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Energy Intensive Industry for Alaska Volume 1 1978
Energy Intensive Industry for Alaska Volume |: Alaskan Cost Factors Market Factors Survey of Energy Intensive Industries September 1978 Prepared for Alaska Division of Energy and Power Development and the U.S. Department of Energy under Contract 300A 01123 Institute of Social and Economic Research, University of Alaska Pacific Northwest Laboratory Operated for the U.S. Department of Energy by Memorial Institute PROPERTY OF: Alaska Power Authority 334 W. 5th Ave. Anchorage. Alaska 99501 NOTICE OF assumes any legal liability or responsibi tus, product or process disclosed, or The views, of ne contractor and do not necessarily re; tment of Energy. FINAL REPORT ENERGY INTENSIVE INDUSTRY FOR ALASKA VOLUME I ALASKAN COST FACTORS MARKET FACTORS SURVEY OF ENERGY INTENSIVE INDUSTRIES W. H. Swift J. J. Jacobsen M. Clement T. B. Powers E. G. Baker C. A. Rohrmann D. C. Elliot G. L. Schiefelbein September 1978 Prepared for the Alaska Division of Energy and Power Development, Department of Commerce and Economic Development, and the Department of Energy under Contract 300A 01123 Pacific Northwest Laboratory Richland, Washington 99352 CONTENTS INTRODUCTION EXECUTIVE SUMMARY 2.1 ALASKAN LABOR COSTS a 2.2 ALASKAN ENERGY AND CAPITAL COSTS . 2.3 ENERGY INTENSIVE INDUSTRIES 2.4 TIMING. SCOPE OF WORK . ALASKA ENERGY COSTS AND AVAILABILITY 4.1 OIL COSTS AND AVAILABILITY . 4.2 NATURAL GAS COST AND AVAILABILIITY 4.3 COAL COSTS AND AVAILABILITY 4.4 ELECTRIC POWER . Soe eee 4.5 SUMMARY OF ENERGY COSTS IN ALASKA CONTIGUOUS STATES ENERGY COSTS AND AVAILABILITY 5.1 OIL COSTS AND AVAILABILITY . 5.2 NATURAL GAS PRICE AND AVAILABILITY 5.3 COAL PRICE AND AVAILABILITY 5.4 ELECTRIC POWER COSTS AND AVAILABILITY ALASKAN CONSTRUCTION AND CAPITAL COSTS ANALYSIS OF ALASKAN LABOR COSTS AND ESTIMATION OF WAGE DIFFERENTIAL BY INDUSTRY . 7.1 INTRODUCTION 7.2 OBJECTIVE ee eee ses 7.3 IDENTIFICATION OF WAGE DIFFERENCES ECONOMIC FACTORS OF PRODUCTION AND MARKETS FOR ALASKA'S ENERGY INTENSIVE INDUSTRIES dag > oa a _ PP LHP LHP HL ym NY LY ananan ale a0 a9) ap oo 8.1 ECONOMIC FACTORS OF PRODUCTION . 8.2 THE ALUMINUM INDUSTRY AND JAPANESE MARKETS . 9.0 ENERGY INTENSIVE INDUSTRY SCREENING AND EVALUATION . INTRODUCTION . THE ALUMINUM METAL INDUSTRY . CEMENT INDUSTRY . 9.1 Or es) 9.4 CHLOR-ALKALI INDUSTRY . 9.5 LIME INDUSTRY 9.6 METHANOL FROM COAL . 9.7 PETROLEUM REFINING . eau iaeelalesiales 9.8 PETROCHEMICALS AND AGRICHEMICALS FROM NORTH APPENDIX A . APPENDIX B . SLOPE NATURAL GAS iv oO =i) ay BA) 34 03 -62 oO ono wo oOo oO oO 9.75 A-1 B-1 THE POTENTIAL FOR ENERGY INTENSIVE INDUSTRIAL DEVELOPMENT IN ALASKA: PHASE II, III: FACTORS EXTERNAL TO ALASKA Prepared for the Division of Energy and Power Development Department of Commerce and Economic Development and the Department of Energy by Pacific Northwest Laboratory Operated by Battelle Memorial Institute March 1978 1.0 INTRODUCTION This report is addressed to the relationship of the State of Alaska's indigenous energy and other natural resources and the role they may play in the future economic development of the State. Alaska is popularly and frequently referred to as the “energy ware- house" of the United States. This public awareness derives primarily from the current activity surrounding the development of oi] and natural gas resources on the North Slope and the expectation that additional reserves will be found in other locations. The availability of very major coal (largely subbituminous) reserves is less well known but well recog- nized by natural resource authorities. The hydroelectric power potential, also very large, is in the same category--known to people knowledgeable on Alaska but less well recognized by the public at large. 1.1 Alaska is also popularly regarded as a "warehouse" of other mineral resources, principally metallic, which could be exploited. On the other hand, the State is regarded by many as a largely untouched wilderness with regions of great natural beauty that deserve preservation in their own right. The term "warehouse," though widely used in reference to Alaska, is however largely a misnomer. Very few of tne energy or non-energy resources have been developed to the point where they are “available on pallets" in the usual warehouse connotation. The sole notable excep- tions are the oi] and gas resources of the Cook Inlet Basin and the North Slope and, earlier, the placer and hard rock gold and other metal mining activities now largely dormant. In fact, much of the information avail- able on geologic resources is at best reconnaissance grade being based largely on surface observations and inferences. As a result the resources are poorly understood. Similarly, the hydroelectric power resources of Alaska have been developed to probably far less than one percent of the ultimate uncon- strained potential. Renewable natural resources such as forest products, also very large, have similarly not been developed primarily due to institutional constraints, higher costs, transportation to the domestic market and the near market availability of lower cost sources in the Lower 48. Although far from "energy intensive," the fisheries resource of Alaska's Continental Shelf is immense and, under newly established international agreements relating to the 200 mile economic zone, may become a very significant factor in Alaska's economic development. This would be over and above the significant contribution the fisheries industry already makes to the State's economy. Assuming that the State wishes to encourage development of stable noncyclical industry, a natural first question is: Can Alaska's energy resources and other endowments be coupled in ways that bring the desired lire economic development? Subsidiary questions relate to the benefits (stable employment opportunities, reduction in the cost of living, increased state revenues, etc.) and costs (environmental impacts, in- creased need for public services, etc.). The question of industrial development, however oriented and regard- less of location, is largely one of economics. Industries will choose to locate in a manner to maximize their long-term return on investment and judge one location vs an alternative on this basis. In all location decisions, comparisons are made to at least the economics of one or more alternative locations. The use of the term "economics" above is not intended to imply simply accounting of simplistic costs of production (principally raw materials, energy, labor, and financing costs) and costs of marketing. The industry decision-maker will also include in his or her analysis a review of many factors that are less quantifiable. These factors include perceptions of stability and skills of the labor force, unionization, hospitality of the candidate locations toward industry entry, extent of competition in transportation outlets for products, and actions by competitive interests. All of these factors ultimately have their economic content. For any development to take place it must pass a number of economic tests. In short, an Alaskan development must compete with other locales (an international perspective is important for a number of industries) for attraction of a desired industry. The major considerations for industrial location in Alaska are as follows: 1) Competitive position of a given product produced in Alaska in its marketplace. Since Alaska's population is relatively low, it does not in itself constitute a major market, particularly for inter- mediate products. Thus products produced in Alaska from Alaskan materials in most instances must bear the burden of transportation 1.3 costs to the domestic or Pacific Rim markets such as Korea, Japan, and Taiwan. 2) Capital costs for industrial plants constructed in Alaska are signi- ficantly higher than in the contiguous states (11.5 fold) in part due to transportation costs associated with importing materials and in part to the higher costs of field construction in the State. These costs are even higher when compared to similar costs in most Asian countries. 3) Operating costs, both labor and material components, are recognized as being considerably higher. 4) Plant scale is becoming an increasingly important factor in modern industrial development. In most industries, new developments are currently taking place usually with "world scale" plants. Product transportation costs have become a smaller component in the final price and geographically larger markets can accommodate the entry of the larger plants with their attendant economies of scale. The above four conditions present significant problems to be over- come for successful industrial location in Alaska and are undoubtedly the primary reasons for the current sparceness of nonservice industrial development within the State. Energy intensive or related industries that have developed to date include small scale petroleum refining and the world scale agrichemical ammonia and urea operations at Kenai. The former industry is at a scale necessary to meet instate market needs where its competitive position is favored by the cost of importing petroleum products and the proximity and hence lower cost of feedstocks. The latter industry is the largest ammonia/urea installation on the West Coast. In this instance the Collier Carbon and Chemical Company plant's competitiveness is based principally upon the availability of very low cost (typically $0.17 per MMBTU) natural gas from the Cook Inlet Basin. 1.4 This low cost feed stock situation is to some extent unique in that natural gas was discovered in the course of search for crude oil. With the (then) lack of transportation systems to major markets, where it could demand a much higher price, the Cook Inlet natural gas became almost a nuisance product in a buyer's market. The low feed stock costs under long-term contracts allow the Alaskan ammonia/urea industry to compete in the West Coast and international market despite higher product trans- portation costs. With the advent of natural gas transportation systems (NLG in this instance), an outlet for the Cook Inlet natural gas is now available into markets where it can command a far higher price. As a consequence of this improved marketability, Cook Inlet gas now sells for $0.50 per MMBTU as feed for a natural gas liquefaction plant and is competitively