The recent news for coal-fired power generators and the coal companies that supply them was almost universally bad, with a number of generators reporting a plunge in their coal-fired generation due to cheap natural gas and a warm winter.
Coal prices have also plunged, which is definitely bad for coal producers, but not necessarily good for the power producers. Their stagnant coal needs left them little opportunity to go into the market and nail down cheap coal that they then would just have to throw into burgeoning coal piles at power plants and coal transloading facilities.
That’s the clear conclusion from a number of reports and financial filings examined recently GenerationHub.
“The results of the market dynamics in the first quarter of 2012 continued to be generally positive for new combined cycle gas units,” said a May 17 report on first-quarter developments in the PJM region, prepared by Monitoring Analytics LLC, the Independent Market Monitor for PJM. “The result of the continued decline in gas prices compared to coal prices was that the fuel cost of a new entrant combined cycle unit fell below the fuel cost of a new entrant coal plant in the first quarter of 2012. New entrant combined cycle net revenues were higher in about half the zones in the first quarter of 2012.
“The results of the market dynamics in the first quarter of 2012 continued to be generally negative for coal fired units. Net revenues declined for coal units in every zone in the first quarter of 2012,” Monitoring Analytics went on to say in the report.
In the first quarter of this year in PJM, coal units provided 39.9%, nuclear units 36.3% and gas units 19% of total generation in the region. Compared to the year-ago quarter, generation from coal units decreased 11.6%, generation from nuclear units increased 8.3%, generation from natural gas units increased 66% and generation from oil units increased 54.2%.
Here is a rundown, compiled by GenerationHub, of recent activity (or lack of it) in the coal arena by power producers.
Duke Energy Ohio
Duke Energy Ohio purchased 19.6% less coal in 2011 (6,196,415 tons) compared to 2010 (7,708,853 tons) and continued to experience electricity customer switching during 2011 that resulted in it accumulating more coal than required for the lower level of customer demand. Consultant Schumaker & Co. was hired by the Public Utilities Commission of Ohio to conduct a fuel audit of Duke Energy Ohio, with that audit filed with the PUCO on May 10. Duke Energy Ohio is a unit of Duke Energy (NYSE: DUK).
Total tons delivered in 2011 to the three individual plants were down 1,404,288 tons (15.4%) from the 2010 level, the audit said. Deliveries to Beckjord, Miami Fort and Zimmer were down 10.5% (177,734 tons), 10.5% (373,541 tons) and 22% (853,013 tons) respectively. Contributing factors to the decreased need for coal during 2011 included customer switching and unplanned outages at Zimmer and Miami Fort.
Progress Energy Carolinas
During a 12-month review period ending Feb. 29, in order to minimize fuel costs, Progress Energy Carolinas took advantage of a “dramatic decrease” in natural gas prices and operated its natural gas-fired combustion turbines at much higher capacity factors as compared with prior review periods. Dewey Roberts II, Manager-Power System Operations at PEC, outlined the company’s power plant performance in annual fuels case testimony filed May 9 at the South Carolina Public Service Commission. PEC is a unit of Progress Energy (NYSE: PGN).
Also testifying was Bruce Barkley, Manager-Fuel Forecasting and Regulatory Support for PEC.
Coal costs increased as compared to the review period ended Feb. 28, 2011, primarily as a result of contract expirations. PEC consumed 9.3 million tons of coal during the one-year review period ended Feb. 29 and purchased 10.2 million tons. Coal in inventory jumped, from 1.5 million tons on Feb. 28, 2011, to 2.5 million tons as of Feb. 29 of this year.
Duke Energy Indiana
Due to increasingly lower power prices and reduced demand for coal generation, Duke Energy Indiana‘s coal burn projections for 2012 have been adjusted downward. For example, coal burn for Duke Energy Indiana stations in December 2011 through February 2012 were about 45% less than the coal burn compared to the same months over the prior five years. If natural and power prices continue to be depressed, there likely will be further downward pressure on Duke Energy Indiana’s coal generation.
That’s according to Elliott Batson Jr., Vice President, Regulated Fuels at Duke Energy Business Services LLC, a service company subsidiary of Duke Energy (NYSE: DUK), and a non-utility affiliate of Duke Energy Indiana. He described the coal situation in April 30 testimony filed at the Indiana Utility Regulatory Commission.
The Gibson, Wabash River, Cayuga plants, and, most-recently the Edwardsport IGCC plant, are supplied by long-term contracts for more than 90% of their annual requirements. For the twelve-month period ended Feb. 29, the company bought about 12.4 million tons of coal (under both long- and short-term commitments) at an average cost of $2.55/mmBtu.
