EPRI COAL MARKETS WORKSHOP:
WILD FLUCTUATIONS, WILD WEATHER
PRESENTED BY: W. DOUGLAS BLACKBURN, JR.
21 JUNE 2002
LESSONS FROM COAL MARKET DRAMA
20 JUNE 2002
INTRODUCTION: CHANGED CIRCUMSTANCES
The year 2001 may follow the plot line from the movie GROUNDHOG DAY. As you may recall, Bill Murray was forced to relive this day until the critical life lessons were learned. The volatility and challenges that were experienced in 2001 may well be repeated. I’d like to point out some of the reasons that supply interruptions should be anticipated in the future. I would also suggest some issues that can be addressed in the fuel procurement stage to mitigate some of the worst features of this future. Finally, I would like to draw some conclusions about a possible future for the new relationships between supplier and customer.
First, I want to at least table some of the challenges the four major coal producing basins face going forward. The four basins are: Northern Appalachia; Central Appalachia; Illinois and Powder River. Studies such as the ones produced recently by Hill & Associates and Marston indicate an average seven-year economic life of current Pittsburgh Seam mines in the Northern Appalachian Basin. This is comprised of a number of mines already nominated for closure and a group of mines with 10-15 year lives. In Central Appalachia depleting reserves offer less opportunity for large long-lived mines. In the Illinois Basin mines continue to close and reserves await a market shift driven by the utility decision to scrub their plants. In the Powder River no new mines are contemplated in the Southern part of the Basin and material handling limits quick short term response to market opportunities.
Specifically, Northern Appalachia will require $3 billion of recapitalization in the next decade to maintain current production. Interestingly the mines that are closing are the ones with historically high seam heights thereby insuring lower mining heights on average in the future. This, in and of itself, might not seem particularly challenging, but combined with geological hazards (for example Mine 84) and intense gas well drilling, will operate to constrain tonnage and productivity improvement. Subsidence challenges for gas priority and historical structures is a real danger for the Basin. Additionally, the consolidation, no pun intended, of the seam will continue. As Federal #2 approaches the end of its economic reserves, Peabody Energy (Peabody) must decide to move to reserves which the Blacksville #2 mine and Martinka mine found non-competitive due to mining conditions. Any decision by Peabody to postpone this move will essentially leave the Pittsburgh Seam to Consol Energy (Consol) and RAG Coal (RAG).
In Central Appalachia, the USGS has recently published a study that concluded that reserves were depleting in several major seams. An informal study by Caperton Management found few opportunities for major producers to develop the next large long-lived project. In fact, the best opportunity was probably the return of Arch Minerals to DAL-TEX. However, Judge Haden of the Federal District Court for the Southern District of WV has clouded this once again with his recent order suspending permit approvals by the US Corps of Engineers under Section 404 of the Clean Water Act. Not only are surface mines affected by this decision but also underground mines and preparation plants are implicated. Additionally, CHIA litigation that forces regulatory agencies to consider the combined hydrologic impacts on a watershed is adding uncertainty and delays to the permitting process.
Central Appalachia is in a period not seen since the late 1960’s. After 18 years of a declining coal market, the workforce has lost many of its talented and most highly credentialed employees. An inability to attract youth and talent is a critical constraint on production. Where will the industry find certified supervisors, EMT’s and electricians? Massey Energy (Massey) and others have set up in-house training to address this problem only to lose many of their students to recent layoffs resulting from poor market conditions. Underground mines are exploiting; thinner seams, seams with higher levels of reject and geological hazards. And it is taking 18-24 months to permit these mines. During the period 1969-1979, Central Appalachia productivity was cut in half as new employees were hired to deal with new regulatory schemes and more difficult seam conditions. MSHA data indicates that USBM District 8 (Central Appalachia) surface mine productivity peaked in the fourth quarter of 1999 and underground productivity peaked in the first quarter of 2000. Unlike the 1980’s, there is no technology fix on the horizon to offset the secular trend.