exported to Japan. Thus a producer long-term contract price approxi- mately threefold above that for the ammonia/urea operation is obtained as the result of access to new markets. It is expected that this price effect will continue at even stronger levels in the future. New contracts for old gas (regulated) will likely be in the $1.50 per MMBTU range new gas approaching $2.00 per MMBTU and escalating. The net result is that the competitive situation is altered to the detriment of a new Alaskan ammonia/urea or similar petrochemical venture although not necessarily to the point of totally removing the competitive edge. However, it must be recognized that fuel or feedstock costs from alternative sources, e.g., the continguous states, have also risen and will continue to do so. Another factor that will have strong bearing on the future of energy intensive or related industries, regardless of location, is national energy policy currently evolving. Current federal government interven- tion into energy affairs is pervasive to say the least with most signs pointing to increased rather than decreased distortion of normal market 1.5 functioning. The effects of this intervention are both direct (taxes, price regulation, prohibitions, or certain uses, etc.) and indirect, the latter arising principally from uncertainty. Whereas normally function- ing market can be fairly well forecasted as a basis for business decisions, future nonmarket or institutional factors such as price regulation are far less predictable. Uncertainty is the bane of business decision mak- ing--the higher the uncertainty, obviously the greater tendency to defer decisions committing financial resources to projects with a high degree of exposure to risk or regulatory intervention. The current so-called "surplus" of crude oi] on the West Coast despite rising foreign imports is perhaps a good example of the conse- quences of the uncertainty factor and is particularly germane to Alaska. Even knowing that Alaskan North Slope crude 011 would become available on the West Coast in mid-1977 and could be used to reduce foreign oi] imports (a clear national objective), refiners deferred capital projects necessary for allowing Alaskan crude to displace foreign imports. As a consequence the West Coast "surplus" is more accurately described as a "shortage" of appropriate refinery capacity brought about by regulation, in this case primarily due to imposition of more stringent fuel sulfur standards for environmental reasons. The more direct effects of national energy policy on industrial development will be immense regardless of location. The national policy is understandably directed toward solution of a set of perceived prob- lems on a lumped-together national basis. The primary real national problem is, of course, the growing dependency upon imported energy with all tne national security and balance of payments issues associated therewith. The lumping-together process may however result in regional diseconomies and particularly so in Alaska given its resource base and geographic isolation. As a potential area for industrial location, Alaska has both advantages and disadvantages. The advantages include: 1.6 e Very large energy reserves and resources e Low cost transportation to Asian markets e Very large raw material resource base e Land availability e A new industrial plant would be the most modern and efficient e Significant capital availability for new ventures e Outlook for declining energy costs relative to other domestic locations e Apparent hospitality toward industry The disadvantages include: e Higher plant capital and labor costs e@ Limited local market and remoteness from major domestic markets e Limited intrastate transportation systems e Uncertain land and related resources status All things considered, it appears that the major inhibitions to industrial locations in Alaska relate primarily to the relatively higher costs of doing business in the State. Thus any action the State can take to reduce this cost will be beneficial, including the successive attraction of basic industries that on their own will reduce costs of construction and ultimately lower the cost of living and the adverse labor cost differential. Tey eal 2.0 EXECUTIVE SUMMARY ALASKAN LABOR COSTS An average Alaskan employee has earned 130% to 140% more than the average employee working in the remainder of the U.S. during the 1965 to 1973 time period. The Alaskan wage differential became even greater during the TAPS pipeline construction era and increased to 175% of the national average. Prior to the construction of the pipeline, Alaskan labor costs were increasing at a slower rate than the national average. The result was that the Alaskan wage differential as compared to the nation was diminishing and Alaskan employees were becoming relatively less costly as compared to the national average. The local inflation driven by construction of pipeline has apparently caused a change in the past trend and more recently the Alaskan wage differential increased. The State should concentrate on attracting industries which are the more efficient with respect to labor; i.e., a large ratio of output (in dollars) per employee. This will minimize the unit cost of labor per unit of output. Plants locating in Alaska should have access to the latest technology. Most new technology is very efficient in terms of labor requirements. Alaskan labor costs should then be at least partially offset by the latest technology. The Alaskan wage differential relative to the national average wage should diminish again as the Alaskan economy readjusts from the pipeline boom economy. The differential should also become less as the Alaskan economy matures and becomes somewhat more self- sufficient. 