Coal News and Markets
Coal News and MarketsWeek of January 29, 2006
Coal Prices and Earnings (updated January 30, 2006) This report summarizes prices from the business weeks ended January 20 and January 27. In the business week ended January 20, Powder River Basin (PRB) spot prices declined. The average spot price for 8,800-Btu PRB product lost $2.00, descending to $18.66 per short ton. That decline was followed, in the week ended January 27, by a rebound in the average, to $19.15 per short ton. An all-time high average spot price of $20.49 had been reached in the week ended January 6 for the PRB coal tracked by the Energy Information Administration (EIA). There were no changes in the indexed spot prices in the other coalfields in either of the past 2 weeks. The average spot price for the Central Appalachia (CAP) 12,500-Btu rail coal tracked by EIA remained at $58.25 per short ton, after losing $0.75 in the week ended December 30, 2005. The average spot price for 11,800-Btu Northern Appalachia (NAP) held at $45.00 per short ton for the fourth and fifth successive weeks. The Illinois Basin (ILB) spot price was unchanged at $36.00, and the 11,700-Btu Uinta Basin (UIB) coal average spot price was still $37.00 per short ton (all for prompt-quarter delivery, Coal Outlook, January 23 and 30, p 2).
The unprecedented high prices for PRB spot coal recently are consistent with the continuing low stocks at a determinative number of coal-fueled power plants and industries. EIA's latest statistics at electric power plants indicate that coal stockpiles had risen by just under 3 million short tons (mmst) from the end of September to the end of October, 2005, as summer consumption slowed. The 101.1 mmst of coal on hand, however, was 10.0 mmst lower than in October 2004, and is low historically. Further, national statistics tend to obscure extreme cases, where coal supplies have been managed carefully to keep enough in reserve to avoid potential interruptions in plant operations. Argus Coal Daily writes that PRB spot prices are being pushed higher by the cumulative shortages in the Midwest and, especially, the south-central United States caused by last summer and fall's rail problems (January 6, p 3). Power generators in Texas, Kansas, Oklahoma, and Arkansas are said to be hardest hit. Generators who could conserve coal stocks did so, but those without good natural gas generation options have dug deeply into coal supplies on hand or turned to purchasing power from other producers.
Although EIA projected that U.S. coal prices in general will rise more moderately (at a rate of 5.5 percent) in 2006 than last year, pricing of PRB spot market coal since late November 2005 had been upward sharply until the week ended January 20. As discussed later, the $2.00 per ton decline in PRB spot prices may be indirectly related to falling natural gas prices and sulfur dioxide(SO2) allowance prices in recent weeks. The factors that have tipped toward higher prices (in addition to existing low customer stockpiles) include expectations for continued high prices for sulfur dioxide(SO2) allowances in 2006, limited improvements in coal shipping, and the fact that additional demand in 2005 for PRB coal was largely unfulfilled. Also, early heavy activity by coal buyers, which likely contributed to price run-ups, may signal attempts to avoid a repeat of the delivery constraints experienced in 2005. Coal producers too are aligned with price increases: coal that customers could not get shipped in 2005 is no longer available at 2005 prices, but will be sold under newer, higher-priced contracts. The rising prices for PRB spot coal have been in puzzling contrast to prices for CAP coal and NAP coal, which declined in 4Q2005. There are some plausible explanations. The key is that coal suppliers are essentially selling two commodities in 2006 – Btu’s and sulfur. The higher the Btu, the higher the value of the coal itself, but the higher the sulfur entrained in the coal, the more it must be discounted. In the past, one reported rule of thumb would discount the price by $0.30 per short ton for each 0.1 percent of sulfur in the coal (Coal & Energy Price Report, January 9, pp 1-2). By that approach, a 1.5 percent sulfur CAP coal would be discounted $1.50 per short ton below the price of a 1.0 percent coal of similar Btu. In 2006, however, with the prices of SO2 emission allowances topping $1,500 per ton, boiler operators have been demanding discounts of $15 to $16 per ton of coal carrying an extra 0.5 percent sulfur. By the same token, the heat content of the coal has become more critical because the amount of sulfur converted ultimately to SO2 emissions is inversely proportional to the Btu value of the coal. The lower the Btu content, the more coal and attendant sulfur must be combusted to produce the heat or power needed. As a result 11,500-Btu coal with 1.5 percent sulfur may be at the margin of the market, but 