Tag Archives: power market design

Al Roth, Matchmaker

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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

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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

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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…

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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.

NYC Brownouts? But why?? I thought they had electric power capacity markets

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Michael Giberson

From Reuters: Amid NYC heat wave, Con Edison lowers power voltage

New York energy company Consolidated Edison Inc reduced the power voltage in some Manhattan neighborhoods on Wednesday, in an action known as a brownout, as a brutal heat wave stressed the city’s electric system for a third day.

This was the second voltage reduction during this week’s heat wave, aimed at easing the load on the power grid and allowing workers to fix heat-stressed equipment in the affected neighborhoods. The company had also turned down the voltage in a few Manhattan neighborhoods for several hours on Monday.

MORE ABOUT CAPACITY MARKETS: Capacity markets are economic rules by which consumers collectively pay electric power supply resources to be available to help meet consumer demand, particularly if and when consumer demand is especially high.

See the New York ISO capacity market rules for the details, though the document is not exactly easy to read. Part of the problem is that capacity markets have been difficult to design well, so there has been constant tinkering with the rules. (Notice, for example, that the NYISO capacity market rules document begins with an 18-page “Revision History,” see pages vii-xxiv.)

The NYISO’s “2011 State of the Market Report,” which is more readable than the NYISO capacity market manual, describes the markets as follows (p. 35):

The capacity market is designed to ensure that sufficient capacity is available to reliably meet New York’s planning reserve margins. This market provides economic signals that supplement the signals provided by the NYISO’s energy and operating reserves markets. Currently, the capacity auctions determine clearing prices for three distinct locations: New York City, Long Island, and NYCA. By setting a distinct clearing price in each location, the capacity market facilitates investment in areas where it is most needed.

What reliably “meeting New York’s planning reserve margins” means is that suppliers get paid extra, that is in addition to being paid for supplying electric power and providing transmission support services, they get additional pay for ‘being there’ in order to help assure that consumers can get all of the power they want AND the system still has sufficient extra resources available in case of an emergency. The use of brownouts indicates either that the ISO didn’t plan for enough resources or that some of the resources paid for were unable to deliver when needed.

As mentioned here and here before, currently regulators in Texas are considering whether they should stick with ERCOT’s so-called “energy-only market design” (where generators can get paid through the ERCOT market for supplying electric power and providing reserves and other transmission support services, but nothing more**) or switch to a capacity market, as was recommended by a Brattle Group report.

Mostly the point of my post here is that even with capacity markets, sometimes there isn’t enough power to go around. Part of the problem, as everyone knows, is that no amount of market design or contracts or financial assurance can actually guarantee physical resource adequacy. In plainer English: No matter how much you pay or promise to pay, you can not guarantee there will always be enough power to go around.

Makes you wonder what consumers are paying for in capacity markets.

**Most generators make most of their revenue through contracts with retailers, which could include a payment for capacity in addition to energy supplied. However, ERCOT rules do not require consumers to buy “capacity.”

LATE AMENDMENT: A correspondent points out that the Manhattan brownouts were most likely a distribution system problem, not a resource adequacy problem. NYISO capacity reports indicate adequate reserve margins on July 18 and 19, the days of the brownout. A more careful reading of the article itself supports the distribution system view; notice that the article mentions the brownouts were “aimed at easing the load on the power grid and allowing workers to fix heat-stressed equipment in the affected neighborhoods.” (emphasis added).

 

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

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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.

Solar subsidies in Italy

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Michael Giberson

Carlo Stagnaro, writing in the European Energy Review, finds that Italy’s generous feed-in tariffs for solar power are creating challenges for both the Italian budget and the Italian energy market.

In terms of investments, Italy’s experience with solar power is definitely a success… Only Germany has more PV capacity. Indeed, Italy has more solar capacity than Japan, the US and China together.

[Image] Congested nodes in the high-voltage power grid in Italy. (Source: Terna)

But the success of Italian solar power came at a cost. It is built on Italy’s very generous incentive scheme, based on an extremely high feed-in tariff that is awarded to PV-installations (at least, to installations that were built before the end of June 2011). In addition, distributors are required to accept and dispatch “green” energy with top priority, regardless of the volumes offered. The combination of a guaranteed high price and virtually unlimited supply created the grounds for the boom.

Not only has government support for solar power led to high costs (€3.9 billion in subsidies in 2011 alone), it has also had another unforeseen effect: it has undermined the very market design that, until recently, had worked remarkably well, and had made Italy one of the most competitive electricity markets in Europe.

Stagnaro works for the Istituto Bruno Leoni, based in Milan.

Negative power prices in RTO and bilateral power markets

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Michael Giberson

The Energy Information Administration has published a pair of short posts on negative power prices, one looking at negative prices in bilateral power markets in the Pacific Northwest and another looking at negative prices in RTO markets across the country. Dan Haugen has a related story at Midwest Energy News. Negative power prices may seem counter intuitive, but as Haugen reports negative prices are sometimes just the right price for the market to send.

EIA: Negative prices in wholesale electricity markets indicate supply inflexibilities
(Mid-C is the Mid-Columbia pricing point on the Washington-Oregon Boarder; COB is the California-Oregon Border; NOB is the Nevada-Oregon Border)

As the chart above from the bilateral pricing story indicates, negative prices emerged in bilateral trading primarily in May and June. The late Spring 2011 period saw a combination of high hydro power output and high wind power output which overwhelmed the ability of the regional transmission grid (and local consumers) to absorb all the power produced. (See also this related information from EIA.)