2.1 ase 2.3 ALASKAN ENERGY AND CAPITAL COSTS Both residual fuel oi] and new natural gas is estimated to cost about $2.50 per MMBTU during the 1985-2000 time period (January 1, 1977 dollars). Beluga coal is estimated to cost about $0.85 per MMBTU at the mine mouth and $1.00 per MMBTU at the Coast (January 1, 1977 dollars). Healy coal is estimated to cost $0.70 per MMBTU FOB Healy. Rail- road transportation would increase the cost to $0.90 per MMBTU delivered to Nenana and $1.10 per MMBTU delivered to Anchorage (January 1, 1977 dollars). Prices of fossil fuels can be expected to increase at a rate about 2 to 3% faster than the rate of general inflation over the long term (20-30 years). Capital or construction costs for industrial facilities for various locations in Alaska relative to costs in the Pacific Northwest are estimated to be: Anchorage 1.65 times higher Beluga 1.80 times higher Healy/Nenana 2.20 times higher Fairbanks 2.00 times higher ENERGY INTENSIVE INDUSTRIES The presence of large energy resources in Alaska will not in itself attract industry to them until such time as the costs of energy in Alaska are lower than in alternative industry locations. This reduction must be enough so as to reduce the disadvantages of higher construction, labor, and marketing costs. The above situation appears to be the case vis-a-vis Japan and although the average cost of energy in the contiguous states is lower than in Alaska, the gap is expected to narrow in the future. 2.2 This will come about as a result of phased deregulation of new natural gas, the decline in production of regulated gas, and pos- sibly the institution of import fees on imported foreign oil. e@ The industries that will tend to locate in Alaska as a result of energy considerations can be characterized by the following attributes: 1) Product is produced in large volumes in large facilities and readily shipped in bulk. 2) Energy as a factor of production represents a large frac- tion of the total cost of production. 3) Labor cost should be low, i.e., the industry must be capable of a high degree of automation and employ continuous as opposed to batch processes. 4) The industry should be a primary industry, i.e., not dependent upon having to import intermediate materials and components and should produce a slate of products that can be directly marketed. 5) A substantial market for the products should exist in foreign countries such as Japan where energy costs are high and where product shipment under foreign flag is possible. e@ The energy intensive industries meeting the above criteria are, in order of merit: 1. Lime 5. Carbon Black 2. Aluminum 6. Ammonia 3. Portland Cement 7. Chlorine 4. Methanol 2.3 Industrialization has historically been a gradual process in frontier areas and generally has followed a course initiated by industries that will have a substantial local market, i.e., construction mater- jals such as lime and Portland cement. Provision of these pro- ducts in turn reduce the cost of living and doing business and thus increase the attractiveness of the location to other following industries. © The Japanese markets for energy intensive products appear to be particularly attractive to Alaskan industries vis-a-vis domestic "Lower 48" market. This condition arises from several considera- tions: 1) Japan is almost totally dependent upon imported foreign energy, principally oil from Saudi Arabia. The landed price (Yokohoma) is approximately $13.27/bb] or $2.29/MM Btu. Conversely, the U.S. domestic prices for energy are regulated (both natural gas and o0i1) at considerably below the world price. For example, the average (weighted foreign and domestic) refinery acquisition cost of crude oil has run at about $11.98/bb1 or $2.06/mm Btu. An even stronger disparity exists for natural gas where recent interstate sales contracts have ranged in the $1.36 to $1.67/mm Btu. Domestic coal prices have recently (June 1977) ranged from $0.47 to $1.14/mm Btu for the Mountain and South Atlantic states respectively. The corresponding national average coal price in June 1977 was $0.993/mm Btu. Thus based simply on fossil energy costs alone, the "Lower 48" will tend to "shut out" energy intensive Alaskan products. It should be noted that the above situation could change rather significantly in future years as a result of federal regulation. Imposition of a crude oi] import tariff of say $3.00/bb1 ($0.52/mm Btu) would be significant as would the 2.4 phased deregulation of new natural gas. Thus, the com- petitive position of Alaska vis-a-vis the Lower 48 can be expected to increase with time. 2) Industrial production in Alaska can be marketed in Japan using foreign flag vessels at about 1/3 the cost of trans- portation to the outside domestic market. Under the Jones Act, interstate commerce must move in U.S. registry vessels at an approximately fourfold higher unit cost. 3) Due to the imbalance of trade, Japan had a $7.3 billion surplus in 1977. This surplus is creating severe strains in the foreign currency exchange providing inducement to purchase U.S. products. 