A recent longwall census reports that 55 longwalls operate today against a peak of 128. Arch Mineral (Arch) has the only long-term successful installation in Central Appalachia steam coal and it has announced that it will cease operation in 2006, if, permitting allows continuance. Arch also has the last significant dragline property at DAL-TEX. However, concerns over valley fill litigation have forestalled further development. Longwalls and draglines will not turn the productivity slide as they did in the mid-70’s.
Adding insult to injury, quality degradation is also becoming an issue. Compliance Coal reserves, originally found in 22 counties from Pikeville, KY in the southwest to Summersville, WV in the northeast are depleting at an ever increasing rate. A study commissioned by Zeigler Coal Holding Company predicts that only five counties will produce substantial compliance tonnage by 2010 and only two counties will produce substantial tonnages by 2020. Sulfur levels will continue to rise through this decade and availability of direct ship coal will decline dramatically.
These challenges and the lack of earnings that followed from 18 years of revenue declines, have led to financial uncertainties and lender reluctance to fund projects. In fact, many of the “Coal Banks” no longer participate in mine development financing. This has driven the industry to mezzanine, read expensive, financing. The smaller reserve blocks that are available for development don’t justify major mining houses attention. Independent operators will become the miner of choice for new development in Central Appalachia. Query where will the financing come from for these players? Query, in project financing, who will be the guarantor until development risks are conquered?
It should come as a surprise to no one that the historical reliability of Central Appalachian producers is at risk. This reliability has allowed customers to draw down stockpiles to historical lows and interruptions such as the outage at Martin County Coal have the potential to trigger 2001 like market conditions.
The Illinois Basin has evolved into two regions going in different directions. Mine closings in Illinois continue the slide driven by the Clean Air Act of 1990. In fact, of the nine significant mines in Illinois, most are closing or moving to new reserves. Reserves of low sulfur coal found in Franklin County are essentially mined. Recent additions such as Willow Lake may reverse this trend. However, the story of Indiana is one of restructured growth, although dominated by one producer. Indiana is expected to lose 40% of its surface mine production and triple it underground production by 2011.
The good news for the Basin is that Phase II of the Clean Air Act and proximity to utilities will argue for a resurgence of the Illinois mining industry. In fact, the only elephant (major) reserve blocks of low cost, mid-sulfur coal left for development east of the Mississippi occur here. Arch and Peabody have announced intentions to develop mine mouth generating projects on coal lands held by them. Recently, TVA announced the first auctions of their tracts. The award went to Central Appalachian independents, Cline Resources and Larry Addington’s Illinois Fuels Co. Assuming water and power line capacity issues can be addressed economically, Southern Illinois may indeed become the next generation’s coal basin. With the sale of Exxon’s Monterey Coal Company, the short life of Horizon Natural Resources Mine #11 and the constant threat of closure of RAG’s Wabash mine and Freeman United’s Crown #2 mine, the field seems left to Peabody. Constraints in the Powder River Basin may, in fact, assist in the resurrection of this Basin.
Although the Powder River Basin has looked invincible for the last 20 years, limits to growth are appearing. First, the railroads reached a capacity level of 63 trains per day during 2001 but could not sustain that level for any ninety-day period. Obviously, railroad capacity will grow but it will take time and money. Short- term constraints exist for all the mines material handling systems in general and crushing capacity in particular. One material handling system (that I am intimately familiar with) cost $18million and required a year’s construction time. This does not include permitting time that is always a consideration in the Basin.
Secondly, the acquisition of reserves has become an increasingly costly exercise. Uncontested reserves cost $0.20 per ton in 1998. A recent contested Lease By Application (LBA) cost in excess of $0.70 per ton of reserves. More interestingly, this represents approximately $1.00 per produced ton for the next five years for the acquirer. The next LBA’s to be contested could well drive the figure toward $1.00 per ton of reserves. Returns on assets over the last ten years make it increasingly likely that capital rationing will occur and further consolidation will take place as well. With the results announced by Vulcan Capital Management (Vulcan) for the last two years, an argument can be made that there is still one too many producers in the Basin.
