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By Bob Bellemare Chief Executive Officer

Utilities are feeling the strain of a train derailment in the West that occurred after heavy weather in late winter and early spring. Coal inventories at many power plants were already at low levels because the high price of natural gas had coal-fired power plants running at full capacity. Now, with shipments from the Power River Basin (PRB) of Wyoming and Montana constrained, utilities curtailing coal generation and switching over to more costly generation to conserve supplies. Customers will feel the pinch in their wallets as the higher fuel costs are passed along through fuel cost adjustments in their electric rates.

The Rail System

The U.S. railroad freight industry is nearly a $40 billion annual business with coal making up about 40 percent of ton-mileage total of shipments. The coal found in the PRB region of Wyoming and Montana is a desirous fuel for many utilities because of its low sulfur content and makes up about 35 percent of all coal burned in U.S. power plants. The coal is shipped long distances, primarily to power plants in Illinois, Texas, Wisconsin, and Missouri, and as far away as New England and Florida.

The two primary carriers in the PRB region are BNSF Railway and Union Pacific Railroad. While the rail traffic is heavy, there are a limited number of rail lines originating from the region. BNSF and Union jointly own rail lines emanating from Gillette, Wyoming. The South Power River Basin Joint Line (SPRBL) represents the busiest and highest density freight railroad in the world.

According to company reports, on Saturday, May 14, 2005, a BNSF train derailed 15 cars approximately 6 miles north of Bill, Wyoming, on the SPRBL. The next morning a Union Pacific coal train derailed 28 cars approximately 19 miles north of Bill, Wyoming, on the Joint Line. The two derailments are suspected to have been caused by severe weather and coal dust that had settled under the tracks. The eastern half of Wyoming experienced heavy rainfall and snow this past spring, including a major spring snowstorm on April 21 that virtually shut down mining operations in the Basin. On May 11 two inches of rain fell on the area followed by 6 inches of snow. Another contributing factor was the long-term accumulation of coal dust on the track which reduces water drainage thereby deteriorating the track structure. Photos of the rail problems can be found at http://www.uprr.com/customers/energy/sprb/photos_orin_1.shtml .

As a result of the derailments the railroads ability to fulfill their contractual shipment obligations is limited to about 80 to 90 percent of normal. BNSF and Union Pacific agreed that postponing major rehabilitation work was not an alternative and that the best solution was to immediately remove coal dust from the roadbed and to replace several miles of ties and track. Extensive maintenance and track repair are expected to run through November 2005 with some maintenance and repair work to be carried over into next year.

BNSF is using two undercutters and a tie and rail replacement machine to perform track repair and maintenance. The coal dust will be removed from approximately 100 miles of roadbed and the ties and rail will be replaced on approximately 14 miles of track. Union Pacific reported on August 25, 2005 that maintenance activity shifted to "undercutting," which cleans coal dust out of the rock ballast supporting the track structure. They claim the primary cause now for reduced coal shipments has shifted from railroad repairs to the inability of mines to load trains, although Union experienced another train derailment in August caused by high winds. Since the beginning of August, 70 percent of the missed trainloads are attributable to mines unable to load trains for a variety of reasons, ranging from landslides in the pits, to no coal inventory, to equipment upgrades. Union Pacific reported it was able to fulfill 89.3 percent of its contracted demand in the month of July and is currently tracking at 85.62 percent of demand through August 15. Union Pacific is allocating coal proportionately among its customers based upon trains loaded as a percent of total train demand.

Utility Customers Pay the Price

The rail companies have ridden through the derailments without much impact on the bottom-line. BNSF, for example, recorded coal revenues of $1.2 billion for the first six months of 2005, an increase of $116 million, or 11 percent, versus the same period a year ago. Average revenue per car increased 9 percent, primarily driven by contractual rate escalations, fuel surcharges and increased length of haul. Year-to-date net income was $361 million versus $323 million for the same period in 2004.

