Item 2. Properties
Item 2. Properties.
Coal Reserves
We controlled an estimated 3.0 billion tons of proven and probable coal reserves as of December 31, 2020. An estimated 2.6 billion tons of our attributable proven and probable coal reserves are in the U.S., with the remainder in Australia. Approximately 2% of our U.S. proven and probable coal reserves, or 52 million tons, are metallurgical coking coal. The remainder of our U.S. coal reserves consists of thermal coal. Approximately 56% of our Australian proven and probable coal reserves, or 243 million tons, are metallurgical coal, comprised of approximately 121 million and 122 million tons of coking coal and low-volatile pulverized coal injection (LV PCI) coals, respectively. The remainder of our Australian coal reserves consists of thermal coal. We own approximately 6% of these reserves and leased property comprises the remaining 94%. Approximately 88% of our reserves, or 2.7 billion tons, are compliance coal and 12% are non-compliance coal (assuming application of the U.S. industry standard definition of compliance coal to all of our reserves). Compliance coal is defined by Phase II of the CAA as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.
Below is a table summarizing the locations and proven and probable coal reserves of our major mining segments.
Proven and Probable
Reserves as of
December 31, 2020 (1)
Owned
Tons Leased
Tons Total
Tons
Mining Segment Locations
(Tons in millions)
Seaborne Thermal Mining New South Wales — 211 211
Seaborne Metallurgical Mining Queensland, New South Wales and Alabama — 275 275
Powder River Basin Mining Wyoming — 2,223 2,223
Other U.S. Thermal Mining Illinois, Indiana, Kentucky, New Mexico and Colorado 190 149 339
Total Proven and Probable Coal Reserves
190 2,858 3,048
Total United States
190 2,424 2,614
Total Australia
— 434 434
Total Proven and Probable Coal Reserves
190 2,858 3,048
(1) Estimated proven and probable coal reserves have been adjusted to account for estimated process dilutions and losses during mining and processing involved in producing a saleable coal product.
Reserves are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:
• Proven (Measured) Reserves — Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.
• Probable (Indicated) Reserves — Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.
Our estimates of proven and probable coal reserves are established within these guidelines. Estimates within the proven category have the highest degree of assurance, while estimates within the probable category have only a moderate degree of geologic assurance. Further exploration is necessary to place probable reserves into the proven reserve category. Our active properties generally have a much higher degree of reliability because of increased drilling density.
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Our guidelines for geologic assurance surrounding estimated proven and probable U.S. and Australian coal reserves generally follow the respective industry-accepted practices of those countries. In the U.S., our estimated proven coal reserves lie within one-quarter mile of a valid point of measure or point of observation, such as exploratory drill holes or previously mined areas, while our estimated probable coal reserves may lie more than one-quarter mile, but less than three-quarters of a mile, from a point of thickness measurement. In Australia, our estimated proven coal reserves generally lie within 250 meters of a point of observation, while our estimated probable coal reserves may lie more than 250 meters, but less than 500 meters, from a point of observation. For some of our Australian coal reserves, the distance between points of observation is determined by a geostatistical study.
The preparation of our coal reserve estimates is completed in accordance with our prescribed internal control procedures, which include verification of input data into a coal reserve forecasting and economic evaluation software system, as well as multi-functional management review. Our reserve estimates are prepared by our staff of experienced geologists and engineers. Our corporate Technical Services group is responsible for tracking changes in reserve estimates, supervising our other geologists and coordinating periodic third-party reviews of our reserve estimates by qualified mining consultants.
Our coal reserve estimates are predicated on information obtained from an extensive historical database of drill holes and information obtained from our ongoing drilling program. We compile data from individual drill holes in a computerized drill-hole database from which the depth, thickness and, where core drilling is used, the quality of the coal is determined. The density of a drill pattern determines whether the related coal reserves will be classified as proven or probable. Our coal reserve estimates are then input into our computerized land management system, which overlays that geological data with data on ownership or control of the mineral and surface interests to determine the extent of our attributable coal reserves in a given area. Our land management system contains reserve information, including the quantity and quality (where available) of reserves, as well as production data, surface and coal ownership, lease payments and other information relating to our coal reserves and land holdings. We periodically update our coal reserve estimates to reflect production of coal from those reserves and new drilling or other data received. Accordingly, our coal reserve estimates will change from time to time to reflect the effects of our mining activities, analysis of new engineering and geological data, changes in coal reserve holdings, modification of mining methods and other factors.
