GLG News by Thomas Shewski

Implications:     The court decision striking down the Clean Air Interstate Rule will have an affect on SO2 allowances and the SO2 premium earned by coal suppliers.

Analysis:     The court’s decision struck down the Clean Air Interstate Rule, including the provision requiring the Eastern states to relinquish 2 SO2 allowances for every 1 ton of SO2 emissions in 2010 and 2.86 allowances for every 1 ton of SO2 emissions starting in 2018.  Instead the status quo requirement remains of 1 SO2 allowance for every 1 ton of SO2 nationwide under the existing Clean Air Act Amendment passed by Congress and signed by the first President Bush.
 
     Under the existing Clean Air Act Amendment, a SO2 allowance has a vintage-year for which it can be used to meet SO2 emissions.  If it is not used, it may be banked and used for emissions compliance in a later year.  The number of banked SO2 allowances currently stands at approximately 6.75 million allowances.  Actual SO2 emissions in 2007 were approximately 500,000 tons below the annual cap and likely to grow in future years with the scrubber retrofit projects underway.
 
     As a result of the court’s decision not requiring a 2:1 surrender rate in 2010 and 2.86:1 surrender rate in 2018, there are plenty of SO2 emissions allowance supplies to meet SO2 emissions.  As a result, the value of SO2 allowances fell to nearly an all-time low on the day of the court decision against CAIR (July 11).
 
    The destruction in the value of SO2 allowances will affect the realized price received by coal suppliers starting in Q3 2008 because they earn a premium for delivering coal with sulfur under the contractual guarantee and the value of this premium is tied to the monthly weighted-average of an SO2 emissions allowance.  For illustration purposes, the premium a PRB coal supplier earns on super-compliant coal is only about 30 cents per ton at the current low SO2 allowance prices. 

Implications:     The decision by the U.S. Court of Appeals for the District of Columbia Circuit striking down the Clean Air Interstate Rule (CAIR) will affect emissions control spending in the immediate term.

Analysis: As a brief background, CAIR was to further reduce NOx emissions starting in 2009 on an annual basis beyond the already in place in a seasonal NOx program and further reduce SO2 emissions starting in 2010.  The plan covered 28 states in the Eastern United States.  CAIR was put in place in March 2005 by the EPA. 

     Challenges to CAIR led to this court case.  The court overturned CAIR based on the regional basis of the rules, rather than state-specific limits and the EPA’s change of the surrender rate on SO2 emissions allowances from the current 1 to 1 ratio to 2 to 1 in 2010 and 2.86 to 1 in 2018, among other reasons.               

    Coal-fired generators in the CAIR states were gearing up for the upcoming NOx and SO2 reductions through analysis, purchase, and ultimately the construction of SCRs or NSCRs to remove NOx and scrubbers to remove SO2 on existing coal plants.  Many retrofits have been completed, with more scheduled in the next two years.               As a result of this Court ruling, it is unlikely that a coal-fired generating utility or independent power producer in the affected CAIR states will make any commitment on new environmental control systems to reduce NOx or SO2 until either Congress or the EPA issue new emissions reduction laws or regulations.  The new laws or regulations could take into the next Administration to be completed and then taking effect a few years later.  Companies without definitive commitments for emissions control retrofits will take a wait and see attitude before moving forward.    

    Those with emissions control retrofit projects ordered or underway will complete the projects.  These projects are in the construction pipeline for the next 18 to 24 months or so.

Implications:     The U.S. Court of Appeals for the District of Columbia Circuit struck down the EPA’s Clean Air Interstate Rule (CAIR) to reduce NOx and SO2 in 28 Eastern United States.  This follows a court decision striking down EPA’s Clean Air Mercury Rule (CAMR).       These court decisions will eventually cause actions and opportunities in the emissions control space.