11,000-Btu coal with 1.5 percent sulfur may have to be discounted below its cost of production. Of more concern, much of the “off-spec” coal (with Btu below specified levels or with sulfur content above specified levels) is not being bought at any price (Coal & Energy Price Report, January 9, p 2). If this selective buying were to become widespread it could indirectly result in a broad loss of productive capacity for coal. For example, some of the extra Appalachian capacity in 2005 was produced at new or expanded surface mines, in part because of the shortage in trained underground miners. Further, the decision by the Fourth Circuit Court of Appeals in late November 2005 on Section 404 permitting (see below) will ease permitting delays for surface mines and, especially, mountaintop removal mines in CAP. The dilemma is that economically feasible surface mines tend to recover multiple beds of coal, of which only a minor percentage will have the desired Btu/sulfur properties. The other coal must also be salable for at least a modest profit for these mines to stay in business, but currently in the spot market those off-spec coals are being mined at a loss. The market for Appalachian coal affects both operators who burn that coal exclusively and those whose boilers were converted to use PRB coal. In the Midwest and South Central regions of the United States a sizable number of managers at power plants that burn PRB coal also purchase low-sulfur and high-Btu Appalachian coals. Those plants blend Appalachian coal, especially CAP, with PRB coal to boost Btu and meet their sulfur emission budgets. At current emission allowance prices the quality of the high-Btu blend coal has become just as important as the low sulfur in the PRB coal. The impacts so far are limited because 80 percent or more of Appalachian coal sales are under existing contracts, at prices the customers can still tolerate in conjunction with emission allowance costs. If SO2 allowance prices remain high, however, the costs could price more CAP and NAP coal out of the market at a time when their Btu’s are needed (Coal & Energy Price Report, January 9, p 2). Although NAP and ILB coals, and off-spec CAP coal, are expected to gain market share because of the addition of flue-gas scrubbers at scores of generating units, it should to take until 2011 for all the first wave of anticipated scrubbers to be built and installed. Consol Coal, with the highest holdings of available reserves in NAP, expects the scrubbed coal-fired capacity to double between now and 2011 (Argus Coal Daily, January 11, p 4). EIA’s 2006 forecasts project 90.6 gigawatts of coal-fired generation retrofitted with new scrubbers by the end of 2011. The total then would be nearly 2 times the 102 gigawatts of scrubbed coal-fired capacity on line in 2004. (EIA projects continuing retrofits beyond 2011, reaching 132.7 gigawatts of cumulative retrofits by 2020 and 140.6 gigawatts by 2030.) In the meantime, some power plants, with scrubber installations in place or underway, were securing new contracts for high-Btu, mid- to high-sulfur coals for delivery in 2006 and 2007. Spot sales could be lean over the next few months, however, or until allowance prices decline. Prices for coal other than PRB have been held in check in part by the unseasonably warm weather during much of January in many States. The weather affects heating fuel markets east of the Rocky Mountains as well as in coal-fired electric power regions. The weather affected demand for spot coal and for natural gas. Natural gas storage levels are higher than expected for January and natural gas futures prices had fallen by almost 40 percent in less than a month (Dow Jones Newswires, "US GAS: Weak Futures Market Shows No Sign of Bottoming Monday," January 9). Since many power producers already had to turn to natural gas generation last summer, when natural gas was expensive, to supplement their sales, they are open to employing natural gas generating units now that prices are falling, and because of the very low SO2 emissions with natural gas. Coal inventories are monitored at plants that generate electricity (utilities, independent power producers, and industrial and commercial plants with generation capacity). Those inventories increased in November 2005, as they usually do in autumn, and had a small but noteworthy impact on the overall downward trend in coal stocks (see graph below). Coal on hand increased from 101.1 to 109.5 mmst from the end of October through the end of November based on EIA's early-release "Electric Power Flash" estimates. Earlier statistics are based on revised or final data from EIA's latest Electric Power Monthly. By historical standards, though, coal stockpiles continue to be low: they totaled 113.3 mmst in November 2004 and 126.7 mmst in November 2003. Calculated days of consumption represented by coal stocks increased from 37 days to 40 days from end of October to end of November. That marks the first month since January 2005 that days of coal consumption increased to within 1 day of the coal on hand a year earlier. By comparison, ending November coal stocks in 2004 equated to 41 days' consumption and in 2003 to 46 days'. Days of consumption levels normally increase in October and November because inventories increase and because the rate of consumption tends to be lower in those months than in any of the previous four or five months.  