Duke Energy Indiana’s coal inventories as of Feb. 15 had grown to about 3.8 million tons (over 60 days of coal supply at a full load burn rate per day) across the system, including more than 450,000 tons in storage at the Gibson plant remote pile. From Dec. 1, 2011, through Feb. 15, 2012, coal inventories increased by about 800,000 tons, a period of time in which historically inventories have decreased. As of April 11, coal inventories were around 3.6 million tons (the equivalent of 58 days of coal supply).
The recent reduction in inventory is due to increased coal burns since the implementation of a coal price decrement on Feb. 24, as well as reduced coal shipments over this time period. However, based on the company’s latest forecast for coal generation, Duke Energy Indiana expects coal inventories to increase through the remainder of 2012 and into 2013. A decrement is basically a way for Duke Energy Indiana to subtract the money it loses when a plant doesn’t run from its bid price for that power into the Midwest ISO regional power market, making that generation more competitive.
Northern Indiana Public Service
Northern Indiana Public Service (NIPSCO), a unit of NiSource Inc. (NYSE: NI), made no spot purchases in the first quarter of this year, said NIPSCO’s Director of Fuel Supply, Kevin Strnatka, in May 4 fuel adjustment clause testimony at the Indiana Utility Regulatory Commission.
“The challenge this summer will be to manage the excess coal inventory incurred due to the mild winter and the low natural gas pricing, effectively displacing coal fired generation,” he added. “Consumption could further decline based on continuing mild weather and persistent low natural gas pricing. NIPSCO will attempt to manage through any excess inventory by working with suppliers to defer tons as allowed in the coal supply agreements, and to redirect coal for consumption from one station to another if necessary, but at the same time attempting to meet the minimum volume commitments in our transportation agreements to forego paying liquidated damage penalties to the railroads.”
Coal supply during the first quarter continued to be impacted by the mild weather, the decrease in the price of natural gas and “lackluster” coal demand in both the domestic and international markets, Strnatka said. Inventories continue to grow and spot market pricing is sliding due to the overabundance of coal on the market. However, since electrical demand has decreased, requiring less coal to be burned, NIPSCO was not afforded any opportunities to buy cheap coal in the spot market. Therefore, reduced coal requirements were fulfilled with strictly contract coal.
Effective April 1, NIPSCO had five long-term contracts with four coal producers: Arch Coal Sales (for Powder River Basin coal); Enserco Energy LLC (PRB coal); Consol Pennsylvania Coal (Pittsburgh 8 coal); and two contracts with Peabody COALSALES LLC (Illinois Basin coal).
Performance of the coal-fired power plants in Illinois of Dynegy Inc. (NYSE: DYN) slipped a bit in the first quarter of this year due to various factors, including power market issues and the retirement last year of the Vermilion plant, said Dynegy in its May 10 Form 10-Q report. The coal segment consists of six plants, all in the Midwest ISO region, and totaling 3,132 MW. The coal units and their net ratings are: Baldwin, 1,800 MW; Havana Unit 6, 441 MW; Hennepin, 293 MW; and Wood River Units 4-5, 446 MW.
At the Illinois plants, both on-peak and off-peak power prices were lower in the first quarter of 2012 compared to the first quarter 2011 while generation volumes decreased period over period. Energy revenue and the corresponding cost of sales decreased by $65m and $5m, respectively, for a net decrease in energy margin of $60m.
Energy revenues decreased due to lower power prices in the Midwest ISO market associated with warmer than normal weather and lower load demand. Generation volumes were down due to lower demand as a result of a mild winter which resulted in fewer day-ahead commitments at Hennepin and lower day-ahead commitment levels at Havana and Wood River in the first quarter 2012 compared to the first quarter 2011, as well as the mothballing and subsequent retirement of Vermilion in 2011.
Energy Future Holdings
The competitive electric segment of Energy Future Holdings was hit with a 23% decrease in lignite/coal-fueled production in the first quarter that was driven by an increase in economic backdown and unplanned outage days in 2012, while nuclear-fueled production increased 3% reflecting no outage time in 2012.
Energy Future Holdings also reported in its May 1 Form 10-Q report that fuel, purchased power costs and delivery fees decreased $202m, or 24%, to $628m in the first quarter of 2012. Lignite/coal fuel costs decreased $62m reflecting increased economic backdown and an increase in unplanned outage days due to equipment failures, partially offset by increased coal, lignite mining and nuclear fuel costs.