Analysis:     The court decisions striking down CAIR that required a reduction in NOx and SO2 in 28 Eastern states and CAMR that required a reduction in mercury will allow emissions at the status quo for a period of time.  It is unlikely that Congress and EPA will allow this status quo on emissions to continue.  Instead, it is likely that Congress and EPA will develop new, and stricter, emissions reductions rules on NOx, SO2, and mercury.  It could also include CO2 as well. 

     In the meantime, coal-fired generators will not commit to emissions retrofits to comply with federal rules until new rules are known.  Those environmental retrofits underway or committed will be completed over the next 18 to 24 months. 

     The new emissions rules will likely be more limiting than those under the cap and trade CAIR and CAMR programs.  As a result, it will actually require more emissions control equipment be installed on coal plants than under CAIR and CAMR that was struck down by the courts.  The remaining question is the effective date(s) for these likely new emissions-limiting rules.

Implications:     Railroads, unlike airlines and trucking firms, are able to pass along the high cost of fuel in  transportation agreements.  Below discusses this and the value to the railroads for coal transportation.

Analysis:     The railroads transport approximately 70% of U.S. coal as the final carrier.  (Other transportation methods may be involved such as barge, conveyor, or truck.)  The railroads have re-priced legacy transportation agreements over the last 4 years, including a fuel surcharge mechanism.
 
     The railroads have a fuel surcharge mechanism in place tied to the Highway Diesel Fuel Average used for coal transportation two months later.  Utilizing the 2006 average rail transportation haul of 850 miles, the BNSF fuel surcharge of $0.53/car/mile, and an average of 118 tons of coal in an aluminum coal car, the fuel surcharge would add an additional $3.82/ton to the coal transportation cost.  This helps the railroads cover the high cost of fuel. 

     Approximately 1/3 of the railroads coal transportation agreements are still to be re-priced and include a fuel surcharge.  This will be an additional upside for the railroads as these are included in existing coal transportation, on top of their volume growth.  For planning purposes, it would be appropriate to assume that these remaining contracts would be re-priced and with a fuel surcharge at the rate of approximately 20% per year.

Implications:     The input costs for utilities to generate electricity are up.  These costs include coal, transportation, natural gas, and power purchases.  There are no guarantees, however, that a regulated utility may pass along these costs as discussed in the commentary section.

Analysis:     The discussion that follows is for regulated utilities, not unregulated utilities (Independent Power Producers.)               

    The cost to generate electricity is going up for utilities.  There are no guarantees, however, that regulated utilities can pass along the costs to customers through increased rates.
 
     First, some utilities do not have a power cost adjustment (“PCA”) provision that allows them to pass along power-related cost increases experienced intra-year.  Instead, any un-hedged fuel or power position risk after a predetermined date prior to the start of the year is borne by the regulated utility—both positive and negative.  Any movement in the cost of fuel or power in this scenario would on the regulated utility, rather than customers.
 
     Second, even in the existence of a power cost adjustment provision, there is the risk the regulated utility could experience a disallowance for failure to be prudent in its purchases.  A regulated utility is always under such look-back scrutiny.  If the fuels department or power operations department were not deemed prudent, the Public Utility Commission could disallow that which it considers to be imprudent.  This has happened in the past.               

    Third, a regulated utility may have a gain-sharing program between it and customers on cost increases and savings on power costs.  These gain-sharing programs may even have a dead band before they trigger or collars.               

    A review of a regulated utility’s financial statement for its hedged position and regulatory treatment and inclusion of a power cost adjustment is prudent to perform.

Implications:     Wind power qualifies for production tax credits.  These production tax credits are set to expire on December 31, 2008 without renewal by Congress and the President.

Analysis:     Wind projects qualify for production tax credits equal to approximately 2.1 cents/KWh produced during the first 10 years of a project.  The wind project must be completed and operational by December 31, 2008 in order to qualify for these credits.               

    These production tax credits help make wind projects economic to proceed versus alternatives.  In 2007, the U.S. expanded its generating capacity by 45% to over 16,800 installed MW. 

