Retire it, retrofit it, run it; which of these applies to your coal plant?

(This is my prepared speech for Oct. 17 at the marcus evans Power Plant Management Summit in Illinois. For those of you who were there, note that I ramble when wound up on coffee and crossaints, so what follows has only some resemblance to what I actually said. I did thank Kent and Jennifer, by the way.)

Good Morning! Before I forget, I would like to thank Kent Knutson, our ace numbers guy, and Jennifer Habig, for putting together the slides that I’ll be showing this morning. Kent is doing a great job putting together our new Fossil Fuels Tracker product, which is keeping up with the changes in the fossil fuels end of the power industry. It’s a constantly evolving picture, so he needs to move fast. I’m often digging up new information about what coal plants are closing, and which ones are getting emissions retrofits, which keeps Kent busy.

Much of this picture for troubled coal power changes, and changes quickly. American Electric Power, for example, applied last year with the Kentucky Public Service Commission for approval to put a scrubber on the coal-fired, 800-MW Big Sandy Unit 2. Then, after re-looking at the numbers, it withdrew that application in May. And it hasn’t said yet what it’ll do from here. Retirement is looking very possible, though, since AEP is under a deadline in a federal consent decree to shut it or scrub it. Big Sandy Unit 1, smaller and older, is definitely headed for the scrap heap under that decree.

(Note that I talked to AEP’s Mark McCullough the day before this speech and he said the decision still hasn’t been made yet on Big Sandy Unit 2, but that a scrubber is still in the options being considered.)

The numbers are scary when it comes to coal plants and their often limited futures. There’s a new study from The Brattle Group, which is an update to work it did in 2010. It finds that 59,000 MW to 77,000 MW of coal capacity are likely to retire over the next five years. That’s about 25,000 MW more than previously estimated. Since 2010, both natural gas prices and the projected demand for power have dropped. That, in part, resulted in accelerated coal plant retirements. As of July, about 30,000 MW of coal plants, which is roughly 10% of total U.S. coal capacity, had been announced by their owners to retire by 2016.

Brattle estimated that compliance with EPA regulations will lead a large number of coal plants to install emissions equipment instead of retiring. Baghouse and activated carbon injection installations are seen as the most common approach. There would be 121 GW to 132 GW of coal plant capacity installing baghouses. Brattle says there would be 136 GW to 183 GW of coal capacity installing ACI. Also, Brattle estimated that 48 GW to 52 GW of wet flue gas desulfurization, and 8 GW to 15 GW of dry sorbent injection will be installed.

For anyone here in Chicago, this trend of coal shutdowns is all too real. Midwest Generation decided to shut down the coal-fired Fisk and Crawford plants in Chicago in September of this year. That advanced a schedule announced in February that would have seen Crawford shut at the end of 2014 and Fisk at the end of 2012. Crawford is a 532-MW plant. Fisk is, or was, a 326-MW plant. They date back to operational starts in the late 1950s and early 1960s. Plants of that age all around the country are in big trouble.

One big issue is that the underlying EPA regulations, leading to many of these shutdowns, are in flux. For example, EPA on October 5 asked the full U.S. Circuit Court of Appeals for the D.C. Circuit to review an August 21 decision. That decision was by a three-judge panel in that court. The panel tossed the Cross-State Air Pollution Rule. That rule imposed big SO2 and NOx cuts on dozens of coal-fired power plants in the eastern U.S. There was a long list of power companies and states that appealed the rule. The panel ordered that the older Clean Air Interstate Rule remain in place while EPA rewrites or replaces CSAPR. It would take months, at least, for EPA to come out with something new to replace CSAPR. And the ongoing appeal just adds to the time lost.

Air rules are in flux, and so are the plans of some utilities

Now, many power generators have said they’ll go forward with CSAPR-related projects in the meantime. But that is not always the case. The Kentucky Public Service Commission, for example, recently approved a reduced emissions plan from Big Rivers Electric. Big Rivers will not construct the most costly projects it initially proposed. The modified plan costs nearly $59 million, which is $225 million less than Big Rivers originally proposed. Most of the changes are the result of the August 21 CSAPR court decision. The commission said a replacement rule might come down the pike later on, so Big Rivers may be required to install additional controls in the future. But not right now.