Although SO2 allowance prices have declined since December, they are still costly . Year 2006 allowances traded on January 9 at $1,550, which was not much below the $1,630 record on December 9, 2005. By c.o.b. January 26, the last settle price was $1,400 per ton and the average for 10 trades that active day was $1,390.50 per ton (Evolution Markets, January 27). Evolution Markets suggested the logical cap would occur when the market sees coal plus allowance prices becoming more expensive than natural gas prices on a Btu basis, or when market players on the margin start to sell allowances and buy power on the open market (Evolution Markets, SO2 Markets November 2005). By that reasoning, it is logical to see a correlation between lower prices for SO2 allowances and steadily declining natural gas prices in the face of the widespread mild weather since mid-December. Since the Wednesday-to-Wednesday week ended December 13, 2005, the natural gas spot price at the Henry Hub declined by 42.6 percent , from $14.80 per million Btu (MmBtu) to $8.50 per MmBtu. During that same period, the settlement price for year-2006 SO2 allowances declined by 10.7 percent, from $1,630 to $1,455 per short ton, and to $1,400 by Thursday, January 26. The lower spot prices are paired up with unusually good supplies of natural gas, for which very few SO2 allowances would be needed (storage is 21.7 percent above average for this time of year). For each major coal-burning generator or industrial plant the decision - whether to burn coal, to switch to gas-burning generators or boilers if available, to purchase power, or to follow other options - depends on individual circumstances, but for many the rationale for conserving coal stockpiles for a while is better than at any time in 2005. Although certainly not a trend at this point, the spot price for PRB 8,800 Btu coal dropped by 9.7 percent in the single week ended January 20. In a number of regions, day-ahead and forward prices for power purchases have declined recently. Whether power producers with coal-fired capacity opt to buy power off the grid depends on complex individual assessments of each one's mix of generating technologies, coal stocks, supply contracts, transportation options, access to other generation energy sources, and - in rapidly changing power markets - on timing. Dialogue between Platts and market players attributes the unprecedented price spikes in part to speculative trading by banks and hedge funds, which have at least doubled market activity since 2004. Traders also noted that although a large number of electric power producers intend to install flue gas scrubbers, many in that group may be scrambling to acquire needed allowances before the year-end compliance deadline (Coal Trader, December 12, p 5). In contrast to 2005 SO2 allowance prices, year 2005 emission allowances of nitrogen oxide (NOx) trended down in price last year. The 2006 and 2007 allowances traded relatively level, and generally below 2005-vintage prices. NOx gases are formed primarily from combustion air and from subsequent chemical reactions in the atmosphere. Virtually no precursor free radicals of nitrogen are normally derived from the fossil fuels combusted, unlike SO2 emissions, for which the sulfur is contributed by the fuel and oxidized during combustion. NOx allowance prices offer a meaningful contrast with the behavior of the SO2 market during a year when low-sulfur coals were in short supply. Most of the new crop of flue gas desulfurization units currently under construction or planned (EIA identified 21.6 gigawatts planned as of late 2004) will be operational by 2011. Their influence could constrain high volatility in future SO2 emission prices. After unusual growth in coal exports in 2004 (5.0 mmst over 2003), 1Q2005 exports were ahead of 1Q2004, but that pattern reversed in 2Q2005. (EIA, Quarterly Coal Report, Table 1, December 21, 2005). Since then, coal exports were roughly equivalent to those of 2004, with the result that exports year to date at the end of September were nearly the same as in the same period of 2004: 37.6 versus 37.2 mmst. U.S. coal exports continue to be led by metallurgical coal, but the year-to-date totals are also very similar to the prior year for met coal (21.7 versus 21.4 mmst in 2004) and for steam coal exports (15.8 mmst in both years). On the other hand, coal imports are up by 13.5 percent for the first 3 quarters of 2005: 22.7 versus 20.0 mmst in 2004.