     In 1999, 2001, and 2003, the tax credits lapsed and development dropped off significantly; by up to 93% in one of those years.                

    On June 17, Congress could not agree where to get the estimated $7 billion in lost tax revenues over 10 years to renew the credits.  At this point, it is difficult to forecast if Congress will renew these tax credits.  As we approach the end of 2008 without a renewal to the credits, it could have an impact on the orders for wind turbine manufacturers.  Wind turbine manufacturers include General Electric, Vestas, Siemens, Gamesa, Mitsubishi, and Suzlon.

Implications:     Bituminous coal prices have soared over 100% in the last year.  This is obviously bad news to electric consumers dependent upon utilities with a large exposure to coal-fired generation.  The run-up in coal prices could be a benefit to some utilities.

Analysis:     A utility can (and often does) have regulated and unregulated business lines.  Energy provided to customers is regulated with the utility given an allowed rate of return from the Public Utility Commission.  The unregulated are not governed in that manner; rather are “market”. 

     The price run-up on coal can benefit those utilities with unregulated coal assets.  Ironically, one of those utilities with unregulated coal assets is Vectren Corporation that was written about in the linked article.  There was no mention in the article that Vectren Corporation had coal assets; let alone unregulated coal assets. 

     Vectren’s coal mining group mines and sells coal to the company’s utility operations and to third parties through its wholly owned subsidiary Vectren Fuels, Inc (Fuels).  Vectren Fuels, Inc. may sell to the utility’s coal plants at the current high market numbers and such costs of the coal would be passed along to customers through rates as long as the utility demonstrated prudency and it was conducted in an arms-length transaction manner.  This could be demonstrated by the regulated utility formally bidding the coal to objectively demonstrate the market price of the coal and to show it did not pay above market for the coal.

Implications:     As the article correctly points out, capital costs to build a new power plant have risen considerably since 2000; coal plants included.  It is not just the up-front capital costs that have affected decisions to build new coal plants as discussed in the commentary section.

Analysis:     When a new power plant is considered, a real- levelized-cost analysis is performed to determine the alternatives’ economics.  Such analysis considers the plants’ capital costs, return on/of capital requirements, fuel costs, fuel transportation costs, fixed operations and maintenance costs, and emissions-related costs.  Such real-levelized cost analysis is generally done over the 40-year life of the plant, and is also sometimes called “life cycle costs”.
 
     As the referenced article pointed out, the capital costs to build new power plants has soared; including coal plants.  For natural gas-fired plants, the cost of natural gas has risen dramatically in the last few years.  More recently, the coal and transportation costs have soured; in some cases doubling.  This has helped close the economic advantage of coal-fired generation over natural gas-fired generation.
 
     This gap has further closed because of the potential risks and cost impact of CO2-limiting legislation that would essentially tax CO2 emissions from fossil fuel-fired power plants.  A coal plant emits approximately 1 tonne (metric ton) of CO2 per MWh, while a natural gas plant emits approximately 0.4 to 0.5 tonne of CO2 per MWh.  This CO2 cost on coal, on a static analysis basis, closes the gap between coal-fired generation and natural gas-fired generation.              

    The “Climate Security Act of 2008” sponsored by Senators Lieberman and Warner if implemented in its current form is anticipated to add approximately $40/MWh to the real- levelized cost of a coal plant.  Such potential CO2 risk and costs have slowed the announcement of new coal plants and even the cancellation of previously announced coal plants.  New natural gas-fired power plants have been the beneficiary of these cancellations.

Implications:     The recent plunge in SO2 allowance prices may affect the decisions of coal-fired power plant owners.

Analysis:     SO2 allowance prices have plunged over 60% in six months.  This plunge in prices is believed to be from lack of interest from generators more worried about procuring the physical coal in the current high-priced and difficult to secure environment, lost interest from traders, and the outstanding lawsuit challenging the EPA’s authority to change the surrender rate on these SO2 allowances to 2 to 1 in the Eastern states starting in 2010 under the Clean Air Interstate Rule.               