In another example, while some of the underlying clean air rules are in flux, Oklahoma Gas & Electric said recently that it plans several new emissions projects. That was in an integrated resource plan that it filed October 9 with the Arkansas Public Service Commission. The planned projects include Low NOX Burners, Dry Sorbent Injection and Activated Carbon Injection. But, the utility said it would be premature to move forward with costly dry scrubbers at this point. That is something EPA has been pushing for under its Regional Haze rules. The utility has EPA’s haze ruling tied up in court. Thus the scrubber delay. The company has five coal units at the Muskogee and Sooner power plants with over 2,500 MW of capacity. By the way, it’s also looking at coal unit shutdowns or conversion to natural gas of some of those units, depending on future needs and environmental restrictions.

The new air rules can lead directly to financial problems, as well. For example, Homer City Generation LP, which is a new affiliate of General Electric, filed applications October 9 with the Federal Energy Regulatory Commission. That is related to its takeover of the 1,884-MW Homer City coal plant. An affiliate of Edison International is giving up lease rights on the plant, due to financial problems, including the costs of new scrubbers now being installed on two of the plant’s three units. The third unit got a scrubber a few years ago.

And of course the power industry is under constant pressure from environmental groups to go beyond existing air rules. That even includes in Maryland, which a few years ago passed a Healthy Air Act that forced scrubber installations on several plants. That includes the Morgantown, Chalk Point, Dickerson and Brandon Shores plants.

The Sierra Club recently launched a public pressure campaign to force emission reductions from the coal-fired C.P. Crane and Herbert A. Wagner plants located near Baltimore. The club said that Crane and Wagner threaten the region with SO2 pollution.  A billboard they put up on Interstate-95 in Baltimore asks the plants’ presumptive new owner, Riverstone Holdings, if it has “Buyer’s Remorse Yet?” The billboard features a picture of a child suffering from asthma, with a call to retire the plants. Exelon, the current owner, says the plants comply with the state Healthy Air Act. Exelon is selling its three Maryland coal plants to Riverstone. The third plant is Brandon Shores, by the way, which recently got a scrubber installation, making it cleaner than the other two. But the Sierra Club would like that plant shut, as well.

Compliance methods are many when it comes to the air rules. FirstEnergy, besides shutting, in some cases permanently, a number of coal plants outright, is looking at co-firing natural gas and coal at five of its coal plants. The decision on these projects will depend on factors like proximity to a natural gas pipeline, the price of gas in the future and the cost of equipment upgrades. The first decision would likely be made in 2014 for Hatfield’s Ferry in Pennsylvania. The other four plants being considered for co-firing are Mansfield and Mitchell in Pennsylvania, plus Pleasants and Harrison in northern West Virginia. At Hatfield’s Ferry, any new equipment would likely allow 25% to 40% of the plant’s fuel to be gas. That’s a lot of coal that would get displaced.

Moving west, the Los Angeles Department of Water and Power released a draft resource plan recently that outlined how it plans to get off of coal-fired power. That would be by exiting its investment in the Navajo power plant in Arizona by 2015. Also, it is working with other participants in the Intermountain coal plant in Utah to convert it to natural gas. Intermountain has two units with a combined capacity of 1,800 MW. Los Angeles is the operating agent at the plant for a number of municipal utilities. The in-service date for the converted Intermountain facility will likely be sometime after 2023. This is all largely being done because Los Angeles is under California mandates to reduce greenhouse gas emissions.

There is some good news in a whole field of bad. Detroit Edison has reversed itself, a bit, on some retirements. It said in a 2011 cost recovery case at the Michigan Public Service Commission that in 2015 it was looking at possible retirements. These would be at Harbor Beach, River Rouge Units 2 and 3, St. Clair Unit 7 and Trenton Channel Units 7 and 9. The retirements were to be offset in part by the addition of a new gas-fired combined cycle unit. But, the utility told the commission recently that in part due to successful testing of dry sorbent injection and activated carbon injection, four of these units can, cost-effectively, comply with EPA’s Mercury and Air Toxics Standards. Operation of these units beyond 2015 will also allow the deferral of that new combined-cycle power plant. The company has assumed, on the other hand, the retirement of the coal-fired Trenton Channel Units 7 and 8 in 2015. However, Detroit Edison said the ultimate retirement of those units remains uncertain.