Finally, the Powder River Basin is not immune to regulatory risks. Recent proposals by the Executive and Legislative Branch of government will severely limit releases of mercury into the atmosphere. Under either scenario, the Powder River Basin will be significantly impacted. Comparatively, the PRB has the highest levels of organic mercury and therefore, since there is no best available mercury removal technology, will face limits on its application as a fuel source. For several years, permits have been contested and inspections have focused on fugitive dust produced by cast blasting techniques and haul road usage. This attention will only increase as the industry relies on these techniques. Additionally, with increasing depth, the highwalls that are developed by the draglines will attract scrutiny from MSHA. Should MSHA choose to require ground control plans, the ability of draglines to operate would be severely constrained.
For the forgoing reasons, interruptions in supply from the major coal producing basins can and should be expected. The historian’s question: Then what is the concentration of this paper.
FUEL SUPPLY CONTRACTING REGIME
Given the challenges outlined above and the market realities expressed in the OTC trading regimes of the Pittsburgh, Big Sandy and Powder River typical coals, the question naturally arises: Then What?
At this time I’d like to consider some thoughts on contracting for fuel supply that might effect a new risk sharing mechanism and allow operators to plan and operate their mines most efficiently and finance the necessary capital plant to remain reliable suppliers of cheap energy. Short of significant increases in price these are contractual issues that may improve the operators’ ability to continue a stable, dependable supply.
Fuel supply agreements must allow either party to suspend shipments until disputed quality issues can be settled. The UCC provides for operators to offer reasonable assurances for future compliance. In the most alarming cases both parties need the option of terminating the contractual relationship short of corporate suicide. In the future, sources of coal will become more susceptible to geological and quality aberrations and the fuel supply agreement should be drafted to acknowledge the increased variability and risks associated with producing coal from more difficult and less attractive reserve bodies. Additionally, the agreement should provide as much flexibility for the operator on scheduled deliveries as is practicable. It is not clear that the historical reliability of shippers can be depended upon going forward. Therefore, in order to avoid costly arbitration and/or litigation, a more flexible approach to suspension/termination is necessary.
It becomes, for operators, important to limit express warranties and disclaim any implied warranty for fitness of purpose and merchantability. In the current environment when source agreements are increasingly turning to supply agreements operators face evermore risks with the possibility of an agreement being traded.
Additionally, the agreement should explicitly acknowledge the sole and exclusive remedy for breach. This allows the operator and his banker to accurately evaluate and price this risk.
Uniformity of Supply
As coal fired plants reach for higher utilization rates, one of the significant contributions suppliers can make is uniformity of supply. Boiler efficiency is particularly sensitive to feedstock variability. With the certain knowledge that direct-ship coal is becoming rare, it is obvious that steam coal will increasingly rely on coal preparation. An economic argument can be made that a shipper that can reach 3 SIGMA quality control can add significant value to its customers. In fact, one utility has consistently exceeded nameplate rating by 10-15% due to the consistency of feed from Marrowbone Development Company. It would seem to be natural to consider a new contractual clause that would provide an inducement (gain sharing) for the operator that could and would commit to such tight control of quality.
Most mining equipment has a useful or depreciable life of five (5) to seven (7) years while preparation plants and concomitant material handling systems have lives of 20 plus years. Typically, financing for plants however are limited to eight (8) to nine (9) years. Financing for typical mining equipment is of much shorter term. With the needed recapitalization of the eastern industry, some thought should be given to match the contractual term to the financing needs of the project. That is, a ten-year term may be the determinative factor that allows construction of a new efficient plant. The plant’s ability to deal with increasing reject levels and efficiently extract coal from shale and clays may be the difference in green lighting the project.