    SO2 allowances were approximately $1,600 in December 2006 and $550 in November 2007.  They are currently approximately $200 each.
 
     This low SO2 allowance price could cause a delay in environmental capital spending by coal-fired generators for scrubbers that remove SO2 emissions.  The $200 SO2 allowance price is well under the capital costs of installing a scrubber and the fixed/variable O&M costs of operating the scrubber (reagent and parasitic load with the consequent lost power sales).  Said differently, it is currently more economic for coal plants currently without scrubbers to maintain the status quo and delay scrubber retrofits and instead emit SO2 and utilize SO2 allowances.
 
     Also, this low SO2 allowance price is at a point where it is actually more economic for a coal plant to emit SO2 and use SO2 allowances, rather than incur the variable O&M costs of reagents and lost power sales from the parasitic load to run the scrubber.  It is unlikely, however, that a generator would risk the public relations fallout from not operating a scrubber and instead emitting SO2.
 
     The last item is the potential risk that comes from a generator that was going to sell its long position of SO2 allowances created from installing scrubbers that remove 90 to 95% of the SO2.  The 60% drop in the last six months alone has dropped the value of the SO2 allowance book of several generators by hundreds of millions of dollars; affecting the potential source of money that was going to be used to pay for the announced scrubber retrofits by these generators.

Implications:     The D.C. Circuit Court of Appeals ruling on February 8, 2009 in favor of the plaintiffs that coal plants could not be removed from the list of mercury sources subject to a Maximum Available Control Technology (MACT) standard and the subsequent movements to require EPA to set a mercury MACT standard for coal-fired power plants provides an opportunity in the mercury control space, including activated carbon.

Analysis:     Senator Tom Carper (D-DE) introduced on February 14, 2008 S. 2643, “Mercury Emissions Control Act” (MECA).  MECA requires the EPA to set a MACT standard for coal-fired power plants.  The bill calls for MACT to remove at least 90% of mercury that would otherwise be emitted.
 
     Activated carbon injection is one of the leading and proven means to remove mercury from a coal plant’s emissions.  One of the companies in the activated carbon space and planning expansion is Calgon Carbon Corporation.

    As the article stated, a coal plant’s configuration and the type of coal it burns influence the control system’s efficiency.  Likewise, it also affects the amount of activated carbon required to achieve the proposed 90% removal rate.  For planning purpose, new plants with 90% mercury removal require approximately 13 lbs per each 100 MWhr.

Implications:     All of the various regulations being discussed in the U.S. Congress to slow, stabilize, and then reduce CO2 emissions nationally include some type of cap and trade system.  Each of these programs have a portion of the CO2 emissions allowances being allocated for free to the U.S. electric generators.  The allocation methodology and the power companies’ generation mix could determine companies’ financial outcome under the program.

Analysis:      A CO2 program would have a reduction in CO2 emissions below a baseline, with the use of CO2 allowances to allow the market to determine the method of compliance with the program.  Under the various proposals being considered, a CO2 allowance would be required for each ton of CO2 emissions.  In the various cap and trade programs being discussed, a portion of these CO2 allowances would be allocated to the electric utility sector for free.
 
     The two methods are based on historical generated electrical output or historical CO2 emissions levels.  Generation output would be denominated in mega watt hours (MWh) produced in the baseline year and historical CO2 emissions levels would be denominated in tons of CO2 emitted during a baseline year.  In both methodologies, the CO2 allowances would be given pro rata to the rest of the nation’s electric generators.
 
     A utility with a higher proportion of zero emissions generating resources, such as hydroelectric and nuclear, would come out favorably under a generation output-based CO2 allocation because it would not need the CO2 allowances to generate on these resources and would be free to sell the excess CO2 allowances to those utilities short the allowances.  On the other hand, those utilities with a high proportion of coal to other generating resources would be at a disadvantage under this allocation methodology.
 