4) The cost of land in Japan suitable for industrial siting is currently in the range of $million/acre. This factor among others is contributing to development of industries that are labor intensive as opposed to energy intensive as the latter typically also require relative large acreage. e Cement and Cement Products. One aspect of the cement and cement products industry relates to Japan. Currently, the Japanese cement industry, though highly energy efficient, is in a state of over- capacity as a result of intense competition from the lower labor costs in Korea and Taiwan. Given the very major demands for cement for the potential Upper Susitna hydroelectric projects, the possi- bility for moving an existing Japanese cement plant to Alaska should be explored further. A 300,000 ton/year cement plant (valued in the Lower 48 at $30 to $40 million) might be moved to Alaska for on the order of $3 to $4 million. The $2 billion Upper Susitna pro- ject beina studied assumed an import of cement from the lower 48 and considerable savings might accrue from local production. Construc- tion of the Watana dam is expected to require approximately 26,000 tons per year during a 3-year period. 2.5 In addition, the contiguous Pacific Northwest states and British Columbia is, and is expected to remain, a cement deficit region. Some export of cement from Alaska to the domestic market might well be possible. Petrochemical Industry. A preliminary analysis indicates that the economics of locating a petrochemical/agrichemical complex adjacent to the North Slope natural gas pipeline, in interior Alaska, are not promissing. The hign cost of construction in inland Alaska, plus the cost of shipping the products to the domestic market appears to make the operation of such a complex unprofitable in today's market place, irregardless of feedstock costs. For comparative purposes the economics of the chemical complex in Alaska were compared to a similar complex, operating with naphtha feedstock, on the Gulf Coast. The Gulf Coast opera- tion appeared to have an economic advantage for all products. Petroleum Refining. Since the introduction of Alaskan North Slope (ANS) crude oil into the market, there has been a large surplus of crude oil available to refiners on the West Coast. Despite this the industry has developed no major plans for expan- sion of refining capacity on the West Coast as refining capacity already significantly exceeds product demand in the area. Tradi- tionally West Coast refiners have concentrated on optimizing gasoline production and as a result cannot directly replace imports with heavy, sour ANS. Therefore, ANS crude is the sur- plus crude on the West Coast and a large fraction being shipped to the Gulf Coast and Virgin Islands for refining. The outlook for development of a basic grass roots petroleum refinery in Alaska is not good; however, consideration is being given to establishing a petrochemical refinery (ALPETCO) to pro- cess ANS royalty oi1 for product marketing in Japan. 2.6 2.4 TIMING The question of when energy intensive industries will seek develop- ment in Alaska is most difficult to forecast. However, there are certain considerations that can contribute to an understanding of the probable timing: 1) Electric power intensive industries, e.g., aluminum reduction and chior-alkali industries will be attracted only when and if low cost hydroelectric power becomes available in relatively large blocks necessary to support an economically scaled plant. The most likely major hydroelectric development is the proposed Upper Susitna project (1,580 MW total). A two-step construction project has been recommended; the Watana system with a capacity of 686 MW available 6 years from start of construction followed by Devil Canyon to complete the 1,580 MW 10 years after project initiation. The pro- ject initiation, presuming favorable findings from the 4-year Plan of Study just initiated, could be by 1982 leading to Watana power availability by 1988 and full Upper Susitna power by 1992. There- fore, a 1990 date for electric power intensive industries appears reasonable. Industries dependent upon coal based energy, e.g., the cement industry, will probably not be attracted until a significant market increment is added (such as the hydroelectric projects mentioned above) or until the lowest cost coal source (Beluga) becomes avail- able. A reasonable date for the latter is in the mid 1980's cor- responding to the potential startup of the first coal fired Beluga station. For industries dependent upon oi] or natural gas, the situation is somewhat more clouded due to uncertainties in federal regulation and to a lesser extent on the future behavior of the world oi] price as set by the Organization of Petroleum Exporting Countries (OPEC). Alaska is in the anomolous position of having its most widely known and highest valued resource subject to considerable uncertainty both as to price and marketing. 