maximum, even if the effect is a market price higher than it would be otherwise. FERC further concluded that the company had not violated laws against energy market manipulation.

The Justice Department claimed that KeySpan violated Section 1 of the Sherman Act, namely that the company entered into an agreement in restraint of trade. It seems a somewhat novel application of the Sherman Act, especially if KeySpan’s actions were otherwise in compliance with laws and market rules. That said, KeySpan’s actions deterred competition that would have brought benefits to consumers in the region, and it is a broader purpose of NYISO’s market rules to promote competition in New York’s power market.

$12 million seems like a too-modest remedy.

NOTES:

Posted in Electricity, Energy markets, Regulation | Tagged , , | 3 Comments »

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BPA won’t pay negative prices to get wind power producers to curtail

January 18, 2011

Michael Giberson

At a December 2010 meeting, the federal Bonneville Power Agency announced that it would not pay wind power producers in its area to curtail during overgeneration events that sometimes result from the way the agency manages water flow through hydropower facilities to comply with environmental regulations.

When reservoirs are full, the BPA’s dams can either generate power or spill any excess water. High water conditions common during late spring in the Pacific Northwest sometimes put the BPA up against environmental limits on how much water it can spill, so driving it to want to produce and distribute as much power as possible. (Spilling too much water leads to high concentrations of dissolved gas in the water, a hazard to fish.)  In the past, BPA would essentially give away power in order to maximize power generation, and utilities in the area were happy to take the cheap power and shut down their thermal power plants which were costly to run.

Over the past few years, however, the growth of wind power in the BPA’s area has presented the agency with a new problem. Wind power producers who can obtain from $20 to $40 per MWh in federal and state subsidies while they are producing power don’t want to shut down for nothing. If the BPA wants to curtail them, they’d like to be compensated for their losses. The BPA says it will not pay; in a statement it explains why:

While one possible outcome would be for BPA to compensate wind generators the value of the foregone incentives, BPA does not believe that is an appropriate consequence of actions taken to protect fish. …  Currently, qualifying renewable energy receives PTCs and/or RECs when it generates, and the cost is shared broadly by taxpayers. If BPA were to pay negative prices to comply with ESA and the Clean Water Act during high runoff events, the cost burden would shift and would be narrowly focused on BPA preference customers. We do not think the law was designed to place this cost burden on a narrow class of utility ratepayers, and we are not prepared to initiate this change.

The BPA claims it has sufficient legal authority under existing generator interconnection agreements to implement its new policy of “environmental dispatch,” but to clearly articulate the authority it will unilaterally amend provisions of its standard generation interconnection agreements to reflect the policy.

In areas with RTO/ISO power markets, negative prices are now the conventional way for coordinating resource supplies during periods of potential overgenation (mostly also involving high wind power among other contributing factors).

NOTES:

Posted in Electricity, Energy markets, Environmental policy | Tagged , | 3 Comments »

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