Coalmines must be assured of a fixed tonnage level in order to correctly size the equipment and provide for the knowledge, ability, skills and habits of a competitive workforce. Capital intensity in the east requires investments of $25 per annual ton of capacity. Capital intensity in the west requires investments of $10 per annual ton of capacity. These large capital burdens require high utilization rates. Fuel supply agreements should acknowledge this by fixing the tonnage requirement during the term of the agreement. Flexibility can be found in the pricing mechanism. Frequent reopeners can protect both parties from 2001 shocks. Prices can be indexed to provide the operator protection against shocks such as the Powder River has experienced with the price of diesel fuel. A rise from $0.85 to $1.15 per gallon has cost one operator $500,000 per month. Careful construction of an index that represents the market conditions of the operation can protect the operator and reopeners can provide both parties protection against the once in a lifetime market swings.
Reopeners require an evaluation of the market. Parameters for this examination should be limited and set forth clearly in the document. Forcing a highly capitalized operation to compete against the marginal tonnage of a competitor in a reopener is a major deterrent to development. A clear definition of a comparable mining operation, for purpose of this clause, is critical.
Another contractual response is offering the shipper the Right to Match. Tonnage is thus assured, risk of forfeiture is minimized and the draconian effects of a market anomaly are reduced or eliminated.
Finally, Baseball Arbitration should be the exclusive remedy for this type of dispute. Both parties must begin with reasonable positions to eliminate this powerful lever in negotiations. Baseball Arbitration, because of its “one side prevails” mechanism provides drastic risks for the unreasonable negotiating position.
Option Tonnage: The 2001 Problem
The coal-trading regime has shown conclusively that real options have significant value whether to increase or decrease annual coal takes or extend term beyond the fixed term of the agreement. However, these options have significant risks for the operator. First and foremost, the operations that are still competing today are running at close to optimal levels and significant, costly changes are required to reschedule tonnage. Options to increase or decrease shipments by more than 5% imperil operators. In fact, in 2001 much of the shock came from demands by most customers to exercise option tonnage at the same time. Option tonnage is only taken when cheap spot alternatives are not available and option tonnages not to take are only exercised when no other shipping options are available to the operator.
Large eastern mining companies, when faced with a 10% call, may be forced to adjust their performance by 50,000 tons per month. Western operators face up to 6 million tons per month adjustment. This is neither realistic nor reasonable. 2001 performance has shown that this is an industry-wide problem and a rational contracting approach will recognize this fact.
Finally, performance under this clause may not be excused by force majeure protections. The risks to the operator are great as experienced in 2001 and the protections afforded otherwise are not available. Now that trading is a reality, perhaps the utility should assume this risk and revert to the OTC markets instead of jeopardizing the relationship with critical suppliers in a difficult producing environment.
Subject to Anti-Trust provisions, utilities should allow shippers the first right of refusal for the remarketing of coal that does not fit with their current burn-schedule. Anti-Trust rules probably discourage covenants that purport to limit the utility’s right to resale after title has transferred. However, it can be of particular moment for a distressed operator, limited in shipping ability, to have to face his own coal in the market for the remaining customer universe.
In a source contract, the supplier dedicates reserves and ships from those reserves with a right of limited substitution. Agreements typically provide an excuse for performance for Acts of God, i.e., nature not human induced, and certain other conditions beyond the control of the operator and without claimant’s fault or negligence. The party claiming force majeure develops a duty to mitigate the effects of the claim within a reasonable time and expense. If the agreement is silent on this term or the writing is ambiguous, the UCC at 2-615 provides the background rule of Commercial Impracticability to fill in the gap. Commercial Impracticability requires that a contingency exists that makes performance impracticable and that the non-occurrence of the contingency was a basic assumption on which the contract was formed.