Our estimate of the economic recoverability of our coal reserves is generally based upon a comparison of unassigned reserves to assigned reserves currently in production in the same geologic setting to determine an estimated mining cost. These estimated mining costs are compared to expected market prices for the quality of coal expected to be mined and take into consideration typical contractual sales agreements for the region and product. Where possible, we also review coal production by competitors in similar mining areas. Only coal reserves expected to be mined economically are included in our reserve estimates. Finally, our coal reserve estimates consider dilutions and losses during mining and processing for recoverability factors to estimate a saleable product. Factors impacting our assessment include geological conditions, production expectations for certain areas, the effects of regulation and taxes by governmental agencies, future price and operating cost assumptions and adverse changes in market conditions and mine closure activities. The estimates are also impacted by decreases resulting from current year production and increases resulting from information obtained from additional drilling. Our estimation as of December 31, 2020 reflected a net reduction compared to the prior year of 1.0 billion tons of coal reserves. The decrease was driven by production, changes to our estimates of economic recoverability to reflect market conditions, mine plan changes and new drilling.
We periodically engage independent mining and geological consultants and consider their input regarding the procedures used by us to prepare our internal estimates of coal reserves, selected property reserve estimates and tabulation of reserve groups according to standard classifications of reliability. Our December 31, 2020 reserve estimates for the Gateway North Mine and El Segundo Mine in the U.S. were audited by Weir International, Inc., independent mining and geological consulting firm, which included a review of the data, procedures and parameters employed by us in developing our reserve estimates. The audits found that the reserve estimates for the areas were (1) well documented, clearly and concisely reported and (2) prepared consistent with standard industry and geological practice, and in accordance with United States Geological Survey Circular 891 requirements and SEC Industry Guide 7 guidelines. We plan to complete additional audits of our reserve estimates on a cyclical basis for each of our major operating regions.
With respect to the accuracy of our coal reserve estimates, our experience is that recovered reserves are within plus or minus 10% of our proven and probable estimates, on average, and our probable estimates are generally within the same statistical degree of accuracy when the necessary drilling is completed to move reserves from the probable to the proven classification.
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For each mine or future mine, we employ a market-driven, risk adjusted capital allocation process to guide long-term mine planning of active operations and development projects for economically mineable coal. We refer to this process as Life-of-Mine (LOM) planning. The LOM plan projects, among other things, annual quantities and qualities for each coal product. The saleable product mix for a mine may include multiple thermal and metallurgical products with different targeted qualities. The expected volumes for each mine and product, as well as annual pricing forecasts for each product, developed as described below, and related cost forecasts, developed as described below, are then evaluated to determine the economically recoverable coal in the LOM plan.
Pricing
The pricing information used to establish our reserves includes internal, proprietary price forecasts and existing contract economics, in each case on a mine-by-mine and product-by-product basis. In general, our price forecasts are based on a thorough analytical process utilizing detailed supply and demand models, global economic indicators, projected foreign exchange rates, analyses of price relationships among various commodities, competing fuels analyses, projected steel demand, analyses of supplier costs and other variables. Price forecasts, supply and demand models and other key assumptions and analyses are stress tested against independent third-party research not commissioned by us to confirm the conclusions reached through our analytical processes, and our price forecasts fall within the ranges of the projections included in this third-party research. The development of the analyses, price forecasts, supply and demand models and related assumptions are subject to multiple levels of management review.
Below is a description of some of the specific factors that we evaluate in developing our price forecasts for thermal and metallurgical coal products on a mine-by-mine and product-by-product basis. Differences between the assumptions and analyses included in our price forecasts and realized factors could cause actual pricing to differ from our forecasts.