For many years, especially in foreign production centers, direct reduction iron (DRI) has been a useful intermediate product. DRI is made using crushed natural ore, possibly small amounts of fluxes, great amounts of natural gas to heat the ore, and mo coke. The result is 97 percent pure iron, as compared with blast furnace hot metal, which is only 93 percent pure. The DRI - either granular or pelletized, depending on whether it is used on site or shipped - is used in mini-mills and melt furnaces to produce various type of finished steel. When the DRI is shipped, the steel can be produced in small, lower-cost facilities, near where the finished product is needed. Research has been ongoing for years on processes that would eliminate the need to consume vast amounts of natural gas and would incorporate coal. Most results have been only partly successful and have not advanced beyond bench scale or pilot plant set-ups, but now a company in Minnesota, Mesabi Nuggets, LLC, plans to have such a plant operating by 3Q2007. [Please link to: http://mesabinugget.com/ ] The iron-rich "nuggets," including powdered coal largely as a carbon source, will be produced at a location about 4 miles north of Aurora, Minnesota, and will be shipped to a Steel Dynamics, Incorporated mill near Butler, Indiana. The manufacture will use the Kobe Steel ITmk3 process co-developed with Midrex International. In international markets metallurgical coal demand expectations are varied and mixed. A Wall Street Journal article predicts that met coal prices will decline by about $10.00 per metric tonne in 2006, from prices in 2005 ranging from $78 to $125 per tonne (depending on quality) in world markets (WSJ, January 13, p A2) The core issue affecting met coal is that 2005 domestic steel production in China was well above projections, resulting in a glut of steel despite China's current position as the world's largest consumer of steel. The Chinese State Council released new regulations to reduce unneeded steel capacity by shutting down blast furnaces with less than 300 cubic meters capacity by the end of 2007, and also to shut down small converters and arc furnaces by the end of 2006 (Metals Place, January 10). China's largest steel producer, Baosteel cut prices by at least 10 percent November 22, after cutting prices by 15 percent in August (Financial Times (FT.com), November 22). As noted in the Transportation section (below), Chinese steel producers have been drawing down iron ore supplies. It appears the same is true of metallurgical coke. To deal with slow domestic sales of met coke, producers in China were reported offering coke for $130 per metric tonne at Chinese ports (U.S. Coal Review, November 21, p 5). Prices in that range for coke, if they persist in steady volumes, would deter further sales of metallurgical coal above $100 per tonne ($90-$91 per short ton). Much depends on location and timing. Some producers, especially those with new contracts, are confident that demand will remain high over the next several years, just not greater than $100 per short ton. The graph below, and its downloadable data file include data available through October 2005. They show quarterly average values based on coal cost data EIA collects from coke plants. It also depicts monthly average values declared for met coal brought to ocean terminals for export, from U.S. Customs data. The values reported include the costs of transporting the coal to the coke plants or export districts. The October data reflect a $4.83 per short ton rise over September in average declared value of coking coal transported to export docks. Unlike most prices reported in coal newsletters, the values below are based on surveys of actual shipments. These prices are about 2 months old, however, when they are first available and do not address future prices. Because the prices below are averaged and include met coal shipments from multi-year contracts and traditional 12-month contracts - and not just spot shipments - variances are less extreme than in some spot price reports.