2001 exhibited an extreme case of large-scale non-performance across the industry. Geological conditions, regulatory decrees, floods, trucking disputes, rail/barge availability, storage, lack of available mining talent and other reasons were offered for the failures. It is evident that claims of force majeure should offer protection for the party that confronted conditions beyond its control. However, it is just as clear that not all conditions reach the level of excuse. In fact, this is a factual situation that requires scrutiny. The requirement that the party claiming force majeure be without fault or negligence makes the analysis of forseeability, duty to perform and failure of that duty criticizable. Negligence analysis essentially asks the question; what would a reasonable man, under all the facts and circumstances have done in a similar situation?
Economic issues are not held to be force majeure events. Courts have narrowly interpreted this clause. Acts of God have been limited to natural disasters such as floods, tornadoes, hurricanes, fires and other such natural as opposed to human conditions. Often issues or conditions occur that are extraordinary by their very nature. This in and of itself does not make them excusable under this analysis. Are they beyond the control of the party is the question to be addressed. A coal adage is that any condition that leads to a $1.00 per ton loss is a force majeure event. Although it makes for good story telling that is not the standard. Neither can a customer with a history of 100 day inventories (historical anticipation of labor stoppages) maintain the excuse claim when inventories reach an uncomfortable financial but physically possible level. In order for the clause to provide meaningful protection it must say what it means and mean what it says.
Let me highlight a new contracting regime that deals effectively with this contractual difficulty. 2001 is the harbinger for more frequent cessation of supply and rather than contesting the force majeure or commercial impracticability clauses continuously, the parties may wish to consider the following scenario.
As opposed to source agreements the industry may move to supply agreements where coal quantity and quality is specified but the source remains open. Now that eight (8) coal companies control over 50% of the supply nationally, multi-sourcing options can work for both parties. Additionally, open transparent OTC markets for the Big Sandy, Pittsburgh and Powder River Coal provide flexibility and insurance for the continuous supply of fuel.
In order not to relive GROUNDHOG DAY 2001 suppliers and customers must recognize that the 20-year history of reliable supply faces severe challenges. In this paper I have attempted to table some of the more obvious issues that may impact upon supply going forward. Significant decreases in mineabilty and merchantability of the remaining reserves will act as a drag on earnings. It will also endanger reliable supplies of fuel for the buyer. Interruptions of demand for multi-pollutant regulations will heighten the risk for operators, investors and bankers. Failures of supply will require operators to seek the protection of force majeure increasingly. For the first time in my career we are seeing utilities assert this claim for stockpile capacity. All of this strains the financial security of the coal producers. This strain leads to fewer more expensive sources of capital, in an industry facing major recapitalization.
Who will we choose to work with? Although beyond the scope of this analysis is the question of credit in a Post Enron environment. This will become another major issue between the supplier and the customer and working out the new arrangements will be time consuming and expensive for both parties. Risk analysis will address the above-mentioned issue, as well as the others discussed in this paper in light of this changed circumstance.
What can be done to mitigate some of the worst features of this scenario?
Let the party best able to bear the risk, bear it. There are certain contractual issues that can operate to improve the performance of suppliers by offering added flexibility in the planning, mining and shipping of the product. Relaxing, if not reversing the trend of tightened contractual clauses may be the most reasonable way of assisting the supplier in his efforts to remain a reliable, low-cost supplier of choice. At best, 2001 type supply interruptions are inevitable. The thought process that goes into future contracting can set the arbitration/litigation strategies for the future. Hopefully, consumers are buying coal not lawsuits.
Although I have attempted to show non-economic ($price) issues that can impact upon the ability of the utility/supplier relationship in the new environment, I cannot leave the issue without suggesting the relaxation of tight contractual clauses and sharing (efficiencies, power line costs and revenues and fuel pricing against electricity pricing) with an eye towards partnering between supplier and consumer. Sharing, augmented with appropriate insurance coverage, may eventually be the least cost strategy for avoiding GROUNDHOG DAY everyday.