     Companies such as American Electric Power have a high percentage of coal-fired generating resources and would be at an economic disadvantage under a generation output-based CO2 allocation system versus a historical emissions based CO2 emissions-based CO2 allocation system.  Conversely, a company such as Exelon with its high percentage of nuclear generating capacity would be at an economic advantage under a generation output-based CO2 allocation system because the company’s nuclear fleet does not emit CO2 and the company would be able to sell those allocated CO2 allowances based on generation to other utilities short the allowances.

Implications:     The biggest driver for orders of coal railcars will be the new coal plants coming on line the next few years.  The commentary section below discusses the number of new coal plants presented by FreightCar America on its Q1 2008 conference call versus an updated analysis by this author.

Analysis:     FreightCar America stated on its conference call that approximately 75 coal-fired power plants are expected to come on line in the next six years.  FreightCar America forecasts these 75 new coal-fired power plants will require approximately 40,000 coal railcars.  FreightCar America also forecasts that of the75 plants, 47 are currently either under construction, near construction, or permitted for construction, requiring approximately 20,000 coal railcars.  Unfortunately, FreightCar America is using dated information that does not include the numerous number of coal plants that have been cancelled in the last 15 months.  Furthermore, FreightCar America does not reduce this coal railcar demand by those coal plants that will receive coal by truck or barge or are mine mouth; not requiring any coal railcars.    

    Once the number of new coal plants is reduced and adjustments are made for those coal plants not requiring coal railcars for coal transportation, the number of coal railcars required for new coal plants is substantially less than FreightCar America’s estimates.  Recent analysis computes the number of required coal railcars to be less than half of FreightCar America’s estimate over the next six years (2008 to 2013, inclusive).

Implications:     The BNSF and other railroads charge in new coal transportation tariffs and contracts a fuel surcharge to recover the cost of fuel.  Other freight moves also come under fuel surcharges.  The commentary that follows discusses by the numbers the BNSF’s fuel surcharge on coal transportation.

Analysis:     For coal transportation, the BNSF began implementing a fuel surcharge on coal transportation in the 2003- to 2004-timeframe on coal that moves under tariffs and contracts.  It is stipulated in BNSF Rules Book 6100 – Item 3381 – Coal Mileage-Based Fuel Surcharge.  The fuel surcharge is based on the monthly U. S. Average Price of Retail On-Highway Diesel Fuel (HDF) and is applied to the deliveries two months later.
 
     For BNSF coal transportation deliveries in May 2008, the fuel surcharge would be based on the March HDF.  In this rising oil price market, the BNSF’s diesel expenditure in March is not recovered until May; affecting Q1 earnings because of the lag in recovery to Q2.

    The fuel surcharge is a per-railcar charge and is based on the one-way mileage between the mine and plant.  For May 2008, the fuel surcharge on coal transportation is $0.44/ton.  For a hypothetical 1,000 one-way coal haul on BNSF, this equates to $440 per railcar.  At 118 tons of coal per railcar, this equals a $3.73/ton fuel surcharge.
 
     The BNSF transports 15% of coal by tariff and 85% of coal by contract.  Of the contract moves, nearly 1/3 are legacy agreements that do not yet include a fuel surcharge mechanism.  (Note:  These legacy agreements are also substantially under current market rates that will rise significantly once re-priced.)  In 2007, the BNSF transported 291 million tons of coal.  Of this total, 247 million tons (85% of 291) move under contract.  This means approximately 82 million tons (1/3 of 247) of coal transported by the BNSF does not yet have a fuel surcharge.  Using the May 2008 fuel surcharge rate on a 1,000 mile average haul that equates to $3.73/ton and those 82 million tons of coal not subject yet to a fuel surcharge, this is $306 million per year in un-recovered fuel costs for the BNSF’s coal transportation.  Once these legacy coal transportation contracts expire and are renegotiated with a fuel surcharge, these fuel costs will be recovered, improving the BNSF’s revenues.  The same can be said for the other Class I Railroads as their legacy coal contracts expire and new contracts include fuel surcharges.