Thermal. Several factors can influence thermal coal supply and demand and pricing. Demand is sensitive to total electric power generation volumes, which are determined in part by the impact of weather on heating and cooling demand, inter-fuel competition in the electric power generation mix (such as from natural gas and renewable sources), changes in capacity (additions and retirements), competition from other producers, coal stockpiles and policy and regulations. Supply considerations impacting pricing include reserve positions, mining methods, strip ratios, production costs and capacity and the cost of new supply (greenfield developments or extensions at existing mines).
In the United States, natural gas is the most significant substitute for thermal coal for electricity generation and can be one of the largest drivers of shifts in supply and demand and pricing. The competitiveness of natural gas as a generation fuel source has been strengthened by accelerated growth in domestic natural gas production, new natural gas combined cycle generation capacity and comparatively low natural gas prices versus historic levels. The build out of renewable generation and subsidized power can also be a key driver of power market pricing and hence coal prices.
Internationally, thermal coal-fueled generation also competes with alternative forms of electricity generation. The competitiveness and availability of generation fueled by natural gas, oil, nuclear, hydro, wind, solar and biomass vary by country and region and can have a meaningful impact on coal pricing. Policy and regulations, which vary from country to country, can also influence prices. In addition, seaborne thermal coal import demand can be significantly impacted by the availability of domestic coal production, particularly in the two leading coal import countries, China and India, and the competitiveness of seaborne supply from leading thermal coal exporting countries, including Indonesia, Australia, Russia, Colombia, the U.S. and South Africa, among others.
Metallurgical. Several factors can influence metallurgical coal supply and demand and pricing. Demand is impacted by economic conditions, government policies and demand for steel, and is also impacted by competing technologies used to make steel, some of which do not use coal as a manufacturing input. Competition from other types of coal is also a key price consideration and can be impacted by coal quality and characteristics, delivered energy cost (including transportation costs), customer service and support and reliability of supply.
Seaborne metallurgical coal import demand can be significantly impacted by the availability of domestic coal production, particularly in leading metallurgical coal import countries such as China, among others, as well as country-specific policies restricting or promoting domestic supply. The competitiveness of seaborne metallurgical coal supply from leading metallurgical coal exporting countries of Australia, the U.S., Russia, Canada, Mongolia and Mozambique, among others, is also an important price consideration.
In addition to the factors noted above, the prices which may be obtained at each individual mine or future mine can be impacted by factors such as (i) the mine’s location, which impacts the total delivered energy costs to its customers, (ii) quality characteristics, particularly if they are unique relative to competing mines, (iii) assumed transportation costs and (iv) other mine costs that are contractually passed on to customers in certain commercial relationships.
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Costs
The cost estimates we use to establish our reserves are generally estimated according to internal processes that project future costs based on historical costs and expected trends. The estimated costs normally include mining, processing, transportation, royalty, add-on tax and other mining-related costs. Our estimated mining and processing costs reflect projected changes in prices of consumable commodities (mainly diesel fuel, explosives and steel), labor costs, geological and mining conditions, targeted product qualities and other mining-related costs. Estimates for other sales-related costs (mainly transportation, royalty and add-on tax) are based on contractual prices or fixed rates. Specific factors that may impact the cost at our various operations include:
• Geological settings . The geological characteristics of each mine are among the most important factors that determine the mining cost. Our geology department conducts the exploration program and provides geological models for the LOM process. Coal seam depth, thickness, dipping angle, partings and quality constrain the available mining methods and size of operations. Shallow coal is typically mined by surface mining methods by which the primary cost is overburden removal. Deep coal is typically mined by underground mining methods where the primary costs include coal extraction, conveyance and roof control.
• Scale of operations and the equipment sizes . For surface mines, our dragline systems generally have a lower unit cost than truck-and-shovel systems for overburden removal. The longwall operations generally are more cost effective than room-and-pillar operations for underground mines.
