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Spark and Dark Spreads Indicate Profitability of Natural Gas, Coal Power Plants

graph of daily PJM Western Hub wholesale electricity price and delivered fuel costs, as explained in the article text

Source: U.S. Energy Information Administration, based on price data from SNL Energy

Relative profits for some natural gas- and coal-fired generators in several Midwestern and Mid-Atlantic states may have decreased since 2016 because of higher natural gas and coal prices and lower wholesale electricity prices. A common measure of profitability for power plants within a region is the difference between their input fuel costs, such as the cost of coal or natural gas, and their wholesale power price.

For electric power generation fueled by natural gas, this difference is called the spark spread; for coal, the difference is called the dark spread. Spark spreads and dark spreads in the first part of 2017 were lower than the 2016 averages in the PJM Western hub, which covers electricity generation in parts of several Midwestern and Mid-Atlantic states.

Changes in spark spreads and dark spreads for a given electricity power market indicate the general operational competitiveness of coal-fired or natural gas-fired electric generators in meeting the market’s electricity demand. These spreads are calculated by comparing the day-ahead, wholesale power market price with the delivered input price of the fuel, and are adjusted for the energy content of the fuel and the relative conversion efficiency of power plants. These values can then be compared with wholesale power prices, which, in this example, are the average day-ahead prices at the PJM Western hub.

Delivered coal prices vary among coal supply regions based on the quality of coal, the transportation costs of shipping the coal, and other contract terms. Natural gas prices vary regionally and are calculated using spot market prices, which can be volatile on a day-to-day basis.

Coal and natural gas have different energy contents, and the power plants using these fuels have different heat rates, or energy conversion efficiencies. For this reason, spark and dark spreads are location-specific and reflect the characteristics of the fuels and the technical specifications of power plants in a given market.

For example, natural gas consumed in the electric power sector in the PJM region has an estimated heat content of 1,033 British thermal units (Btu) per cubic foot of natural gas. So far in 2017, the average price for natural gas in this area has averaged $2.54/million Btu, based on prices at the Texas Eastern Transmission Market Zone 3 (Tetco M3) trading hub, which generally reflects natural gas prices in Pennsylvania, New Jersey, and New York. Spot prices within PJM vary widely because of pipeline constraints transporting natural gas from production areas in the Appalachian region to different markets.

Natural gas combined-cycle plants in the PJM region are generally expected to produce one kilowatthour of electricity for every 7,300 Btu of natural gas. In the PJM region, combined-cycle plants are more commonly operated in direct competition with coal-fired generators. At the national level, average heat rates for all natural gas-fired generators have decreased over time (i.e., become more efficient) as more efficient natural gas power plants such as combined-cycle units have been installed and as older and less efficient units have been retired or converted to more efficient units.

Coal consumed in the PJM region has an estimated heat content of 22.5 million Btu/short ton, representing the consumption-weighted average heat content of various coal types. Coal prices in the region have averaged about $55/short ton so far this year. Adding in an assumed coal transportation cost of $17/short ton, the estimated delivered coal costs translate to about $3.20/million Btu, or about 34% higher than delivered natural gas costs. PJM-region coal plants are, on average, less efficient than natural gas combined-cycle units, requiring about 10,500 Btu of coal to produce one kilowatthour of electricity.

Although PJM-region spark and dark spreads appear to indicate that natural gas-fired units have been more profitable than coal-fired units recently, many factors affect these calculations, including the selection of representative fuel prices, generator heat rates, fuel delivery costs, and time of year considered.

Principal contributor: Augustine Kwon

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Bob Meinetz's picture
Bob Meinetz on Oct 21, 2017 2:38 pm GMT

Augustine, a comparison of recent quark spreads (wholesale price of electricity minus cost of uranium) with dark and spark would be helpful in debunking the myth nuclear generation is uneconomical.

Using this metric, in 2015 nuclear energy was four times more economical than both natural gas and coal (its fuel cost was four times lower). It takes very little uranium to make a lot of energy, and there is lots of uranium in the earth’s crust.

However, utilities are less interested in quark spreads than spark and dark, for two reasons: 1) the price of uranium is relatively stable, and 2) with higher security, capital, regulatory, and legal expenses (to fight nonstop legal challenges from renewables/fossil industries and “environmental” groups), nuclear plants have higher operating expenses: about five times higher than natural gas, and twice as high as coal.

So how does nuclear compare overall? With fuel, maintenance, and operation expenses considered on a per-MWh basis, nuclear costs 23% less than natural gas and 31% less than coal. Myth debunked.

Nathan Wilson's picture
Nathan Wilson on Oct 23, 2017 1:12 pm GMT

As the amount of electricity from wind and solar increases, a factor not shown in the graphs will start to take large role: the power price varies with time, and dispatchable generators can stop producing when power prices are too low.

Each category of generator will have a different average power selling price, and increasingly, wind and solar will tend to produce at times of day and year when prices are lowest.

