Tag Archives: negative prices

Negative power prices due to wind power’s subsidy

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Michael Giberson

On the NYTimes.com Green blog, Matthew Wald reports on “An argument over wind.” The issue is the scheduled-to-expire Production Tax Credit for wind power. As previously mentioned here, former PTC-supporter Exelon Corp. has come out against the PTC extension. It parted ways from the American Wind Energy Association, of which it had long been a member, over the issue.

Wald reports on an Exelon-funded study done by The NorthBridge Group, “Negative Electricity Prices and the Production Tax Credit.” According to Wald:

The study sponsored by Exelon, prepared by the NorthBridge Group, which does extensive consulting for utilities around the country, found pockets where the number of negative hours reached 12 percent or more. While various types of electricity generation have received subsidies over the decades, said Frank Huntowski, one of the authors, “I don’t think we’ve seen something as dramatic as this.’’ …

Negative pricing occurs mostly on spring and fall nights when the wind is blowing strongly but offices, stores and factories are mostly closed and temperatures are so mild that there is virtually no demand for home heating or air-conditioning. The phenomenon existed before the surge in construction of wind machines, but the new industry is making it worse, some industry participants say, especially for companies with baseload plants that were built to run at a steady rate around the clock.

That is a special problem for Exelon, which runs many nuclear plants in the Midwest; nuclear plants cannot change their output quickly.

Long-time readers may recall that we’ve discussed negative power prices many times before here on Knowledge Problem. This link will execute a search of the KP archives: negative+prices.

Related:

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.)

Scottish wind power plants paid not to produce

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Michael Giberson

The Telegraph has reported “six Scottish wind farms were asked to stop producing electricity on a particularly windy night last month as the National Grid was overloaded.” The operators were paid a total of £900,000 to take the night off, likely earning more from not operating than they would have earned from selling power that night.

The payments were discovered by the Renewable Energy Foundation, a green think tank, which accused the Government of building too many wind farms in northern Britain.

John Constable, director of policy and research, said not enough care had been taken to ensure there were enough high-voltage cables to transfer the power to other parts of the UK when it was needed.

“Hasty attempts to meet targets for renewable energy mean some Scottish wind farms are now in the extraordinary position of not only printing money when they generate, but printing it even faster when they throw their energy away,” he told the Sunday Times.

The Renewable Energy Foundation provides additional information on its website:

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

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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:

Give it away now: Wind power and the price of electricity

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Michael Giberson

Forbes recently ran a story by Jonathon Farey, “Wind Power’s Weird Effect,” about how sometimes high wind power output and limited transmission capability combine to produce wholesale power prices dropping to zero or below.  (Of course regular readers here have been aware of the issue at least since last November.)

Much more informative was Farey’s story on inventor Leif Hauge and the energy-saving pressure exchanger he invented for use in desalination plants. UPDATE ADDED: (Of course, if I were a better reader of Aguanomics, I would have been aware of the issue at least since last September.)

Negative power prices in ERCOT West: Charts for Jan-June 2009

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Michael Giberson

Below are three charts showing data on ERCOT West zone power prices for the January-June 2009 period.  The charts were derived from data provided through the ERCOT website, on their “Balancing Energy Services Market Clearing Prices for Energy Annual Report” page.

These charts were prepared in the same way, including use of the same axis scale, as earlier charts showing 2008 data in order to make comparison easier.  As discussed in this post published earlier today, average power prices are lower in 2009 than they were in 2008, but prices have gone negative less frequently this year due to the more frequent use of non-price methods of managing grid congestion.

As the histogram chart below shows when compared to its 2008 counterpart, when prices have become negative in 2009 they haven’t been quite so negative as before (likely also due to the congestion management methods used).  Last year about 70 percent of the negative prices were $-30 MWh or below.  So far in 2009 the comparable number is only 44 percent.