• Commodity prices . For surface mines, the costs of diesel fuel and explosives are major components of the total mining cost. For underground mines, the steel used for roof bolts represents a significant cost. Forecasted commodity prices are used to project those costs in the financial models we use to establish our reserves.
• Target product quality . By targeting a premium quality product, our mining and processing processes may experience more coal losses. By lowering product quality the coal losses can be minimized and therefore a lower cost per ton can be achieved. In our mine plans, the product qualities are estimated to correspond to existing contracts and forecasted market demands.
• Transportation costs . Transportation costs vary by region. Most of our U.S. thermal operations sell coal at mine loadouts. Therefore, no transportation expenses are included in our U.S. thermal cost estimates. Our seaborne operations typically sell coal at designated ports. The estimated costs for our seaborne operations include rail and barge transportation and related fees at ports.
• Royalty costs . Our royalty costs are based upon contractual agreements for the coal leased from governments or private owners. The royalty rates for coal leased from governments differ by country and, in some cases, by mining method. Estimated add-on taxes and other sales-related costs are determined according to government regulations or historical costs.
• Exchange rates . Costs related to our Australian production are predominantly denominated in Australian dollars, while the Australian coal that we export is sold in U.S. dollars. As a result, Australian/U.S. dollar exchange rates impact the U.S. dollar cost of Australian production.
Based on our mine-by-mine and product-by-product evaluations of the estimated prices for our coal, and the costs and expenses of mining and selling our coal, we have concluded our reserves were economically recoverable as of December 31, 2020.
On October 31, 2018, the SEC voted to adopt amendments to modernize the property disclosure requirements for mining registrants and related guidance under the Securities Act of 1933 and the Securities Exchange Act of 1934. The final rules provide a three-year transition period, thus, we will be required to begin to comply with the new rules for the fiscal year beginning on January 1, 2021 (reported in the Annual Report on Form 10-K for the year ended December 31, 2021). We are in the process of assessing the impact the new rules will have on our disclosures.
We have numerous U.S. federal coal leases that are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover our principal reserves in the Powder River Basin and other reserves in Alabama, Colorado and New Mexico. Each of these leases continues indefinitely, provided there is diligent development of the property and continued operation of the related mine or mines. The U.S. Bureau of Land Management (BLM) has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at 10-year intervals thereafter. Annual rents on surface land under our federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The U.S. federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2020, we leased 1,610 acres of federal land in Alabama, 3,480 acres in Colorado, 640 acres in New Mexico and 38,915 acres in Wyoming, for a total of 44,645 acres nationwide subject to those limitations.
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Similar provisions govern three coal leases with the Navajo and Hopi Indian tribes. These leases cover coal contained in 64,783 acres of land in northern Arizona lying within the boundaries of the Navajo Nation and Hopi Indian reservations. We also lease coal-mining properties from various state governments in the U.S.
Private U.S. coal leases normally have terms of between 10 and 20 years and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private U.S. leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many U.S. leases also require payment of a lease bonus or minimum royalty, payable either at the time of execution of the lease or in periodic installments. The terms of our private U.S. leases are normally extended by active production at or near the end of the lease term. U.S. leases containing undeveloped reserves may expire or these leases may be renewed periodically.
Mining and exploration in Australia is generally carried out under leases or licenses granted by state governments. Mining leases are typically for an initial term of up to 21 years (but which may be renewed) and contain conditions relating to such matters as minimum annual expenditures, restoration and rehabilitation. Royalties are paid to the state government as a percentage of the sales price. Generally, landowners do not own the mineral rights or have the ability to grant rights to mine those minerals. These rights are retained by state governments. Compensation is payable to landowners for loss of access to the land, and the amount of compensation can be determined by agreement or court process. Surface rights are typically acquired directly from landowners through agreement or court determination, subject to some exceptions.
Consistent with industry practice, we conduct only limited investigation of title to our coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased properties are not completely verified until we prepare to mine those reserves.
