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Record gas prices wreak havoc on heat rates

By Mike Wilczek

January 23, 2014 - Unprecedented high spot gas prices in the PJM Interconnection, mainly in the load zones along the I-95 corridor, are causing some extreme differences in locational marginal prices, and some unusual and counterintuitive marginal heat rates.

Spot gas prices for some locations climbed over $100/MMBtu, the highest prices ever in the spot market--even when adjusted for inflation--and higher than the January 2004 price spike in New England when spot gas climbed above $70/MMBtu.

Power prices have also climbed to record levels not seen since the summers of 1998 and 1999, when power spiraled out of control in the Midwest and reached $2,000/MWh.

The highest on-peak day-ahead average LMP in PJM at the hub or zone level for Wednesday delivery was $548.83/MWh for one of the easternmost zones, the PSEG zone.

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That was a day-on-day increase of more than $300 and a more than $200 premium over PJM’s Western Hub. The Western Hub on-peak day-ahead average LMP was $302.91/MWh.

With prices so high in the eastern load pockets of PJM, normally less efficient units, higher and higher in the bid-stack, would be dispatched to meet demand. However, these prices are not being strictly driven by electricity demand. They are climbing because of fuel cost.

Demand in PJM is in fact lower than it was in the last cold weather event to hit PJM during the polar vortex on January 7, which triggered a generation emergency in PJM.

More than 36,000 MW of generation was forced off line either for mechanical problems brought on because of cold and heavy use or because gas was not available.

PJM set a peak demand record of more than 141,000 MW that day. Wednesday’s peak demand of more than 135,000 MW was high, but still under the previous winter record.

The Mid-Atlantic region of PJM saw loads reach over 48,000 MW Wednesday, more than 1,700 MW less than the January 7 peak for the same region.

This is where a look at heat rates underlines how in this current cold-weather, high-demand event, power prices are being greatly affected by the interplay between high gas prices and the ability to wheel cheaper power into a high-gas price load pocket.

In essence, the marginal unit setting the electricity price in the eastern zones such as PSEG Wednesday may have been hundreds of miles to the west.

Gas prices cheaper to the west even when congestion costs added

Gas prices were so much cheaper to the west that even when congestion costs from wheeling the power east were added, power generated well to the west set the price in the eastern PJM zones.

Marginal heat rate calculations are often used to get a sense of what generation has a shot at being competitive in a given power market.

The efficiency of gas-fired power plants is measured by the amount of gas used to generate a kWh of electricity. A state-of-the-art combined cycle unit has a heat rate of about 6,500-7,000 Btu/kWh.

So the calculated marginal heat rate of a given market is the market price for electricity divided by the market price for gas. Platts calculates these using a mix of spot gas prices for delivery in the area of a given hub or zone.

In a heat wave, heat rates climb as the price of power increases to get more generators to switch on. But in a cold wave, the gas is being consumed not only to generate power, but also as a heating fuel.

For example, with spot gas prices at $100/MMBtu, a 10,000 Btu/kWh generator would need $1,000/MWh to break even, just on the fuel. The average gas price for the constrained eastern PJM area was about $87/MMBtu.

However, where gas was constrained and expensive, the marginal heat rates fell. Normally when power prices rise, so do heat rates, but power prices did not climb enough to get more generating units to switch on in the gas-constrained, high gas-price zones.

The on-peak marginal heat rate for PSEG Zone was 6,301 Btu/kWh, down from 22,778 Btu/kWh when the average on-peak LMP for PSEG Zone was under $300/MWh. This means it was getting harder for even the most efficient gas-fired generation to compete using such expensive spot gas.

The Eastern Hub, which is the key trading hub for the I-95 corridor, saw similar movement in heat rates. The marginal on-peak heat rate was 6,016 Btu/kWh with the average LMP at $523.94/MWh. The previous day the Eastern Hub heat rate was 19,269 Btu/kWh, with the average LMP at $203.05/MWh.

Impact of PJM’s offer cap on auction outcome unclear

It is unclear what impact PJM’s offer cap had on the outcome of the day-ahead auction. Generators were asked to submit emergency bids if their costs were above $1,000. Those bids would be accepted if needed, but would not set the clearing price. PJM is promising to make generators whole through uplift charges if the waiver is granted by the Federal Energy Regulatory Commission.

Demand response can bid in above the offer cap, but generators cannot. Also, generators who have sold capacity into the PJM market are required to offer their generation into the day-ahead market. The retroactive waiver for cost-based offers is in place from the January 21 through March 1.

Outside of the constrained area, LMPs also rose in the day-ahead auction, but not as much as where gas prices reached record levels.

PJM Western hub, the key trading hub for the Mid-Atlantic region with nodes and gas supply outside the constrained area, climbed to $302.91/MWh for Wednesday delivery, up from $161.27/MWh the day before. However, gas prices were only $4.888/MMBtu. The marginal heat rate jumped to 61,975 Btu/kWh. This meant that almost any gas-fired generator could cover its fuel cost.

The reason this was possible was that there was still electric transmission capacity into the eastern portion of PJM. The same constraints on gas were not there on the transmission system.

The transmission limit on PJM’s Eastern internal interface is more than 5,000 MW--it averaged about 5,800 MW in January 2013. There are other key pathways as well.

The Bedington-Blackoak interface represents a 500-kV line bringing power from the Northwest into the Baltimore-Washington area, which saw on-peak average LMPs between $400 and $500/MWh. The limit on that interface is more than 2,000 MW. The Bedington-Blackoak interface averaged more than 2,2000 MW in January 2013.

The AEP-Dominion interface limit is more than 3,000 MW, bringing power into the constrained Northern Virginia area. The average limit in January 2013 was higher than 3,900 MW. On-peak LMPs for the Dominion Zone averaged $209.52/MWh for Wednesday delivery, with a marginal heat rate of 3,834 Btu/kWh.

This does not mean that congestion was not an issue. The Eastern hub had $229.24/MWh of congestion charges compared with the Western hub with 28.03/MWh.

The congestion was visible in divergent LMPs, but there was room to bring in enough power that prices did not go straight to the offer cap of $1,000/MWh or higher with demand response setting the price.

Average day-ahead on-peak LMPs climbed even higher in the auction for Thursday delivery. PSEG zone’s on-peak average climbed to $653.45/MWh and the Western Hub jumped to $536.25/MWh.

The highest priced zone, still in the eastern part of PJM, was PEPCO, which hit $759.47/MWh, up more than $330. The outage of the two Calvert Cliffs nuclear reactors in Maryland Wednesday drove up clearing prices in the Washington DC area.

But spot gas prices, although still extremely high, were receding. This meant that heat rates had some room to rise in the gas constrained parts of PJM. The PSEG Zone on-peak average heat rate climbed to 8,061 Btu/kWh for Thursday delivery.

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