BEFORE THE
PUBLIC SERVICE COMMISSION OF WISCONSIN
Strategic Energy Assessment for the Years
January 1, 2010 through December 31
2016 Docket No. 05-ES-105
2016 Docket No. 05-ES-105
COMMENTS OF RENEW WISCONSIN ON THE DRAFT STRATEGIC ENERGY ASSESSMENT
_________________________________________________RENEW Wisconsin submits these comments on the Commission’s draft Strategic Energy Assessment (SEA) 2016. RENEW’s comments focus on the “Electric Demand and Supply Conditions in Wisconsin” section.
The draft SEA notes that, in 2008, 67% of the energy produced in Wisconsin was generated by coal-fired power plants; 8% by natural gas; and 2% by biomass. Draft SEA, p. 18. Collectively, these units supplied 77% of the energy produced in Wisconsin. With the addition of the two new coal-fired generating units at the Elm Road Generation Station in 2010 and 2011, Wisconsin’s percentage of coal-fired generation has increased even more.
Fuel for all of these types of generating units comes at a cost, both the cost of the fuel itself and the cost to transport it to a generating station. Because coal makes up such a significant portion of the energy generated in Wisconsin and because it is not available in Wisconsin, its costs are particularly important. For years, the assumption has been that coal is cheap and abundant. Even the draft SEA notes that “Coal has historically been an abundant and inexpensive fuel for electric generation.” Draft SEA, p. 46. However, the ability to extract high quality coal and the cost to transport it to Wisconsin have been steadily increasing, calling into question the “abundant and cheap” mantra.
Most of the coal that fuels Wisconsin’s power plants comes from the Powder River Basin (PRB) in Wyoming. That region supplies coal to many of the largest coal plants in Wisconsin’s generating fleet--Columbia, Pleasant Prairie, Weston, Oak Creek, J.P. Madgett, Edgewater, and others. The contribution from other coal fields, such as those in the North Appalachian and Colorado regions, is small by comparison to the voluminous flow of low-sulfur subbituminous coal coming out of such mines as Black Thunder, Jacobs Ranch, Cordero Rojo, Antelope, and North Antelope Rochelle. The coal extracted from these mines is transported to power plants 1,000 miles away in Wisconsin on unit trains with as many as 130 cars.
Data from the Energy Information Administration (EIA) document the steadily rising cost of coal imported to Wisconsin over the past 10 years. In 1999, the average cost of coal delivered to Wisconsin electric utilities was $1.02/MMBtu (Table 34, Electric Power Monthly (EPM), March 2001). By 2004, the average cost had risen to $1.18/MMBtu (Table 4.10B, EPM, April 2005). The cost increase over the next five years was more pronounced, rising to $2.02/MMBtu (Table 4.10B, EPM, March 2010). The cost escalation between 1999 and 2009 corresponds to annual increases of 7%.
Increases in the cost of diesel fuel account for a significant portion of coal’s price rise. Spiking dramatically in mid-2008, diesel prices slumped 40% in 2009 but have since mid-2010 retraced a significant part of that decline, and are now comparable to where they were in early 2008.
Another driver behind rising coal prices is the increased cost of resource extraction. From 2000 to 2010, spot market prices of PRB coal rose from about $4 per ton to $14 per ton. Rising prices reflect increases in the “stripping ratio ,” a key measure of ore quality, encountered by mine operators. The stripping ratio indicates the number of tons of rock that must be moved to obtain a ton of coal. It is prudent to expect the stripping ratio of PBR coal to increase as the largest and most accessible mines become played out and mine operators shift to newer mines with deeper overburdens and thinner coal seams.
(http://www.cleanenergyaction.org/sites/default/files/Coal_Supply_Constraints_CEA_021209.pdf, p. 47.)
For example, the average overburden on the existing Antelope Mine is 122 feet thick and the coal seam is 86 feet thick. Antelope’s operator has applied to expand the coal mine to the west. While there is plenty of recoverable coal at Antelope II, it will be less productive than the original mine, because of the combination of thinner coal seams (50-60 feet thick) and average overburden depths (260 to 280 feet). Thus, the stripping ratio of Antelope II will be significantly higher, as will production costs.
(http://www.blm.gov/pgdata/content/wy/en/info/NEPA/documents/cfo/West_Antelope_II.html)
It’s worth pointing out that the U.S. coal market does not operate in isolation of overseas trends and events, which lately have been propelling coal costs higher. One well-reported trend is increasing demand from China, which has moved from an exporter to an importer of coal. The New York Times (NYT) reported in November 2009 that the volume of Chinese coal imports will hit all-time highs going into 2011. (http://www.nytimes.com/2010/11/30/business/energy-environment/30utilities.html?_r=1&scp=1&sq=breaking%20away%20from%20coal&st=cse)
The catastrophic flooding in northeast Australia earlier this month is certain to apply upward pressure on coal prices globally. Torrential rains incapacitated 75% of the operating coal mines in Queensland, the world’s largest coal-producing region. Much of the coal there is exported to other Asian markets. It will take many months if not years to dewater the mines and restore them to active operation. Though Queensland’s mines supply coking coal for the most part, the damage inflicted to the mines, roads, railways and bridges will ripple through the thermal coal markets as well and lift prices in that sector. (http://www.energydigital.com/sectors/mining-and-aggregates/queensland-flooding-washes-away-millions-coal-revenue
In addition, electric utilities have not been able to lock in low cost coal prices over long-term contracts. A review of recent coal shipments to Wisconsin power stations reveals that most supply contracts will expire between now and January 2013. (EIA-423 available at http://www.eia.doe.gov/cneaf/electricity/page/eia423.html)
The emergence of shorter-term contracts, coupled with the increasing tendency among Wisconsin utilities to rely on the spot market, increases the exposure of ratepayers to rising coal prices caused by (1) higher diesel fuel prices, (2) increased coal exports from North America to China, (3) the ongoing transition to lower-quality domestic coal sources, and (4) natural disasters and other perturbations in global supplies.
It should be noted that the current glut of generating capacity provides no insulation against rising fuel prices. The coal still has to be mined, loaded into unit cars, and transported across the Great Plains and the Mississippi River to reach Wisconsin generating units. Even if utility demand for coal diminishes incrementally during the planning period, whatever moderating effects that trend would induce are likely to be dwarfed by global factors, not least of which is Asia’s ravenous demand for coal, which domestic coal companies such as Peabody will be only too happy to feed.
With these challenges looming in plain sight, it will take a minor miracle to keep coal prices from rising above the 7% annualized rate of the previous 10 years.
Given the degree to which Wisconsin utilities are reliant on PBR coal supplies, RENEW recommends that the PSC track and monitor the emerging supply and cost issues associated with that resource. In their comments on the draft SEA, Citizens Utility Board and Clean Wisconsin recommend that the SEA include historic annual average fuel costs for all combustible fuels (including coal) and a projected annual average fuel cost for each year (including coal) for each year during the SEA period. RENEW supports that recommendation.
RENEW appreciates the opportunity to provide the Commission with these comments and recommendations. RENEW continues to believe in the wisdom of comprehensive long range planning of demand, supply and transmission resources to best meet Wisconsin’s electricity needs while balancing cost, reliability, environmental, risk and other factors.