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The following charts provide a summary, by mining complex, of production (in descending order by mining segment) for the years ended December 31, 2020, 2019 and 2018, tonnage of coal reserves that are assigned to our active operating mines, our property interest in those reserves and other characteristics of the facilities.
SUMMARY OF COAL PRODUCTION AND SULFUR CONTENT OF ASSIGNED RESERVES
(Tons in millions)
Sulfur Content of Assigned Reserves as of December 31, 2020 (1)
<1.2 lbs. >1.2 to 2.5 lbs. >2.5 lbs. As
Production Sulfur Sulfur Sulfur Received
Year Ended December 31, Type of Dioxide per Dioxide per Dioxide per Btu per
Segment/Mining Complex 2020 2019 2018 Coal Million Btu Million Btu Million Btu pound (2)
Seaborne Thermal Mining:
Wilpinjong 14.2 14.1 14.1 T 93 — — 10,000
Wambo (3)
5.5 5.6 5.2 T/C 118 — — 11,300
Total 19.7 19.7 19.3 211 — —
Seaborne Metallurgical Mining:
Coppabella 2.2 2.4 2.7 P 22 — — 12,600
Moorvale 1.2 1.7 2.1 C/P/T 6 — — 12,500
Metropolitan 1.0 1.5 1.7 C/P/T 16 — — 12,600
Shoal Creek 0.6 1.9 0.2 C 52 — — 12,700
Millennium (4)
0.1 0.6 1.9 C/P — — — —
North Goonyella — — 1.4 C 69 — — 12,700
Middlemount (5)
— — — C/P 20 — — 12,400
Total 5.1 8.1 10.0 185 — —
Powder River Basin Mining:
North Antelope Rochelle 66.1 85.3 98.3 T 1,546 — — 8,800
Caballo 11.6 12.6 11.3 T 435 6 — 8,400
Rawhide 9.5 10.1 9.5 T 192 44 — 8,300
Total 87.2 108.0 119.1 2,173 50 —
Other U.S. Thermal Mining:
Bear Run 5.2 6.8 6.9 T 4 25 201 10,900
El Segundo/Lee Ranch 4.6 5.5 5.5 T 1 19 4 9,100
Wild Boar 2.0 2.5 2.7 T — — 27 11,100
Gateway North 1.8 3.0 3.1 T — — 46 10,900
Francisco Underground 1.6 2.0 2.2 T — — 8 11,370
Twentymile 1.2 2.6 3.1 T 4 — — 11,200
Somerville Central (6)
0.4 1.2 2.0 T — — — 11,000
Kayenta (7)
— 3.8 6.5 T — — — —
Wildcat Hills Underground (8)
— 1.4 1.3 T — — — —
Cottage Grove (9)
— 0.1 0.4 T — — — —
Total 16.8 28.9 33.7 9 44 286
Total Assigned 128.8 164.7 182.1 2,578 94 286
T: Thermal
C: Coking
P: Pulverized Coal Injection Metallurgical
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ASSIGNED RESERVES (10)
AS OF DECEMBER 31, 2020
(Tons in millions)
Attributable Ownership 100% Project Basis Modifying Factors (11)
Proven and Probable Reserves Proven and Probable Reserves
Segment/Mining Complex Interest Owned Leased Surface Underground Owned Leased Surface Underground ROM Factor Yield
Seaborne Thermal Mining:
Wilpinjong 100% 93 — 93 93 — 93 — 93 93 — 104 % 86 %
Wambo (3)
(a) 118 — 118 33 85 151 — 151 66 85 100 % 74 %
Total 211 — 211 126 85
Seaborne Metallurgical Mining:
Coppabella 73.3% 22 — 22 22 — 30 — 30 30 — 92 % 78 %
Moorvale 73.3% 6 — 6 6 — 8 — 8 8 — 107 % 79 %
Metropolitan 100% 16 — 16 — 16 16 — 16 — 16 109 % 84 %
Shoal Creek 100% 52 — 52 — 52 52 — 52 — 52 102 % 56 %
North Goonyella 100% 69 — 69 — 69 69 — 69 — 69 105 % 82 %
Middlemount (5)
50% 20 — 20 20 — 40 — 40 40 — 86 % 77 %
Total 185 — 185 48 137
Powder River Basin Mining:
North Antelope Rochelle 100% 1,546 — 1,546 1,546 — 1,546 — 1,546 1,546 — 92 % 100 %
Caballo 100% 441 — 441 441 — 441 — 441 441 — 90 % 100 %
Rawhide 100% 236 — 236 236 — 236 — 236 236 — 93 % 100 %
Total 2,223 — 2,223 2,223 —
Other U.S. Thermal Mining:
Bear Run 100% 230 108 122 230 — 230 108 122 230 — 106 % 72 %
El Segundo/Lee Ranch 100% 24 23 1 24 — 24 23 1 24 — 87 % 100 %
Wild Boar 100% 27 11 16 27 — 27 11 16 27 — 107 % 76 %