A few new coal plants in the works, but not many

There are still a handful of coal-fired power projects in the works, despite the gloom and doom. 2012 is a solid year mostly due to the 1,600 MW Prairie State plant here in Illinois coming on-line this year, along with the new 600-MW Turk plant that AEP has built in Arkansas. Then things fall off as the pipeline of new coal projects dries up due to regulatory and other pressures that decimated a lot of proposed projects.

Besides Prairie State, Duke Energy over in Indiana is getting close to wrapping up construction on its new Edwardsport gasification project. Southern Company is building the Plant Ratcliffe IGCC in Mississippi. Notable is that both Duke and Southern are running into a lot of grief at their state commissions over ballooning costs for these projects. That may make utilities and their state commissions a lot more skittish about such projects in the future.

If EPA’s proposed new CO2 rule for new power plants, which sets emissions targets at the same level as new gas-fired plants, ever goes into effect, conventional new coal plants may not get built for a few years. And they may not be that “conventional” at that point, considering the CO2 controls that will need to be attached to them or be an integral part of them. One of the best near-term possibilities for coal is gasification. There’s a gasification plant, for example, in North Dakota that has piped CO2 for years into Canada for enhanced oil recovery. The CO2 stays in the ground after forcing oil to the surface that would otherwise not be recoverable. So the technology is there for doing CO2 capture and storage.

In one case where this principle is being applied to a new plant, Hydrogen Energy California is proposing a polygeneration project in Kern County, California. The project will gasify a blend of 75% coal and 25% petroleum coke. The syngas will be purified to hydrogen, and used to generate a nominal 300 MW. CO2 from the project will be used for enhanced oil recovery in the nearby Elk Hills oilfield.

Also, Summit Power Group is advancing its Texas Clean Energy Project. It’s a polygen that Summit is developing near Odessa, Texas. It’ll capture 90% of CO2 for enhanced oil recovery in the Permian Basin of West Texas. One Summit official told me a while back that based on CO2 demand alone, the company could build several of these projects in this area, but getting all that power onto the grid would be a big issue. This project will also produce more than 700,000 tons per year of urea as fertilizer for farmers and 200-MW of power for CPS Energy. That’s the municipal utility for the city of San Antonio. The start of construction for the project is targeted for early 2013, with up to four years to complete it from there.

Coal production plunges as coal plants run relatively little

The new EPA regulations are a long-term issue for the U.S. coal production industry. Though the industry hopes the surviving coal plants will be run harder, making up for the coal plant shutdowns. After all, most of the plants that are being shut, or will be shut, are old and relatively little used. Right now, the biggest problems for the coal industry are abundant and cheap natural gas, due in part to the new “fracking” method of getting at shale gas reserves. Also, it’s due to slack power demand in a weak U.S. economy.

Due to these factors, U.S. coal production during the second quarter totaled 241 million tons, which was 9.4% lower than the previous quarter. That’s according to the U.S. Energy Information Administration. The most significant coal production decrease was in the state of Wyoming. That’s the home of the Powder River Basin, which produces nearly half of U.S coal. Many coal producers, including Arch Coal and Peabody Energy, have slashed production in the face of this new market reality.

The data shows that coal inventories at power plants are still pretty high right now. Natural gas prices have gone up lately from historic lows earlier this year. That, plus, a pretty hot summer with heavy air conditioner load, has helped with coal burn. Gas producers have shut-in a lot of wells to get gas prices up. They’re getting market share at the very low prices, but aren’t making any money at it. Gas prices are up enough, at this point, to help plants fired by Powder River Basin coal. They tend to have the cheapest generating costs. But the somewhat higher gas prices haven’t been much help, yet, for power plants burning other, more expensive coals.

There’s an old adage in the coal industry. In a bad market, you’re just one cold winter or one hot summer away from a good market. If that was ever really true, it’s not at the moment. The coal producing and coal-fired generating industries need a kind of perfect storm of good things to happen from here. Several hot summers and cold winters would help. More friendly EPA rules. More costly natural gas. Will state and federal regulators put tighter rules on fracking?

Thank you.

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.