Implications:     The EPA is currently being challenged in the courts by both the states and industry over various aspects of the Clean Air Interstate Rule (CAIR).  The outcome of the case could provide an opportunity for those trading SO2 allowances.

Analysis:     EPA’s program to control SO2 and NOx through CAIR is being challenged by both the states and industry over five main points.  The litigation has been consolidated in State of North Carolina, et al v. United States Environmental Protection Agency and is at the DC Circuit Court of Appeals.

    One of the five points in the legal challenge comes from industry groups that argue that the EPA does not have the right to change the law passed by Congress in the Clean Air Act Amendment regarding the surrender rate of one SO2 allowance for each ton of SO2 emissions.  Specifically, the EPA in the CAIR states requires the surrender of 2 SO2 allowances for every 1 tons of SO2 emissions starting in 2010; lowering to 2.86 starting in 2015.  Pre-2010 SO2 allowances that have not been used for emissions requirements may continue to be banked and used at the 1-to-1 surrender rate after 2010.
 
     If the Court were to rule that EPA did not have the authority to reduce the SO2 allowance surrender ratio in the CAIR states, the value of the 2010 SO2 allowance would increase because it would no longer be at a 50% value because of the 2-to-1 surrender rate; instead it would revert back to the 1-to-1 surrender rate.

    The SO2 market has priced in some of the potential for the Courts to strike down the EPA’s change of a 1-to-1 surrender rate in the Clean Air Act Amendment to a 2:1 surrender rate under CAIR.  The forward curve for 2010 SO2 allowances should trade at ½ the price of 2009 allowances less the cost of money for one year.  Currently, 2010 SO2 allowances trade at $218 versus 2009 SO2 allowances at $350.  In a market without a Court challenge, 2010 SO2 allowances should trade at slightly less than $175 each ($350/2); reflecting the halving of value of an allowance in 2010 versus 2009 and a discount for the time value of money.

    If the Court were to rule EPA did not have the authority to change the SO2 allowance surrender rate, the likely outcome would be for Congress to revisit and reduce SO2 emissions and other pollutants through a more comprehensive Law.  This comprehensive reduction would likely go into effect after 2010, with the surrender value of the 2010 allowance reverting back to a 1-to-1 surrender rate and being priced near the 2009 allowance value.  This provides an opportunity for those in the SO2 allowance marketplace.

Implications:     SO2 allowances are traded daily in the broker and private party markets.  The value of these credits are down, affecting both the cost to generate electricity on coal and the realized sales price received by coal suppliers.

Analysis:     A SO2 allowance is required for each ton of SO2 a coal-fired power plant emits during the year.  The SO2 allowances have been allocated for free to the power plants through 2037 based on their operations in the baseline years of 1985-1987.  The SO2 allowances are bought and sold by market participants to meet emissions requirements.  In addition, the EPA holds an annual auction for 125,000 spot and 125,000 7-year forward allowances to create an additional marketplace.
 
    The cost of a SO2 allowance affects the dispatch and production cost of electricity from coal.  As of this writing, SO2 allowances are at approximately $350 each, versus $475 each in Q! 2008 and over $1,000 each in Q1 2006.  This lowers the cost to generate from the various coals  in units without installed sulfur emissions reduction equipment (scrubbers).  Comparing current 2008 SO2 allowance prices to where they were priced in Q1 2008, dispatch and production costs are lowered by $0.50/MWh (PRB Coal), $1.03/MWh (Central Appalachian Coal), and $2.79/MWh (Illinois Basin).
 