Gateway North 100% 46 44 2 — 46 46 44 2 — 46 64 % 62 %
Francisco Underground 100% 8 2 6 — 8 8 2 6 — 8 64 % 64 %
Twentymile 100% 4 2 2 — 4 4 2 2 — 4 117 % 67 %
Total 339 190 149 281 58
Total Assigned 2,958 190 2,768 2,678 280
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ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES (10)
AS OF DECEMBER 31, 2020
(Tons in millions)
Attributable Ownership 100% Project Basis
Proven and Proven and
Total Tons Probable Total Tons Probable
Coal Seam Location Assigned Unassigned Reserves Proven Probable Assigned Unassigned Reserves Proven Probable
Seaborne Thermal Mining (New South Wales) 211 — 211 146 65 244 — 244 176 68
Seaborne Metallurgical Mining:
Alabama 52 — 52 51 1 52 — 52 51 1
New South Wales 16 — 16 2 14 16 — 16 2 14
Queensland 117 90 207 168 39 147 120 267 212 55
Total 185 90 275 221 54
Powder River Basin Mining (Wyoming) 2,223 — 2,223 2,108 115 2,223 — 2,223 2,108 115
Other U.S. Thermal Mining:
Illinois 46 — 46 15 31 46 — 46 15 31
Indiana 265 — 265 195 70 265 — 265 195 70
New Mexico 24 — 24 24 — 24 — 24 24 —
Colorado 4 — 4 4 — 4 — 4 4 —
Total 339 — 339 238 101
Total Proven and Probable 2,958 90 3,048 2,713 335
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ASSIGNED AND UNASSIGNED - RESERVE CONTROL AND MINING METHOD
AS OF DECEMBER 31, 2020
(Tons in millions)
Attributable Ownership 100% Project Basis
Reserve Control Mining Method Reserve Control Mining Method
Coal Seam Location Owned Leased Surface Underground Owned Leased Surface Underground
Seaborne Thermal Mining (New South Wales) — 211 126 85 — 244 159 85
Seaborne Metallurgical Mining:
Alabama — 52 — 52 — 52 — 52
New South Wales — 16 — 16 — 16 — 16
Queensland — 207 54 153 — 267 85 182
Total — 275 54 221
Powder River Basin Mining (Wyoming) — 2,223 2,223 — — 2,223 2,223 —
Other U.S. Thermal Mining:
Illinois 44 2 — 46 44 2 — 46
Indiana 121 144 257 8 121 144 257 8
New Mexico 23 1 24 — 23 1 24 —
Colorado 2 2 — 4 2 2 — 4
Total 190 149 281 58
Total Proven and Probable 190 2,858 2,684 364
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ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES - SULFUR CONTENT
AS OF DECEMBER 31, 2020
(Tons in millions)
Attributable Ownership 100% Project Basis
Sulfur Content (1)
Sulfur Content (1)
<1.2 lbs. >1.2 to 2.5 lbs. >2.5 lbs. <1.2 lbs. >1.2 to 2.5 lbs. >2.5 lbs. As
Sulfur Dioxide Sulfur Dioxide Sulfur Dioxide Sulfur Dioxide Sulfur Dioxide Sulfur Dioxide Received
Type of per per per per per per Btu
Coal Seam Location Coal Million Btu Million Btu Million Btu Million Btu Million Btu Million Btu per Pound (2)
Seaborne Thermal Mining (New South Wales) T/C 211 — — 244 — — 10,700
Seaborne Metallurgical Mining:
Alabama C 52 — — 52 — — 12,700
New South Wales C/P/T 16 — — 16 — — 12,600
Queensland C/P/T 207 — — 267 — — 12,400
Total 275 — —
Powder River Basin Mining (Wyoming) T 2,173 50 — 2,173 50 — 8,700
Other U.S. Thermal Mining:
Illinois T — — 46 — — 46 10,800
Indiana T 4 25 236 4 25 236 11,000
New Mexico T 1 19 4 1 19 4 9,150
Colorado T 4 — — 4 — — 11,200
Total 9 44 286
Total Proven and Probable 2,668 94 286
T: Thermal
C: Coking
P: Pulverized Coal Injection Metallurgical
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(1) Compliance coal is defined by Phase II of the CAA as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Non-compliance coal is defined as coal having sulfur dioxide content in excess of this standard. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.