CHART_freq_of_neg_prices_ERCOT-WEST_by_date_2009_June

Frequency of negative prices in ERCOT West, January-June 2009

CHART_freq_of_neg_prices_ERCOT-WEST_2009_June

Frequency of negative prices by price bin, ERCOT West, January-June 2009

CHART_average_prices_ERCOT_WEST_by_date_2009_June

Daily average prices in ERCOT West, January-June 2009

2009 power prices in ERCOT’s West zone: a mix of wind power, natural gas prices, transmission constraints, and (inefficient) congestion management practices

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Michael Giberson

ERCOT reached a new peak load record last week, beating the record set just a week before. Boone Pickens is backing off a little from earlier ambitions to build the world’s largest wind power facility near Pampa, Texas. The Wall Street Journal reported recently that low natural gas prices are limiting interest in new renewable power projects. (It seems like such an obvious point that I wonder why they bothered to publish it. In any case, what has changed since they reported the same idea last October?)

Seems like a good time to follow up on earlier posts on wind power and electric power prices in ERCOT’s west zone.

In 2009 so far, power prices in ERCOT have been very low, averaging in the $22 MWh – $32 MWh range, with the West zone at the low end of that range and the Houston zone at the upper end. [All price data from the ERCOT website.] The main factor responsible for low ERCOT power prices has been low natural gas prices, but wind power is the primary reason pushing prices even lower in the West.

Natural gas fueled generators are typically the units that are “on the margin” in ERCOT, meaning the units available to adjust up or down in response to changes in demand and therefore the units most likely to be influencing the price in ERCOT’s balancing energy market.  Over the first 6 months of 2008, with natural gas prices beginning near $7 per million BTU and peaking mid-year over $13) average power prices in the West zone were about $55 MWh and Houston zone prices were over $87 MWh.  This year has seen NYMEX natural gas prices drifting from just over $4 per million BTU in January, down below $3.50, and back to about $3.85 recently.

Wind power output is up in 2009, due largely to significant wind power capacity additions in 2008 and early 2009. (2009: 2,300 MW average output; 2008: 1,916 MW)  To some extent wind power output lowers energy prices statewide.  But when wind power output is high, current transmission limits mean that not all of the power generated in the West zone can readily flow east and south where much of the state’s power consumption takes place.  Transmission limits are easily reached these days, given existing wind power capacity, so the effect of wind power on prices has been intensified in the West.

But negative prices are, surprisingly, less frequent in 2009. (Less than 14 percent of the time in 2009, compared to over 19 percent of the time during the first six months of last year.  The outcome is contrary to my projection earlier this year.)

As explained here before, negative prices in ERCOT’s West zone emerge largely due to the federal Production Tax Credit and Texas state subsidies available to wind power producers, which provide the producers incentives to continue to supply power even when they have to pay the ERCOT market to take the power away.  The subsidies lead to some economic waste in that some cheap, slow-moving baseload generators will be induced to shut down and restart much more frequently than otherwise, even though it would be cheaper overall for the wind generators to curtail instead. (But it is hard to put a good number on this economic waste because analysis of the relevant subsidies for various energy sources and associated externalities becomes very complex very quickly.)

Frequency of Negative prices by Month, ERCOT West, 2008 and 2009

2008

2009
Jan

8.61%

12.53%
Feb

18.82%

11.53%
March

33.33%

15.66%
April

20.63%

23.06%
May

19.62%

12.50%
June

16.46%

7.19%
Jan-Jun

19.55%

13.77%

What has happened in 2009 is that much more of the congestion created by high levels of wind power output in the West has been managed using reliability procedures instead of market-based procedures. Nothing sinister going on here (probably), just a result of the way the ERCOT zonal market design works (or not) to handle congestion of the transmission grid.