    SO2 allowance prices are also used to determine the premium or penalty the coal producer receives based on the coal’s sulfur content.  The erosion of SO2 allowance prices lowers the realized price of coal sold by the producers.  For example, PRB realizations would be lowered by approximately $0.28/ton at current SO2 allowance prices versus Q1 2008 prices.

Implications:     The Clean Air Interstate Rule (CAIR) requires a further reduction in NOx from coal-fired power plants starting in 2009.  This reduction in NOx will add to the dispatch cost from coal-fired generation.

Analysis:     The CAIR requires a reduction in NOx emissions in the Eastern United States starting in 2009.  This is accomplished by requiring one NOx emissions allowance for each ton of NOx emissions from the power plant.  The NOx requirements are further subdivided into ozone seasonal NOx (May through September) and annual emissions (January through April and October through December).  Under the program, CAIR ozone season NOx allowances may not be used for compliance with annual NOx reduction requirements (and vice versa). 

     Because of the EPA’s construct of CAIR and certain states not subject to ozone seasonal NOx requirements, the annual NOx emissions allowances are more scarce and trade at a premium to the ozone seasonal NOx allowances.  Currently, the 2009 annual NOx emissions allowances trade at $3,700 each, while the ozone seasonal NOx allowances trade at $650 each; reflecting the supply shortage of annual NOx emissions under the CAIR program. 

     The cost of complying with NOx CAIR starting in 2009 for a coal plant with minimum NOx emissions controls in the more expensive annual emissions period (January through April and October through December) adds approximately $8/MWh to the dispatch cost.  A plant with advanced NOx emissions controls (SCR), NOx emissions costs add approximately $1.70/MWh to the dispatch cost.  Those generators with NOx controls on the plant will be better situated in the upcoming year.  These costs and affect on margins should be considered when evaluating a company’s earnings potential in 2009 and beyond.

Implications:     Coal lease rates in the PRB are climbing and will cut in coal companies’ margins as exhibited by Foundations recent successful lease bid and Rio Tinto’s higher, but unsuccessful bid.  Also, the upfront payments are due often before the coal is even mined.

Analysis:     The lease cost to secure lease tracts are increasing as evidenced by Foundation’s successful 71 cents/ton and Rio Tinto’s unsuccessful 80 cents/ton.  This is substantially higher than recent years. 

     Successful lease payments are paid over five years, with the first 20% payment due immediately to the Government.  Using Foundation’s successful bid in February 2008, that would mean five (5) equal yearly payments of $36.1 million, plus a $3 per acre annual rental payment.  These five yearly payments will all likely be made before the coal is ever mined and sold. 

     The coal is subject to a 12.5% royalty payment on the value of the coal when it is ultimately sold. 

    The lease rates of 71 cents/ton and 80 cents/ton require the coal companies to earn about $1.20/ton just to pay for these lease rates.  Expressed differently, out of Foundation’s approximate 50 million tons per year out of the PRB, about $1.00 per ton of each of those tons sold will go towards the lease payments of the coal block acquired in February 2008.   

    The coal in the successful Foundation lease and unsuccessful Rio Tinto lease cases are approximately 8,500 Btu/lb.  Lease bids for the higher quality 8,800 Btu/lb tracts should be assumed to be at about $1.00 or more per ton.

Implications:     Railroads impose fuel surcharges in transportation agreements such as for coal transport, but the recovery mechanism timing follows the railroads’ purchase of the fuel causing an earnings lag.     Also, legacy coal transportation agreements do not have fuel surcharge mechanisms squeezing margins on these hauls.

Analysis:     In those rail transportation agreements with a fuel surcharge mechanism, the fuel surcharge lags the fuel index (Highway Diesel Fuel Average) by two months.  For example, the BNSF’s fuel purchases in March 2008 will not be recovered until May 2008, affecting Q1 earnings in this rising oil market.  Using a hypothetical haul of a unit train of coal 1,000 miles and the HDF average price on March 17, 2008, the rail rate per ton on the BNSF for those contracts with a fuel surcharge mechanism would be increase by $0.84/ton over the February rates, but not be recovered by the BNSF until May 2008.
 