2.7 Currently, it appears that these resources are more highly valued as readily transportable fuels and are subject to foreign export limitations either directly or as petrochemical products. In addi- tion, pending federal legislation may preclue their industrial use in new plants except in instances where process and product require- ments preclude the use of coal. Also, strong competition exists in the world petrochemical market (Saudi Arabia with feedstock costs approaching zero) and at least a near term over capacity problem in Japan. On the side encouraging oil and gas based industrial projects in Alaska, is the strong likelihood that basic oil and gas energy costs in the Lower 48 will increase more rapidly than in Alaska. In part, this will occur as the result of phased deregulation of new natural gas, the decline in domestic production of old oil and the possibility of the imposition of a major import tax on foreign oil. Thus the "rolled in" or weighted average cost of oil] and gas in the Lower 48 domestic market will increase more rapidly than in Alaska where the dominant production will continue from "old" oi] and gas reservoirs at least until the late 1980's. There is a very slight possibility that the OPEC cartel will break. The history of successful cartels suggests a mean lifetime of about 6 years prior to the institution of a price war. In the unlikely event of a price brake in the world oi] market, an Alaskan venture would be severely disadvantaged due to the fact that the higher capital carrying charge nature of an Alaskan plant vis-a-vis a Lower 48 plant will cause this contribution to production costs to become more dominant. Conversely, in the more probable scenario of OPEC continuance, the expectation is that, as prudent depletable resource managers, they will increase prices at a rate 2 to 3 percent above general infla- tion. Alaskan energy becomes increasingly attractive as capital, 2.8 labor, and transportation costs become lesser fractions of the total cost of production. This is particularly true for pro- cesses employing the relatively inflation proof hydroelectric power. 2.9 3.0 SCOPE As noted in the Preface, this volume covers the Alaskan and product market factors influencing industry locations in the state and provides a survey of the most energy intensive industries. This volume was prepared by Pacific Northwest Laboratory, operated by Battelle Memorial Institute. In conducting this work, Battelle analyzed the factors external to Alaska that would influence development and the cost of energy and labor in Alaska. This thus covers the industries likely to be drawn to Alaska because of its energy resources and to analyze these in terms of: 1) the cost of using Alaska energy resources in Alaska as opposed to the Lower 48. 2) skill-adjusted wage and salary differentials between relevant Alaskan areas and the Lower 48, and 3) basic plant and equipment and other operating cost differentials between relevant Alaskan areas and the Lower 48. This report also develops an understanding of the likely level at which development might take place and its timing. 3.1 4.0 ALASKA ENERGY COSTS AND AVAILABILITY When selecting a location for an industrial site a company must evaluate the costs of constructing and operating facilities in a number of locations. This chapter presents representative energy costs in Alaska. These costs can be compared with the representative energy costs in the Lower 48 which are presented in Chapter 5. Fossil fuels available in the southcentral and Fairbanks areas of Alaska include distillate and potentially residual fuels from refinery operations either existing (Kenai and North Pole) or a future refinery based on North Slope crude oi], natural gas (Cook Inlet and Fairbanks via the North Slope pipeline), and coal (from Cook Inlet and interior sources). Over the long term, other fuel sources may be developed within the near offshore and not too distant from the Southcentral and Fair- banks areas. An understanding of future fossil fuel costs is essential to the evaluation of any energy intensive industry. Thus, before attempting to arrive at a "best guess" or a "reasonable range" of expected fossil fuel costs it is worthwhile to review estimates made by prior studies, make adjustments based on new information, and then apply some economic theory. The future costs of fossil fuels in Alaska will be determined by a number of factors that have different weights depending on the fuel type: 1) The world energy market is largely controlled by the Organization of Petroleum Exporting Companies (OPEC). 2) The marginal cost of production plus the appropriate taxes, royalties, and return on investment. 3) The general rate of inflation. 4) The nature and extent of federal price controls and taxes. 5) Transportation tariffs. 6) Terms and conditions of long-term contracts for natural gas. 4.1 7) The market rate of interest. 