In recent years, coal power generators have faced increasing difficulty predicting annual fuel requirements due to more cycling and low-load operation. That presents problems for the people negotiating fuel contracts. Not all mining companies are amenable to contract changes, but some unique solutions have been developed.
Remember when coal-fired power plants supplied baseload power 24/7/365 (when they were not offline for scheduled maintenance)? It seems like ages ago. Nowadays, load is as unpredictable as the weather, which is to say, if the sun is shining or the wind is blowing, renewable resources are often putting a crimp in coal-fired generation.
But renewable energy isn’t the only thing pushing coal plants to the sidelines; low-cost natural gas has played a role as well. Consequently, some gas turbines previously used as peaking units are now being dispatched for baseload power. That has meant various coal units have had to run at reduced loads or even to shut down for “economy” from time to time.
Changing Roles Mean Changing Fuel Strategies
Altered operating regimes can make a fuel manager’s job much more difficult. In days of yore, fuel burn was fairly easy to calculate. But when load varies as it does today, forecasting usage can require a crystal ball rather than a calculator.
Coal Creek Station, North Dakota’s largest power plant, with a total capacity of 1,146 MW, offers one example of the predicament. In late December, Great River Energy (GRE) announced that Coal Creek had made a number of operational changes and minor modifications that enable the plant to ramp down to less than 300 MW.
“In the past, we wanted to park our power plants at the top,” Rick Lancaster, vice president and chief generation officer for GRE, said in the release. “In today’s energy market, there is added value for plants that can reduce output—flexibility is an enviable trait.”
Coal Creek has one advantage most other plants lack: It is a mine-mouth operation and has a coal contract structured favorably for flexible operation. Coal Creek and GRE’s Spiritwood Station (a 2015 POWER Top Plant) are the only power plants supplied by the Falkirk Mine. As such, GRE works closely with the mine, including through a joint planning and budgeting process.
“We are not dealing with the common model where utilities have fixed commitments to fuel supply and shipping,” GRE spokesperson Lyndon Anderson told POWER. “If the future market reduces demand for fuel, the joint planning process will take advantage of the flexibility the mine plan has to adjust to variable needs.”
Many fuel managers don’t have the same luxury. Those who bring coal in by rail often have contracts not only with multiple mines, but also with the railroad (Figure 1). One fuel procurement specialist for another Midwest generator said his company has been working with its coal suppliers to restructure contracts, if there are shortfalls, and it has been looking to add greater flexibility into future deals.
“We don’t have remedies as part of our contracts. The coal mines have really just worked with us to adjust tonnage,” he said. “It’s a little bit more than that now, but no penalties.”
Brett Phipps, Duke Energy’s managing director for fuel procurement, suggested that all coal-based power generators face similar challenges. He said the increased volatility in unit dispatch has driven Duke Energy to review and update its fuel procurement strategies. He noted that the process is dynamic and changes with market conditions. Some of the company’s high-level initiatives include:
■ Increasing the percentage of spot coal purchases.
■ Targeting seasonal purchases and deliveries to align with high-demand periods.
■ Raising inventory targets for marginal coal units.
■ Requiring flexibility in new contracts, such as the ability to vary volume by±20% on a quarterly basis.
■ Looking for transactions that tie natural gas and coal purchases together.
■ Developing an integrated fuel procurement strategy team with key stakeholders from various departments.
■ Improving analytical tools that forecast fuel needs.
At least some of the mining companies understand the problem. For the most part, they feel the same pain that generators do and have a self-interest in seeing coal-fired plants succeed.
“We recognize that the landscape has changed and, in response, we have an open dialogue with our customers and the entire supply chain to help all parties meet their objectives,” a spokesperson for Alpha Natural Resources, a company with 18 active mines in Kentucky and West Virginia, said.
Robert Murray (Figure 2), CEO of Murray Energy Corp., the largest underground coal mining company in the U.S., said his company is doing some very unique things to market its coal.
“There are many ways to do it,” Murray told POWER in an exclusive interview. “We’ve been at it now for several years.”
For example, Murray said his company has worked with several very large power plants that were not being dispatched consistently. Murray agreed to reduce the purchase price for his coal so that the plants would be more competitive in the market. As part of the deal, the plants are obligated to share some of their profits with Murray Energy. Murray said his company is getting 30% of the earnings from 425 MW that was not committed to the grid at one plant, while it participates on a sliding scale at another plant.
“We become partners with the power company in these contracts,” Murray said. “They’re all different.”
Of course, Murray still offers physical sale agreements—the more conventional type of contract—if that’s what the buyer wants, but he said power off-take agreements and price participation agreements seem to provide more flexibility for buyers and less potential for default. Murray doesn’t see the situation changing anytime soon.