Estimated monthly coal production for December 2005 was 90.3 mmst (see graph below). The December EIA estimate amounts to a 2.3 percent, or 2.1 mmst, decrease from November’s 92.5 mmst. The December production estimate is a hefty 5.1 mmst below that of December 2004. Preliminary estimates of the year’s production totals 1,119.9 mmst for 2005, which is 7.8 mmst, or 0.7 percent, greater than the final production for 2004. The U.S. Monthly Coal Production graph (below) includes production based on final mine-level reports for 2004 by the Mine Safety and Health Administration (MSHA), EIA Weekly Coal Production estimates through the end of 2005, and revisions to EIA estimates based on initial MSHA mine-level surveys for 1Q2005 through 3Q2005. The revised coal production through the first three quarters of 2005 was 845.9 mmst, based on completed MSHA data. That is 14.8 mmst, or 1.8 percent, more than in the first three quarters of 2004.
If future coal demand is on the rise, as many believe, future coal supplies will require additional production from mines currently in planning and permitting stages. The number of coal mines announced, planned, or reopening increased in 2005. In the PRB, Basin Electric Cooperative expects to submit a siting permit in January for a 375-megawatt coal-fired minemouth plant north of Gillette, Wyoming. The plant would burn an estimated million tpy of subbituminous coal from the nearby Dry Creek mine and transmit the generated power to the western part of its service area (Coal Outlook, November 28, p 6). The fact that rising prices of basic mining materials - steel, diesel fuel, explosives, for example - have helped swell coal prices was noted here in the past. A greater concern, however, is the unavailability of key materials, especially steel and rubber. The biggest impact may be experienced in severely delayed or incomplete deliveries of new equipment. Slowed specialty steel deliveries delay assembly of new equipment. Mine trucks and other rubber-tired equipment have been delivered without tires, which may not be available until 2006 or 2007. An informal search found that a critical scarcity of the enormous tires needed for mine trucks has been an issue at least since early 2005. On March 18, Argus Coal Daily (p 3) noted that PRB mines' capital costs were increasing as a result of "heavier equipment to mine through thicker overburden (and) of the increased cost of steel, rubber and other commodities." Further, mine operators were finding that key equipment was becoming unavailable regardless of cost: "The tires needed for the extremely large surface-mining equipment and trucks are proving to be difficult to acquire not only in Wyoming but globally, with Asian miners saying they, too, are having trouble keeping their trucks shod." Mine operators in the PRB and Appalachia had become accustomed to delays in delivery of new tires and to having old tires repaired or retreaded. Because it is remote from most suppliers, the 30-million-tpy Cerrejon mine in Colombia employs 1/3 of its 3,600 blue-collar labor force repairing and rebuilding equipment. That includes retreading their own mine truck tires, the number of which doubled to 280 in 2005 (U.S. Coal Review, March 21, pp 18,19). By May, ILB mine operators wanted to increase production to meet growing demand but "they can't find rubber tires, they can't find equipment, and they can't find people. They're robbing from one another," according to one source. And, it was reported that "It's gotten so crazy, I've heard of people taking delivery on pieces of equipment that don't even have tires on them" and tire dealers were offering to buy used tires from idle or inoperable equipment (Coal Outlook, May 30, p 1). By October, the wait for new equipment, such as an earth scraper, which had previously been 8 or 10 weeks, was up to 52 weeks. This was not "a new story" and - although sudden increases in coal demand was a factor - it was rumored in the coalfields that Chinese industrial expansion had taken all the equipment. New haul trucks were still being delivered without tires, and steel in the form of spare parts and replacement engines were unavailable (U.S. Coal Review, October 24, pp 1, 15). There has been no change as the year-end nears. "One major coal producer is parking its big trucks on rainy days to preserve tires" another hopes to reduce wear and tear by putting chains on its big tires and "carefully monitoring maintenance." The shortages in tires and steel products extend beyond the coal industry, of course, but the fact that the problems are widespread apparently is not enough to improve their prospects. The outlook for tires is reportedly that Goodyear is sold out through 2006 and Michelin through mid-2007, even though Michelin is constructing a new tire plant in Brazil and planning one in South Carolina. Bridgestone says it will expand three "big-tire" plants in Japan. Even with those efforts, industry sources expect the global shortage not to be totally resolved until 2010 (Coal & Energy Price Report, December 14, p 3).