Conversely, coal and gas will harvest the peaks in the power prices, allowing them to stay profitable even when average prices are falling. So we should not expect a “tipping point” after which renewables can continue to grow without subsidies; it will just keep getting harder as penetration increases.

Joe Deely's picture
Joe Deely on Oct 23, 2017 6:50 pm GMT

Conversely, coal and gas will harvest the peaks in the power prices, allowing them to stay profitable even when average prices are falling.

Nathan, that might work for NG but not for coal. Let’s look at some areas with strong renewable sources and estimate the capacity of coal in those regions/states by 2030.

Western US – 11 states – CA,OR,WA,MT,ID,WY,UT,CO,NM,AZ,NV
Currently 30.4GW of coal – by 2030 < 5 GW

West North Central – 7 states – Iowa, Kansas, Missouri, Minnesota,Nebraska, North Dakota, South Dakota
Currently 34.6 GW of coal – by 2030 5-10GW

West South Central – 4 states – Arkansas, Louisiana,Oklahoma, Texas
Currently 34.6 GW of coal – by 2030 5-10GW

Currently 34.6 GW of coal – by 2030 < 2 GW

Even PA and OH
Currently 27 GW of coal – by 2030 < 10 GW

Average prices in ERCOT were about $27MWh in 2015 and $25/MWh in 2016. Should be a little higher in 2017.

For SPP(Southwest Power Pool) the summer of 2017 prices were about $26/ MWh.

Good luck finding coal plants that can operate in those markets. The only thing that will keep some coal alive is that CF of remaining plants should rise as more and more coal shuts down.

One last thing – if prices rise a lot for times of day with low solar/wind then solar/wind/storage will become more competitive.

Coal – mostly dead by 2030. NG – still doing ok nationally – but dropping in some markets like CA.

Helmut Frik's picture
Helmut Frik on Oct 24, 2017 5:21 am GMT

“problem” for coal power will be that the point when the canibalisation effect becomes relevant (share of renewable generation in grids of significant size) it is already well behind the point in which coal power stations can earn their costs in the remaining hours. And the flexible generators are always in competition with grid extensions, which also allow to bring power to the users when local solar and wind do not deliver. Which limits the price premium which can happen in the area of 10-20€/MWh during most of the time. Same effects are delivered by flexible loads and storages.
This is why german grid operators like 50 Hz do not expect this effect to become relevant belos 60-80% grid penetration of renewables.
Also it remains a question how much subsidy exists if a generator gets a guaranteed price to be able to produce, if this price is significant lower than any other alternative producer could deliver, in case this might be neccesary in some future (which is unsure)

Helmut Frik's picture
Helmut Frik on Oct 24, 2017 5:26 am GMT

Ad to this the higher capital costs and repair costs of the complex nuclear systems, and the market behaviour which does not favor nuclear becomes understandable. As long as the plant is already built and payed for, and as long as nothing breaks, nuclear power plants can provide power a bit cheaper than natural gas and hard coal, but this is only correct as far as these conditions apply. If not it is often “game over” for the nuclear plants today, because the expectation of rising wholesale power prices has gone in todays markets. Unless nuclear receives significant subsidys to remain open.

Bob Meinetz's picture
Bob Meinetz on Oct 24, 2017 4:40 pm GMT

“As long as nothing breaks?” Helmut, maintenance is included in EIA’s calculation, so someone’s already thought of that.

If anything, “the expectation of rising wholesale power prices” would encourage keeping economical, existing plants open. So your conclusion that means “game over” for nuclear makes no sense either.

Mark Heslep's picture
Mark Heslep on Oct 25, 2017 1:29 am GMT

And yet the new Dattln 4 coal plant connects to the German grid in a couple weeks.

Helmut Frik's picture
Helmut Frik on Oct 25, 2017 2:22 pm GMT

And is already deprecated to around 1€, because it will not earn significant amounts of money any more. It was practically finished already many years ago, but was struck in a legal battle. The utility did win this juristical fight, and then after some time of thinking weather it will be cheaper to knock down the brand new coal power plant or get it running, they decided to go threw the test procedures and make it running.

Helmut Frik's picture
Helmut Frik on Oct 25, 2017 2:25 pm GMT

“if nothing breaks. The costs calculated for the french power plants and those published for some US nuclear power plants including some repairs are higher than the equivalent numbers I hear here for hard coal power plants, og gas power plants in the US. So significant repair costs can kill a nuclear power plant economically at any time.

Bob Meinetz's picture
Bob Meinetz on Oct 26, 2017 12:37 am GMT

Helmut, like at all other power plants, things break at nuclear plants all the time. They’re fixed, and life goes on – you’d be amazed.

Nuclear power plants are very, very complicated facilities, but fortunately there are very, very smart people there to take care of things. They have wrenches, screwdrivers, all kinds of fancy tools to get the job done.

Helmut Frik's picture
Helmut Frik on Oct 26, 2017 8:27 pm GMT

And they produce complete new boiler, generators, turbines and other big pieces of equipment just with their wrenches and screwdricers and some pieces of scrap metal they find on site, in parallel to their other work in the power stations, we all know that…..

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