8) The extent to which Alaskan fuels can participate in the domes- tic and world markets through transportation systems. Different fuels (coal, gas and oil) costs can be expected to respond to the above factors in different manners and hence are discussed sepa- rately in the first three sections of this chapter. At the present time and through the year 2000 it appears that elec- tric power in Alaska will be generated by a combination of fossil fuel fired and hydroelectric generating facilities. The cost of power from fossil fuel fired plants will be strongly influenced by the cost of fuel and the capital construction costs. The cost of electric power produced by hydroelectric facilities will of course be rather isolated from inflation but will be strongly influenced by the capital construc- tion costs. Forecasts of the cost of electric power in Alaska are pre- sented and discussed in the fourth section of this chapter. In each of the following sections both the existing price and avail- ability of the energy sources are estimated. In addition, future price levels and availabilities are forecasted. The "more reasonable" esti- mates for the cost of the various energy sources are summarized in the last section of this chapter. 4.1 Oil Costs and Availability 4.1.1 Crude Oil The obvious source of crude oil for Alaskan use is crude oi] pro- duced in Alaska. At the present time there is crude oil produced in the Cook Inlet area and on the North Slope. Crude oil production esti- mates for the period 1976-1985 are shown in Table 4.1. As shown in Table 4.1 North Slope production is expected to steadily increase during the 1977-1985 time period. Production from the exist- ing Prodhoe Bay fields is expected to decline fairly rapidly beyond 1985, however. Production from the existing southern Alaska fields is expected to decline steadily during the 1976-1985 period and beyond. 4.2 TABLE 4.1. Alaskan Crude 0i1 Production, 1976-1985 Production (1000 Barrels/Day) Region 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 Prudhoe Bay & Adjacent Fields -- 200 1000 1150 1200 1500 1500 1575 1625 1675 Southern Alaska Older Fields 173, 160 150 140 120 108 96 85 73 60 Future Discoveries -- -- -- 15 60 73 86 100 150 200 TOTAL 173, 360 1150 1305 1380 1681 1682 1760 1848 1935 SOURCE: Reference 1, pp. 4.19. Estimating the extent of future discoveries in Alaska is highly specu- lative. The estimates present in Table 4.1 must be regarded as an educated guess at best. Federal and state leasing policy would be of critical importance here. Also, the extent of the reserves both in Alaska and off- shore of Alaska in areas yet to be explored is not known. Production from future discoveries is estimated to be quite low during the early 1980s but increase to about 200,000 b/d by 1985. The forecasted increase during 1983-1985 is primarily due to increased exploration activity brought about by a reduction in the worldwide supply of crude oil during this period. (See for example References 2 and 3.) Based on this reasoning the amount of production from new discoveries can possibly be expected to increase steadily beyond 1985. The availability of imported crude oi] in future years is rather speculative. At the present time there exists a surplus of production capacity on a worldwide basis. This surplus of production capacity is expected to be eliminated during the mid-180s. (293) In any event however imported crude oi] should be available if the purchaser is willing to pay the posted price. 4.3 The price of crude oi] in Alaska, as well as the rest of the world, is controlled by the OPEC cartel. The OPEC pricing strategy appears to be based on their perception of the marginal costs of production of the nearest competitor. This policy is intended to maximize their long-term profits. In the future OPEC's most probable strategy (assuming the cartel can be sustained and no other super-giant oil fields are found or alternative lower cost technologies are developed) will be to escalate its prices paralleling the market rate of interest occurring in its western world market area. The market rate of interest sets the basis from which OPEC can measure its opportunity cost and escalates at approximately 2-3 per- centage points higher than the general inflation rate as measured by the GNP deflator. Thus for a general 5% per annum inflating rate, the OPEC oil increase rate would be expected to be about 7-8% per annum. Since Alaska crude will be competing in domestic marketplaces where the marginal barrel is foreign crude, the market value of crude oil in Alaska will be largely determined by the landed price for imported crude with appropriate quality and locational adjustments. At the present time the estimated price of Alaskan North Slope (ANS) crude (which composes the majority of Alaskan production) should be about $13.21 on the West Coast. (1 p. 8.7) Assuming a transportation cost of 90 cents from Valdez to the West Coast and 30 cents from Valdez to the Cook Inlet area, the cost of crude oil in the Cook Inlet area should be about $12.61. (1° p. 8.5) As pointed out above, this price can be expected to escalate at a rate of about 2-3% higher than the rate of inflation over the long term (20-30) years). 