The competitive electric side of the company is the Energy Future Holdings Corp. business segment that consists principally of Texas Competitive Electric Holdings Co. LLC, which is engaged in electricity generation and wholesale and retail energy markets activities, and whose major subsidiaries include Luminant and TXU Energy. Luminant had 10,693 GWh of coal-fired generation in the first quarter, down sharply from 13,966 GWh in the year-ago quarter.
The newly-acquired Ironwood gas plant in central Pennsylvania should fit in nicely with a gas-fired portfolio in the region that has lately been backing down coal-fired generation, said PPL Corp. (NYSE: PPL) Chairman, President and CEO Bill Spence during a May 4 earnings call.
“The purchase of the AES Ironwood plant represented an excellent opportunity for us to expand our gas fleet at an attractive valuation, and in our own backyard,” Spence said. “All of our competitive power plants had high availability during the quarter and our gas-fired units saw increased run times as a result of low natural gas prices and a displacement of higher-cost coal units. Our combined cycle gas units are already seeing close to maximum run times.”
A modest change in coal prices in the first quarter reflects the lower coal burns this year, shifting some of the deliveries to next year, Spence noted. PPL continues to believe that current forward power prices do not appropriately reflect the cost to comply with the U.S. Environmental Protection Agency’s new Mercury and Air Toxics Standards (MATS) and Cross-State Air Pollution Rule (CSAPR) or all anticipated coal plant closures, he added. “We also believe we can see even further heat rate expansion as gas and power prices continue to decouple in the forward years,” Spence said.
Spence said that PPL’s Louisville Gas and Electric and Kentucky Utilities subsidiaries have just gotten approval from the Kentucky Public Service Commission to both acquire and build gas-fired generation in Kentucky. This new capacity would replace coal-fired generation that is targeted for retirement.
Asked about capacity factors for coal units, Spence said: “I think for the summer months we’re going to see the coal units return to their traditional baseload operation. I think, in the fall, of course it’s all going to be dependent upon natural gas prices, as well as coal prices. Hopefully, if you see normal weather, you’d see more run time that we saw in the first quarter. But with the current natural gas price to coal price relationship, I would expect that the capacity factors in the fall are going to be less than what we’ve historically seen. But probably not as bad as the first quarter.”
Public Service Enterprise Group
The coal fleet of Public Service Enterprise Group (NYSE: PEG) was rarely called upon during the first quarter, and when the company’s New Jersey coal units at the Mercer and Hudson plants were dispatched, primarily at Hudson, they were operating part of that time on gas.
“Since our last update in February of 2012, the market price for gas has declined more sharply than the cost of coal,” PSEG Executive Vice President and CFO Carolina Dorsa added during a May 2 earnings call. “The discrepancy has further widened the cost of operating our coal units on coal versus our gas units. In fact, gas would need to increase in price by approximately $3 per mcf or coal decline by $2 per mmBTU. When demand is evident therefore, it has become more economic to run the coal units on gas.”
The coal/gas units at Mercer and Hudson in New Jersey, under PSEG Power, only had an average capacity factor of 2% in the first quarter, down from 29% in the year-ago quarter. The coal unit at the Bridgeport plant in Connecticut only had a capacity factor of 2% last quarter, down from 24% in the year-ago quarter. PSEG’s minority stakes in major baseload coal units in Pennsylvania at the Keystone and Conemaugh plants fared a bit better, with a capacity factor of 63% last quarter, down from 83% in the first quarter of 2011.
Wisconsin Energy Corp.
Wisconsin Energy Corp. (NYSE: WEC), the parent of We Energies, is projecting a burn of just under 9 million tons of coal this year versus 10.7 million tons in 2011.
“Natural gas will take up the slack,” said Wisconsin Energy Chairman, President and CEO Gale Klappa during a May 1 earnings call. “Our natural gas burn is expected to nearly double from 28.5 Bcf last year to 50 Bcf this year. In fact, our natural gas units at Port Washington operated at about a 60% capacity factor in the first quarter of this year. The Port Washington units are essentially now being dispatched in the MISO market as baseload units. So overall, I believe we’re well positioned to adjust as the markets for coal and natural gas continue to evolve and for calendar year 2012, we expect to fully recover our fuel costs.”
Flue gas desulfurization (scrubber) equipment installed in recent years on the Mountaineer and Amos power plants in West Virginia has allowed Appalachian Power (APCo) to burn cheaper high-sulfur coals at those facilities, letting it keep control of fuel costs. Jeffery LaFleur, Vice President-Generating Assets for APCo, was one of several utility officials that wrote testimony that was filed April 24 at the Virginia State Corporation Commission in a fuel cost case.