At the McCloskey U.S. Coal Imports Conference 2005, in Baltimore on November 30 and December 1, coal terminal operators confirmed plans to add more coal import capacity along the U.S. Gulf and Atlantic coasts. Kinder Morgan is expanding terminals along both coasts. The most imminent is the expanded Fairless Hills terminal on the Delaware River in Pennsylvania. Final permits are expected in time for a January 2006 restart of the 2 million short tons per year (tpy) capacity, double its previous size. McDuffie Terminal in Mobile, Alabama, is increasing its capacity during 2006 from 16 million to 18 million tpy, along with adding a new loading and unloading berth, additional stackers/reclaimers, a third barge unloader, and unit train loading. For 2007-2008, McDuffie plans include a new blending belt between two of its yards and attracting additional rail carriers. Dominion Terminal Associates (DTA) in Newport News, Virginia, expects construction or installation to begin in spring 2006 on transfer towers, conveyors, belts, two additional cranes, and a 600-foot pier lengthening. The project in-service date is mid-2007 with new capacity at 7 million tpy, up from 5.2 million tpy in 2003. The Point Tupper terminal in Nova Scotia added a Belgian E-crane in 2005 and was improved to permit docking of cape-size vessels. The terminal does not have loading, transfer, or vessel-to-vessel transloading capabilities, but the facility management firm, Savage Industries, indicated willingness to expand in those areas to meet demand. At least one coal-fired power plant in Massachusetts has been known to import Indonesian coal by way of a Nova Scotia port and stored it there. Smaller transshipments are made to the power plant as needed. The Dakota, Minnesota & Eastern Railroad (DM&E), along with its sister railroad, the Iowa, Chicago & Eastern, applied for a $2.5 billion loan from the Federal Railroad Administration to build a third railroad into the Powder River Basin. The loan would virtually guarantee the fruition of the DM&E’s years of effort, which started in 1998. Construction on the 3-year project could start in late 2006 if the loan is approved, according to Kevin Schieffer, president and CEO of Cedar American Rail Holdings, Incorporated, which owns both railroads. DM&E expects to haul 100 mmst of PRB coal per year when the line is built. In April, the Surface Transportation Board reaffirmed its approval of the DM&E project to build a third PRB line. DM&E is filing for the loan under a provision authored by Senator John Thune, R-SD, that was part of the $286 billion Transportation Reauthorization bill enacted earlier this year. Senator Thune stated, “This project could transform South Dakota’s economy for generations” (Coal Outlook, November 14, pp 10-11).
Secretary of Energy Samuel W. Bodman announced on December 6 that the Department of Energy signed an agreement with the FutureGen Industrial Alliance to build “FutureGen,” a prototype of the coal-fueled power plant of the future. The nearly $1 billion government-industry project is designed to produce electricity and hydrogen and to produce no emissions, including no carbon dioxide, a greenhouse gas. Possible site nominations will be solicited in early 2006, final site selection in 2007, and operations are planned for 2012, using cutting-edge technologies, including advance carbon capture and sequestration. The FutureGen Industrial Alliance will contribute $250 million to the project. Alliance members are: American Electric Power; BHP Billiton (Melbourne, Australia); CONSOL Energy; Foundation Coal; China Huaneng Group (Beijing, China); Kennecott Energy; Peabody Energy; and Southern Company (U.S. Department of Energy, Press Release, December 6). The December 12, 2005, edition of Business Week magazine highlighted climate change and how U.S. and foreign companies are addressing the issue. The lead article – one of 13 features on the climate change subject – finds that a “surprising number of companies in old industries such as oil and materials as well as high tech are . . . moving swiftly to measure and slash their greenhouse gas emissions,” even though current U.S. law does not require mandatory curbs. American companies following that approach are not just trying to win the approval of environmental proponents; they are doing so out of good business sense, with an eye on the bottom line. Bankers, insurers, and institutional investors have determined that the financial risks associated with climate change are too high not to start preparing. And, based on an informal poll, many technology and energy industry CEO’s expect the United States to impose mandatory curbs on carbon dioxide and other greenhouse gases (GHG), eventually. The rationale for cutting back on GHG production turns out to be sound economics, according to business leaders. Many measures taken achieve the GHG reductions in part by reducing fossil fuel consumption, often using low-tech, common-sense changes. For example, in 2002 International Paper increased the use of wood