For utilities, however, the high U.S. demand for low-sulfur PRB coal has left little room for unplanned repairs to the rail lines, particularly in the summer when power demand is highest. And it's not a simple matter of just switching to some other coal. Coal comes with wide variation in physical and chemical characteristics and power plants are “tuned” to burn a specific blend of coal.

Fortunately the decreased western coal shipments are not expected to impact electric reliability. In late July the North American Electric Reliability Council (NERC) sent a letter to the 10 NERC regions requesting they assess the potential reliability impacts of the reduced coal shipments. The regions reported back that the anticipated impacts would not be reliability but financial as the delivery shortfalls would be made up by increasing the use of non-PRB coal, reducing the use of coal in off-peak hours, and switching to natural gas generation.

With western coal shipments down, upward pressure is being felt on the consumption and price of natural gas as well as the price for deliverable coal from other regions. This “substitute” coal from eastern regions will typically have higher sulfur content which also puts upward pressure on sulfur dioxide emission allowance prices.

For some coal merchant power plant owners like Midwest Generation, a subsidiary of Edison International, the impact has actually been a positive. The high natural gas prices and increased off-peak power purchases are boosting wholesale electric prices. According to Dow Jones & Company, Midwest Generation reported $2.2 million in net income for the second quarter, compared with a loss of $63 million in the second quarter of 2004. While Midwest produced less electricity in the quarter, it realized an average price of $41.83 a megawatt- hour (MWh), compared with $24.89 in the same period last year. Exelon Corp. is another company that is claiming a financial benefit. It cited higher off-peak power prices in the Midwest as part of its explanation for a $300 million jump in net revenue from wholesale power sales in the second quarter from the year before.

But not all generation owners are so lucky. Wisconsin utilities Alliant, WPS Resources, and Wisconsin Energy have reported using coal generators less at night to conserves supplies. Wisconsin Energy burns about 12 million tons of coal a year, 9 million from the Powder River Basin. Xcel Energy with utilities spanning from Colorado to Minnesota is switching over some of its generation to natural gas fired plants to conserve coal.

Entergy was reported in NGI's “Power Market Today” as adjusting its power plant dispatch in off-peak periods to reduce coal use. Rick Smith, group president for utility operations at Entergy was reported as saying in a call with analyst that "The transportation companies we're dealing with have reduced the trains moving this way to about 80 to 85 percent, but based on our wholesale market, we've been able to adjust our dispatch to really offset that and have stabilized our inventory levels at a very acceptable level …We have fuel clause mechanisms in all the jurisdictions, so we just pass that through to the customers … It's not a big change for us because the off-peak period, which is really where we're adjusting the dispatch, really there's still pretty favorable generation costs out there in off-peak."

Passing along any increase in fuel cost to customers is what many utilities are planning on. Utilities commonly have a “fuel clause” that can be adjusted to reflect actual fuel costs. Investor Owned Utilities (IOUs) justify any changes in fuel related charges to state regulators, so there is some risk to the utility that state regulators may find a portion of the increased cost as imprudent. That's not likely in this case since the coal shortage was created by an action not reasonably within control of the utility.

Take Xcel Energy, which notified commercial and industrial customers in a letter to expect a jump in fuel costs, although the exact amount of the increase is unknown. The initial projected wholesale fuel cost adjustment factor in Texas for July was 4.1 cents per kWh (kilowatt hour) but because of the coal constraints it was later projected that the fuel cost adjustment might increase by as much as 20 percent, but now they hope the impact will be less than that amount. Wisconsin Power & Light, an Alliant Energy Corporation subsidiary, reported that it expects to ask regulators to recoup $14 million to $22 million in higher power costs from customers.

With the peak electricity season coming to an end it looks like utilities have been able to adjust their generation plans sufficiently to avert severe financial impacts from the coal shipment problems. Much work remains, however, to achieve a full recovery. Once full capacity is restored many utilities will need to replenish stockpiles, continuing a strong demand for coal well into 2006.

©2005, UtiliPoint International, Inc. All rights reserved.

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