     Further affecting the BNSF in this situation is approximately 1/3 of the coal transportation agreements have not been reset to include a fuel surcharge mechanism which also affects margins.

Implications:     New Jersey vs. EPA was filed by several states and environmentalists against the EPA’s removal of power plants from the list of mercury sources subject to a Maximum Achievable Control Technology (MACT) standard and that mercury cannot be regulated by a cap and trade system under the Clean Air Mercury Rule (CAMR).  The D.C. Circuit Court of Appeals ruled on February 8, 2008 in favor of the plaintiffs that coal plants could not be removed from the list of mercury sources subject to a MACT standard and did not rule on whether emissions can be regulated by a cap and trade system.                   This ruling opens up opportunities on new and existing coal plants to control mercury.

Analysis:     This ruling opens up opportunities for those in the mercury control space at new and existing coal plants.   

    New coal plants undergoing the permitting process, and likely those with completed permits but not under construction yet, will be required to have a MACT analysis and, ultimately, maximum technology to reduce mercury.   

    The EPA will likely mandate in a few years after considerable analysis and review a MACT standard for the coal-fired plants with a deadline for compliance.  This MACT standard would apply to the over 1,000 coal-fired units and would be a larger reduction in mercury levels and sooner than under the CAMR cap and trade program.   

    In the interim, many states have already enacted their own mercury reductions on coal-fired units with strict mercury reductions or are considering doing so like Wisconsin as reported in the source article.   

    A Federal MACT standard or individual states acting on their own allows those in the mercury control technology business such as ADA-ES or those companies in activated carbon used as a method to collect mercury such as Calgon Carbon Corporation additional markets.  The timing of the mercury reduction required under a Federal MACT or state initiatives will be the driver in increased business volumes.

Implications:     The Citigroup reports states U.S. coal supply is ample and coal plant inventory levels are adequate such that the higher coal prices of the last several weeks will not hold.  The discussion in the commentary section addresses U.S. coal supply and coal plant inventory and takes a different view than Citigroup.

Analysis:     Below are some points for consideration to support relatively strong coal pricing and volumes:
 
    Citigroup states correctly that U.S. coal inventories are up 10 million tons at the end of 2007, versus the end of year 2006 levels.  However, the amount of bituminous (Eastern) coal is down over 3 million tons in the same period.  The coal inventory increase is in subbituminous (Powder River Basin) coal primarily at Western coal plants.  Eastern coal inventories are not at high levels and there have been reports of some coal plants at uncomfortably low inventory levels causing upward pressure on coal pricing.   

    The increase in U.S. exports in 2008 is anticipated to be 20 million more tons than 2007.  These tons are primarily coming from the Appalachian Region because of the coals’ proximity to the Eastern export terminals.  Assuming that the existing coal mines can produce incremental tonnage through efficiencies and working overtime shifts, there still is a shortfall of at least 10 million tons from the Appalachian Region that is not available domestically.  This shortfall is compounded with the cutback of U.S. imports to domestic utilities.  This unavailability of coal has caused a frenzy of coal bid solicitations of Eastern coal for the balance of 2008 requirements at coal plants, as well as 2009 requirements.  In short, a coal generator does not want to be the one without coal in this tight market.  This has caused the current spike in coal pricing.   

    The shortfall in unavailable Eastern coal will need to be made up from the Powder River Basin (PRB).  Adjusting for the heat content differential in the Eastern and PRB coals, 1.4 tons of PRB coal will need to be purchased for each ton of Eastern coal.  This equates to an additional 14 million tons of PRB tons just to make up for the 10 million tons of Eastern coal that are not anticipated to be available for domestic sales.  Prices in the PRB for 2008 and 2009 have come up to collapse the delivered- emissions-adjusted price gap to the Eastern coals.