waste in its fuel mix (from 13 percent to 20 percent), with the result that carbon dioxide output went down, as well as energy costs. Alcoa, Incorporated, reduced GHG emissions by 25 percent and saved on energy costs by improving a key step in its aluminum production process (Business Week Online, “The Race Against Climate Change,” accessed December 7). Jim Rogers, the CEO of Ohio-based utility, Cinergy, supports mandatory national limits on carbon dioxide even though 95 percent of Cinergy’s electricity is produced by burning coal. He believes the political momentum in Congress to limit GHG is “unstoppable.” Further, the consensus of Mr. Rogers and his advisors at Cinergy is that global warming is real, is hastened by GHG’s from human activities, and that the science indicating that is unlikely to be refuted. Accordingly, Cinergy is making changes “actively and quickly.” Mr. Rogers said that a proactive approach can give a major GHG producer credibility, engender public good will, improve Cinergy’s negotiation position on spreading GHG reduction burdens to other industries, and decrease expensive lawsuits (Business Week Online, “Cinergy Answers Burning Questions,” accessed December 7). On November 22, Goldman Sachs called for the Federal Government to issue rules for a viable U.S. market in greenhouse gas (GHG) emissions. In its new environmental policy, the global investment bank and securities firm said, “Markets are particularly efficient at allocating capital and determining the appropriate prices for goods and services we purchase. The government can help the markets in this regard by establishing a strong policy framework that creates long-term value for greenhouse gas emissions reductions and consistently supports and incentives the development of new technologies that lead to a less carbon-intensive economy.” Goldman Sachs’ policy states that voluntary actions to cut emissions are inadequate and that the firm “will work to develop partnerships with other organizations to help identify and promote effective and efficient regulatory/policy approaches to reducing [GHG] emissions” (Coal Outlook, November 28, pp 10-11). The Department of Energy and the Environmental Protection Agency (EPA) encourage voluntary reporting and reductions of GHG. More than 70 U.S. companies have registered with the EPA’s Climate Leaders program, set corporate GHG reduction goals, and are measuring their progress through emissions inventories. In addition, more than one third of the State governments have enacted GHG reporting systems or expressed interest in GHG regulation or markets. Currently, U.S. policies on climate change are based on development of technologies to control GHG emissions or to avoid producing GHG’s in the first place. In June 2004, Then Secretary of Energy Spencer Abraham stated that because “the United States has a Gross Domestic Product of $11 trillion, with a desired rate of growth of at least three to four percent . . . we will unavoidably continue to generate substantial greenhouse gas emissions—despite pursuing greater energy efficiency and the use of alternative fuels—so long as we use traditional or conventional technological approaches.” Consequently, U.S. policy reasons: “the only possible path to offset these likely GHG increases is by developing truly transformational technologies that will bring us into an entirely new energy age. This is true, because no nation is prepared to trade economic growth, to mortgage its prosperity, for cuts in greenhouse gas emissions” ("U.S. Climate Policy: Toward a Sensible Center,” Conference, Brookings Institution). Secretary Abraham explained that the technologies developed under the U.S. approach would be even more beneficial “in many developing countries, which are moving toward an explosive burst in energy demand, but lack many of the efficiency measures we have deployed here in the United States.” The Chicago Climate Exchange (CCX) is North America’s only multi-sector market for reducing and trading greenhouse gas emissions credits. Members of CCX make legally binding commitments to establish a rules-based market for reducing greenhouse gases and include a cross-section of North American corporations, municipalities and other institutions. The CCX market gives members a way to receive credit for reductions, to buy and sell credits, and thereby to determine the most cost-effective means to achieve emission reductions. Its members include Ford Motor Company, International Paper, and American Electric Power, the country’s largest coal-burning utility. On November 21, the Ohio Air Quality Development Authority joined CCX as an associate member. The authority is the first major state-funded coal research and development organization to join the CCX program. Associate members produce small or no direct emissions; they commit to comply with CCX rules by offsetting the greenhouse gases associated with certain business-related activities (SNL Coal Report, November 28, pp 18-19).
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