Jason Rusk, employed by American Electric Power Service Corp. (AEPSC), another subsidiary of American Electric Power (NYSE: AEP), in the Fuel, Emissions & Logistics Group as Director, Coal Procurement, outlined recent events in the coal markets and APCo’s coal position.
“A strong and robust coal market in 2008 resulted in high market prices for coal,” Rusk reported. “As a result of the economic downturn, which came into play in late 2008 and early 2009, there was a significant reduction in coal prices, as well as lower market prices for electricity. This was followed by a moderate upward trend in coal prices, matched with lower coal market volatility that was present from the fourth quarter of 2009 through the first half of 2011. The market did not experience decreasing coal prices for the majority of 2011 because demand for coal in other countries continued to support the price of coal from the Central Appalachian Basin, the main type of coal consumed by APCo. Starting in the fourth quarter of 2011, Central Appalachian coal prices in the spot market did begin to drop in response to weak domestic demand. However, this recent downward trend in market coal prices has not materially affected APCo’s coal costs as APCo has not had a need to purchase significant amounts of coal in the spot market in recent months.”
Going against the trend, APCo in 2011 actually consumed more tons of coal than during 2010, and the average cost of coal on a per-ton basis was slightly higher than in 2010. In 2010 and 2011, APCo’s total weighted average cost of delivered coal was $62.95 and $63.78 per ton, respectively. In 2011, APCo saw a slight increase in generation over 2010, which had not been forecast.
American Electric Power
American Electric Power, the parent of APCo, said April 20 in an earnings call that a combination of fuel switching and mild weather has swelled its coal piles. AEP, one of the nation’s largest coal-burning utilities, said that its system-wide average coal inventory was 45 days as of March 31 of this year.
AEP’s natural gas consumption increased about 62% in the first quarter of 2012 compared to the first quarter of 2011. Excluding the Dresden gas plant, which came online during the first quarter, AEP’s average capacity factor for its combined-cycle gas plants in the East was about 85%.
AEP CEO Nick Akins said AEP has built or purchased about 5,000 MW of additional natural gas capacity in recent years. It recently retired one of its Sporn coal units and should retire several thousand megawatts of additional coal capacity in the next few years. The timing will be affected by both market factors and possible compliance extensions for tougher EPA standards, Akins said.
The Zeeland gas-fired power plant of Consumers Energy, bought a few years ago, has gone from a peaker to a baseload plant in part because of cheap natural gas that is also currently forcing some of the utility’s coal-fired facilities into cycling mode, said CMS Energy (NYSE: CMS) officials on an April 26 earnings call.
John Russell, President and CEO of CMS Energy, said about the impacts of cheap gas: “We’ve even seen at times that…the combined cycle is dispatched ahead of coal. But even peaking, even the simple cycle has dispatched some coal in some certain timeframes. So we’re seeing that as an advantage that we have with the gas plants. A disadvantage is that we’re really cycling the coal plants a lot more than we have in the past and right now some of the coal plants are out of market. So it kind of fell in line with the strategy that we’ve had to take some of these older units and mothball them in the next couple of years anyway.”
Russell said the company is confident that the decision to mothball seven smaller coal units in Michigan and maybe ultimately retire them is the right move. “The big five coal plants, the work that we’ve done already makes sense because they are competitive,” he added. “Although as I said earlier, we’re moving them around a little bit, cycling them a little bit more than we have in the past.”
Vectren South has coal-fired units that are not being dispatched because more competitively priced power can and is being purchased in the Midwest ISO market, causing the utility to put extra coal into stockpile even though it is taking minimum coal under its contracts.
Michael Eckert, employed by the Indiana Office of Utility Consumer Counselor as a Senior Utility Analyst in the Electric Division, made that point in March 30 testimony filed with the Indiana Utility Regulatory Commission in a Vectren South fuel adjustment clause case. Vectren South, also known as Southern Indiana Gas and Electric, is a unit of Vectren Corp. (NYSE: VVC).
Vectren South’s coal inventory is much higher than historic levels, even though it is continuing to take coal from its coal suppliers at the contract minimum of 85% of the full contracted tonnage, Eckert noted. “Vectren has coal fired generation units that are not being dispatched because more competitively priced power can and is being purchased in the MISO market,” he added. “Given current market conditions and system demand, Vectren’s cost of fuel for some of its units makes them too expensive to run. Thus, MISO is not dispatching them and is utilizing purchased power to supply Vectren’s customers with their power needs. In fact, some of Vectren’s units have been placed on reserve shutdown.”