“That has to continue going forward. It will continue going forward,” he said. “I don’t look for the [coal] markets to improve. They’ll stay about where they are at best.” (For more of Murray’s comments on the future of the coal industry under the new administration, see “Coal Magnate Tells Trump to Lower His Expectations” at powermag.com.)
Let’s Make a Deal
But even when generators and mining companies attempt to settle shortfalls agreeably, things can go awry. Homer City Generating Station offers a case in point.
Homer City is a three-unit coal-fired power plant with aggregate net capacity of 1,884 MW, located in Indiana County, Pa., roughly 45 miles northeast of Pittsburgh. The facility is a PJM capacity resource and primarily sells its capacity through PJM’s annual capacity auction, but it also has the ability to sell energy in the New York Independent System Operator (NYISO) wholesale market.
In an August 2016 presentation, Homer City noted that its fuel strategy is to procure multiple coal types to meet its 4 to 5 million ton annual usage. It said the facility receives three types of coal: scrubber, raw, and ready-to-burn (RTB). Scrubber coal made up the majority of 2015 usage (52.4%), with raw and RTB (Figure 3), split about evenly, making up the rest. Scrubber coal costs about 30% less than RTB coal, but it emits nearly twice the SO2/MMBtu. Raw coal (post-washing) emits the least SO2/MMBtu.
The facility has numerous transportation options, which it said creates competition. Most mines supplying Homer City are within 40 miles of the plant, and a number of them are inside a 10-mile radius. Consequently, truck transportation rates are often less than $3/ton. The Buffalo and Pittsburgh Railroad provides direct rail service to the plant, while Norfolk Southern Railroad offers a combination of rail and truck service, adding even more flexibility for the station.
Homer City Generation and its owners, which include GE Capital, are embroiled in a court battle with one of the plant’s coal suppliers. CONSOL Pennsylvania Coal Co. filed a complaint in the Court of Common Pleas of Allegheny County, Pa., on July 8, 2016, alleging breach of contract by Homer City.
According to CONSOL, Homer City entered into a coal sales agreement with the company on January 6, 2014. The contract was to run through December 31, 2015. However, when Homer City fell behind the delivery schedule prescribed by the contract, an extension agreement was negotiated, extending the purchase period for two additional years.
The extension agreement was said to have mutually agreed upon targets with monthly delivery schedules running from October 1, 2015, through December 31, 2016. Homer City was given the option of deferring up to 125,000 tons of coal per calendar quarter, if necessary, with the deferred quantities carried over into 2017. Nevertheless, by the end of April 2016, CONSOL said that the plant had failed to purchase 639,842.5 tons of coal, even assuming two quarterly deferrals of 125,000 tons each, which it said Homer City had not validly requested under terms of the contract.
When Agreements Go Bad
With Homer City seemingly in breach of the extension agreement, CONSOL claimed it proposed a forbearance agreement pursuant to which CONSOL would have continued to ship coal and forbear, for a period of time, exercising its rights and remedies with respect to Homer City’s default. The forbearance agreement was rife with stipulations, including a requirement for Homer City to deliver a letter of credit or cash deposit to CONSOL in the initial amount of $10 million as security for Homer City’s performance. However, Homer City rejected the forbearance agreement.
Instead, the parties entered into a letter agreement, which required Homer City to prepay for each train of coal at least 24 hours before the train arrived at the mine (Figure 4). It also modified the extension agreement’s delivery schedule with a new monthly plan. Nevertheless, CONSOL claimed that just three weeks after executing the letter agreement, Homer City notified the company that the plant would not accept any future deliveries of coal at the contract price. Homer City subsequently sourced coal elsewhere at a lower price, according to CONSOL.
In an effort to mitigate its losses, CONSOL said it entered into a second letter agreement with Homer City. Under that deal, CONSOL agreed to sell coal to the plant at an interim price while retaining its right to recover the difference between the interim and original contract prices.
Homer City, for its part, has been evaluating ways to address its long-term capital structure. Owners put the plant up for sale in the first quarter 2016. Although bids with implied total enterprise value of up to $535 million were received, none were found to be acceptable. Meanwhile, in its court filing, CONSOL made clear that the company fears a third-party purchaser may not assume all of Homer City’s obligations under the agreements, leaving it with no viable remedy for the alleged breach of contract.
In Homer City Generation’s financial statements dated September 30, 2016 (the most recent available as this story goes into production in early January) management noted, “Homer City and the other defendants named in the complaint dispute the allegations therein and intend to assert defenses against Consol’s claims.” Homer City reported 1,298,000 tons of coal remaining under contract for 2016 and 2.5 million tons under contract for 2017 at the time, but it did not list details of the agreement(s). ■
—Aaron Larson is a POWER associate editor.