The zonal market design limits market-based methods for congestion management to a select number of so-called “commercially significant constraints.”  When other transmission elements become congested, operators must take recourse to non-market methods to manage the grid.  A line between the West zone and the South zone has become frequently congested this year, but no West-to-South lines are currently monitored as part of the market.  When the line approaches its limit, ERCOT operators identify a generator that can relieve the West-to-South line and then pays the generator to curtail production.  The cost of these reliability-based processes is averaged out to all consumers ERCOT-wide.

The reliability-based curtailment of power output in the West zone reduces the likelihood of congestion on the West-to-North zone elements that are part of the zonal market, which reduces the downward pressure on price in the West zone.  Without this out-of-market curtailment going on, power prices would be a lot lower on average in the West zone, and probably would be negative more often as well.

I haven’t found ERCOT data showing just how extensive this out-of-market curtailment is, but reportedly in some months this year the amount of intra-zonal congestion management has been many times the amount of market-based congestion management.  ERCOT updates its list of “commercially significant constraints” each year, and is beginning the review process for the next update, so maybe they’ll add the West-to-South line to the zonal market.  Perhaps also, data on congestion management practices will become available as part of that process.

A better solution than updating the zonal market list of constraints is to shift to a nodal market design, something that ERCOT expects to do in 2010.  A nodal market design automatically includes effectively all transmission elements as part of a market-based approach to congestion management.  The result is that congestion is more likely to be managed efficiently, and transparent price signals better reflect the value of power at different locations on the grid.

NOTE: Link to post charting ERCOT West prices, January-June 2009, including data on frequency of negative prices.

Negative power prices in ERCOT West – 2009 so far

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Michael Giberson

If you thought power prices in ERCOT’s West region were interesting in 2008, keep an eye on the prices in 2009. (For background see my earlier post on negative prices in ERCOT West for 2008. Note on updated data here.)

Late 2008 saw a few developments of note for the region:

  • Almost 2000 MW of wind power capacity was added to ERCOT from September to December, most of it in ERCOT West.
  • When ERCOT updated its zonal boundaries last Fall, a few dispatchable generators – coal and gas units – were moved from ERCOT West to the ERCOT North region.*
  • Natural gas prices, which ranged above $10 per MMBTU last Summer, are now below $5 per MMBTU.
  • The recession, and particularly the drop in oil and gas prices, will tend to reduce electric power demand throughout the state.

(*There are technical reasons justifying the change in zone boundaries, which wasn’t without controversy, but combined with the first bullet point the practical effect is that the West region prices will be even more reliant on intermittent wind power output.  ERCOT reviews zonal boundaries every year.)

How does this all shake out?  Safe to say that electric power prices in ERCOT generally, and ERCOT West especially, will be much lower this year. Peak prices will be kept down by lower demand and low natural gas prices.  Offpeak prices will be lower and more volatile because of the confluence of all four factors.

The key to producing negative power prices is subsidized wind power output in ERCOT West net of local load, compared to the transmission system’s capability to deliver the excess power out of the area.  Lower load combined with more wind power capacity indicates a more volatile price situation.

Will ERCOT West see more frequent negative prices this year?

Yes.  In fact they already have.

In January 2008, ERCOT West was faced with negative prices about 8.3 percent of the time; in January 2009 the region faced negative prices 12.5 percent of the time.  This increase in the number of negative priced periods resulted despite a drop in average wind speed in the area.  (At the Abilene Regional Airport, near the heart of the wind power in the area, the average wind speed in January 2008 was 12.1 mph, while in January 2009 it was 10.7 mph.)  Less wind, but more frequent negative power prices.  Not surprising given the substantial increase in wind power capacity, and not yet a comparable increase in transmission capacity.

So far, February 2009 has been a little windier than February 2008 at the Abilene Regional Airport.  While I haven’t examined February price data yet, I wouldn’t be at all suprised to see that February 2009 shows even more frequent negative prices than those of February 2008 (negative prices 18.8 percent of the time).