EIA Chart on Negative RTO power prices

EIA: Negative wholesale electricity prices: possible, but rare

Negative prices are uncommon in commodity markets since in effect the producer is paying customers to take away the goods – this is why the often strike power market observers as counter intuitive. The EIA identified the following conditions that lead to emergence of negative prices on power markets:

  • For technical and cost recovery reasons, nuclear plant operators try to continuously operate at full power.
  • The operation of hydroelectric units reflects factors outside of power demand, for example, compliance with environmental regulations such as controlling water flow to maintain fish populations.
  • Eligible renewable generators can take a 2.2 cents/kWh or $22/MWh production tax credit (PTC) on electricity sold. This means that some generators, primarily those operating wind turbines, may be willing to sell their output at negative prices to continue producing power.
  • There are maintenance and fuel-cost penalties when operators shut down and start up large steam turbine (usually fossil-fueled) plants as demand varies over a day or a week. These costs may be avoided if the generator sells at a loss when demand is low.

Typically in power markets, these operating or subsidy-driven constraints can be accommodated without negative prices, as other more flexible generating units slow down or cut off to keep energy production and consumption in balance on the system. But when the combination of transmission capability, energy demand, and constrained-on energy production is just wrong, negative prices will be the result.

Considering the four cases above, the first (nuclear) and last (fossil-fueled steam turbine) cases can be distinguished from the second (hydro) and third (subsidized wind) cases. In the nuclear and fossil-fuel cases, the short run negative price is absorbed by the generator as a way to minimize costs and therefore maximize profit over some longer period – as the EIA indicates it can be cheaper to pay someone to take the power than to cycle some large generation units down and then back up again. In both of these cases, if the generator anticipated a long enough string of consecutive negative prices, it would be induced by profit considerations to shut down rather than operate.

Herein is a clear distinction between the nuclear and fossil-fueled generators on the one side and hydro generators on the other: environmental constraints may force a hydro operators to continue operating even in the face of an expectation of a long stream of negative prices. As water enters a dam’s reservoir, it can generate power with it, let the water spill without generation, distribute the water for irrigation or other uses, or hold it in the reservoir. If the last three options are maxed out, the hydro plant must generate power. We can think of negative price in these cases as a kind of shadow price of providing the environmental goods which keep the generator on.

The wind power operator receiving Production Tax Credits or other subsidies will similarly choose to continue operating in the face of a long stream of negative prices, at least so long as the negative price is not so great as to absorb all of the subsidy. But like the first two cases, the wind operator is driven by profit considerations to produce at negative prices. In effect, as the power price drops below the marginal cost of production, the wind power operator is induced to share a portion of the subsidy with consumers taking power from the system.

(I’ve argued before that at least in some cases the subsidies are inducing waste. See additional information. Use this link to see a list of all posts on negative power prices at Knowledge Problem.)

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.

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).

Danish wind power ♥s Norwegian hydropower

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Michael Giberson

From time to time a promoter of wind power will encourage the U.S. to follow Denmark’s lead and aim for a much higher levels of wind power on the grid. (Recently Denmark’s legislature established a goal of attaining 50 percent of its energy from wind power by 2020.)

A working paper by Johannes Mauritzen explains one of the key factors supporting Denmark’s current wind power capability: the flexibility inherent in Norway’s vast hydro-power capability. Mauritzen’s abstract:

It is well established within both the economics and power system engineering literature that hydro power can act as a complement to large amounts of intermittent energy. In particular hydro power can act as a “battery” where large amounts of wind power are installed. In this paper I use simple distributed lag models with data from Denmark and Norway. I find that increased wind power in Denmark causes increased marginal exports to Norway and that this effect is larger during periods of net exports when it is difficult to displace local production. Increased wind power can also be shown to slightly reduce prices in southern Norway in the short run. Finally, I estimate that as much as 40 percent of wind power produced in Denmark is stored in Norwegian hydro power magazines.

So, a first step for the United States renewable power policy might be to pick up and move the country a little closer to Norway.

Less facetiously, and projecting a little bit, we might casually infer that the New York power market won’t have too much trouble with a moderate amount of wind power since it also has access to a lot of hydro-power. (11 percent of generating capacity is hydro and another 4 percent is pumped hydro, plus it imports hydro-power from Quebec.) Similarly, we might be more puzzled about all of the difficulties that power system administrators in the Pacific Northwest are having integrating wind into the regional grid, given the extensive hydro-power resources available. (With hydro about 2/3rds of the electric capacity in the region.) Finally, we might be still more surprised by the relative growth of wind power in Texas, which has relatively little hydro-power capacity on its system. (About 0.6 percent of capacity.)

Admittedly, the thing that a mostly-uncontrollable, variable-output technology like wind needs isn’t hydro-power per se, but rather a certain amount of flexibility and control within the power system it is connected to. The necessary flexibility is one part technology and one part power system rules.

The Nordic power system has both the technical means and the supportive power market rules, same for New York, and same for the ERCOT market in Texas (only in Texas the “technical means” are not hydro-power, but rather fast-ramping gas generation along with other resources over which the market has some control).

The Pacific Northwest has tons of flexible capability on the technical side of things* and it has the federal Bonneville Power Administration on the power system rules side of things. Yet somehow the combination of lots of capability and federal agency management produces as much conflict as cooperation.

*About the only caveat in BPA’s defense is that, to some degree, many competing claims to that technical flexibility have already been granted to non-power system users of the water resources involved in the form of environmental constraints, irrigation demands, treaty obligations with Native American organizations, and so on. Maybe the residual flexibility is smaller than it appears.