(2) As-received Btu per pound includes the weight of moisture in the coal on an as-sold basis. The range of variability of the moisture content in coal across a given region may affect the actual shipped Btu content of current production from assigned reserves.
(3) Includes the Wambo Open-Cut Mine and the Wambo Underground Mine areas.
(4) The Company’s Millennium Mine ceased production in March 2020, with sales continuing throughout May 2020.
(5) Represents our 50% interest in Middlemount, which owns the Middlemount Mine in Queensland, Australia. Because that entity is accounted for as an unconsolidated equity affiliate, 2020, 2019 and 2018 tons produced by Middlemount have been excluded from the “Summary of Coal Production and Sulfur Content of Assigned Reserves” table. Middlemount produced 3.2 million tons, 2.9 million tons, and 4.2 million tons of coal in 2020, 2019 and 2018, respectively (on a 100% basis).
(6) The Company’s Somerville Central Mine ceased production in December 2020, with sales continuing into January 2021.
(7) The Company’s Kayenta Mine closed during August 2019 upon termination of its coal supply agreement with the Navajo Generating Station in Arizona.
(8) The Company’s Wildcat Hills Underground Mine ceased production in December 2019, with sales continuing throughout April 2020.
(9) The Company’s Cottage Grove Mine ceased production in May 2019, with sales continuing throughout July 2019.
(10) Assigned reserves represent recoverable coal reserves that are controlled and accessible at active operations as of December 31, 2020. Unassigned reserves represent coal at currently non-producing locations that would require significant new mine development, mining equipment or plant facilities before operations could begin on the property.
(11) The modifying factors reflect the assumptions which are utilized to convert coal quantities and qualities as in ground to run of mine (ROM) coal after mining, and eventually to saleable product coal after processing. Coal reserves are reported as an estimation of the final saleable quantity, which takes into account any losses and dilutions during mining and processing. We generally keep track of coal reserves through in place coal, ROM coal and product coal. In place coal for U.S. underground reserves excludes planned barrier pillars, but includes regular pillars from projected underground extractions. In place coal for Australian underground reserves is exclusive of all planned pillars. The difference is due to historic practice and software used by each country. The ROM factor represents the estimated ROM coal in relation to the coal in place with considerations of coal losses, dilutions and remaining pillars during mining processes. The yield is the ratio of estimated saleable product coal over ROM coal tons with mainly processing loss considered.
a. In December 2019, after receiving the requisite regulatory and permitting approvals, the Company formed an unincorporated joint venture with Glencore, in which the Company holds a 50% interest, to combine the existing operations of the Company’s Wambo Open-Cut Mine in Australia with the adjacent coal reserves of Glencore’s United Mine. The Wambo Open-Cut reserve is estimated for our 50% interest in United Wambo Joint Venture.