UPDATED: Negative power prices in the West region of ERCOT in 2008

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Michael Giberson

Last November I posted remarks on the frequently observed negative prices for power in ERCOT’s West region. In the post, which analyzed data from January through November, I linked the negative prices to the wind power capacity relative to the transmission capacity, and to the effects of the Production Tax Credit and other subsidies available to wind power producers in Texas.

I recently extended the data set to include all of 2008 and have updated the charts in the original post. As expected at the time of the earlier post, November and December did see a return of frequent negative prices (which had almost entirely disappeared from mid-June through mid-October.) All told, about 14 percent of ERCOT’s 15-minute pricing intervals fell below zero.

The charts are reproduced below along with a new chart showing the average price each day over the year. The unweighted average price for ERCOT West for the year was a positive $53.34. Unfortunately for wind power producers in the region, their output was higher during times that the price was low and their output was lower during times that the price was high.

The charts were derived from data provided through the ERCOT website, on their “Balancing Energy Services Market Clearing Prices for Energy Annual Report” page.

Frequency of negative prices in ERCOT West, 2008

Frequency of negative prices in ERCOT West, 2008

Frequency of negative prices by price bin, ERCOT West, 2008

Frequency of negative prices by price bin, ERCOT West, 2008

Daily average prices in ERCOT West, 2008

Daily average prices in ERCOT West, 2008

What fixed vs. flexible retail power rates in Texas tell us about wind power in the ERCOT market

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Michael Giberson

Electric power consumers in (the ERCOT portion of) Texas have many choices when it comes to the electric power retailer they wish to enroll with, and typically each retailer offers a handful of different plans.  Historically speaking, this is a crazy cornucopia of consumer choice not seen anywhere else in the world. Or, seen from another point of view, a lot of data for economists interested in retail electric power not available anywhere else. This post dissects a few bits of that data and offers a preliminary conclusion.

One choice available to many Texas power consumers, but rare elsewhere, is between rates that are variable from month-to-month and rates that are fixed for a longer term.  Typical terms for fixed rate offers are six months and one year, but terms as long as five years are offered.

The primary difference between a variable rate and a fixed rate is whether the customer or the retailer is exposed to the risk of adverse price movements.  A little simple economics leads one to expect that if the retailer is to take on the risk of adverse price movements, the customer will have to pay the retailer to take on the risk. So we’d expect that fixed rate contracts would tend to be higher than variable rate contracts.

And that is just what we see in the offers listed at www.powertochoose.com, the State’s online list (just comparing average offered fixed rate deals to average offered variable rate deals). For example, in the Houston area the average rate for fixed price offers was 14.04 cents/kwh and the average rate for variable price offers was 13.60.  In Dallas, fixed price offers averaged 13.35 cents/kwh and variable price offers averaged 13.03.

But elsewhere in north Texas, specifically the AEP North Texas distribution service territory, the average rate for fixed price offers was 12.7 cents/kwh and the average rate for variable prices offers was 12.8 cents/kwh. So, apparently in parts of north Texas, electric retailers in effect are willing to pay consumers a little bit in exchange for taking on price risk.

Crazy, right?

Well, not exactly.  A fixed rate offer transfers the exposure to both adverse and beneficial price movements.  If a retailer expects prices to fall (relative to the current market expectations), then it would want to encourage customers to lock in at current rates; if the risk of a price movement down is larger than the risk of a price movement up, and retailers are less risk-averse than individual consumers, then retailers would be willing to pay consumers to take on the risk.

And why might retailers in certain parts of north Texas expect prices to fall? Might it be access to large quantities of wind power that sometimes can’t reach Dallas or Houston due to transmission limits – sometimes such large amounts of wind that prices in the ERCOT west region go negative?

I think so.

Admittedly, simple averages of offered fixed and variable rates provide only the coarsest of indicators of what is going on. Maybe more sophisticated analysis makes the anomaly disappear. But at first glance, it looks like another market indicator of the temporary excess supply of subsidized wind power in west Texas.