4.1.2 Residual and Distillate Fuel 0i1 At the present time there are three crude oil refineries in the southcentral and Fairbanks area. The operating companies, location, and crude capacity of these refineries are shown in Table 4.2. 4.4 TABLE 4.2. Alaskan Crude 0i1 Refineries Total Crude Capacity (b/d) Chevron U.S.A. Inc. - Kenai 22,000 Tesoro Petroleum Corp. - Kenai 38,000 North Pole Refining - North Pole 22,600 TOTAL 82,600 SOURCE: eS and Gas Journal, March 28, 1977, p- . These refineries are producing products primarily for the existing Alaskan market. Any large additional requirement for residual or dis- tillate fuel oil would have to be supplied by: 1) imports of fuel oil, 2) expansion of existing refinery capacity, or 3) construction of new refinery capacity. Figure 4.1 summarizes some past data and several estimates of future industrial fuel oil prices in the Railbelt region. These estimates are presented primarily to illustrate the divergency of opinion that exists. Curves (1) and (3) estimated by the Institute for Social and Economic Research (ISER) for distillate and residual fuels are based on their assumption that fuel costs will track a general inflation rate of 6% per annum after 1980. Forecasts by the Interior Alaska Energy Advisory Team (IAEAT) for 1980-1985 appear low based on recent experience and the influences affecting inflation and escalation. 4.2 Natural Gas Cost and Availability There are many areas of Alaska that have excellent speculative pros- pects for natural gas. However, the Cook Inlet region is the only current major producer. The estimated remaining reserves in the latter region as of January 1, 1977 are summarized in Table 4.3. Estimates of additional 4.5 ESTIMATES OF FUTURE OIL PRICES a 50 }— RAILBELT DISTILLATE ISER"” \ 10;— $/mm Btu UNSPECIFIED OIL ANCHORAGE RW RETHERFORD IN ISER2) -- DISTILLATE FBKS VIA ARR.® | DISTILLATE | FBKS, IAEAT7 RAILBELT RESIDUAL ISER?3 INTERIOR ALASKA ENERGY ADVISORY TEAM”? FEDERAL POWER COMMISSION® COST RANGE #2 DIST. & RESID. N. POLE REFINERY”? ™~ APPROX. NORTHSLOPE CRUDE, FAIRBANKS® U.S. AVERAGE LANDED PRICE IMPORTED OIL -FEA®) 1.0 70 75 80 85 90 95 2000 YEAR FIGURE 4.1. Estimate of Future Oil Prices 4.6 Footnotes for Figure 4.1 Curve No. 1. Railbelt distillate, Institute of Social & Economic Research, "Elec- tric Power in Alaska, 1976-1995," August 1976, Pages 7-24, 25. Six percent per annum inflation and escalation assumed after 1979. Unspecified oi] at Anchorage. Estimate by R. W. Retherford reported by ISER, pages 7-11, 25. 7.3% per annum apparent inflation escalation rate. Railbelt Residual, ISER, pages 7-25, 6% per annum inflation and escala- tion assumed. Railbelt unspecified oi] in "1976 Alaska Power Survey," Vol. 1, pages 8-9, Federal Power Administration. U.S. Landed Price, average foreign imported crude, Federal Energy Administration Monthly Energy Review, September 1977. Prudhoe Bay Crude at North Pole, Battelle Estimate, September 1977 based on Oi] & Gas Journal, September 5, 1977, page 56, 50% of Pipe- line Tariff applicable. Distillate oil Fairbanks, Interior Alaska Energy Advisory Team, June 17, 1977. Distillate, Fairbanks via Alaska Railroad, Date from GVEA, FMUS, October 1977. Range of Cost for #2 Distillage and Residual FOB North Pole Refinery, Data from GVEA, FMUS, October 1977. 4.7 TABLE 4.3. Cook Inlet Natural Gas Reserve Estimates Total Estimated Uncommitted Remaining Reserves Reserves TCF TCF Producing Fields 7.24 2.98 Shut-in Fields 1.08 0.96 TOTAL 8.32 3.94 SOURCE: Reference 4, p. 2. speculative resources in the region range up to 15.47 TCF of which the majority are expected to be offshore and yet to be discovered. (4+ p. 2) In 1975, the Cook Inlet region consumed about 154 BCF of natural gas, 69 BCF of which were for in-state use not related to export. Fore- casts for subsequent years' demands are as follows: TABLE 4.4. Cook Inlet Natural Gas Annual Demand Estimates Billions of Cubic Feet 1980 1985 1990 1995 2000 In-State Use 104 139 154 168 185 Export 106 266 278 302 310 TOTAL 210 405 432 470 495 SOURCE: Reference 4, p. 2. Based on the data presented in Tables 4.3 and 4.4 the currently committed reserves will be exhausted by about 1987, the known reserves in currently producing fields will be exhausted in 1993 and by 1995 the total estimated known reserves will be exhausted. Beyond 1995 dependence will be upon resources to be discovered. 4.8 The largest known reserve of natural gas in Alaska is contained in the Prudhoe Bay field. The known reserves in this area are estimated to be 26 trillion cubic feet or over 11% of the total known United States reserves. Production of these reserves will likely be initiated in 1983-1985 at a rate of two billion cubic feet (BCF) per day and possibly as high as 2.5 billion cubic feet per day. Present plans call for this gas to be transported through the Northwest-Alaskan gas pipeline running from Prudhoe Bay to Fairbanks and then into Canada following the Alaska highway. Compared to fuel oil, natural gas prices represent a completely different and even more complex situation. Figure 4.2 illustrates some estimates of future gas prices under differing long-term contracts for old gas, marketability situations, and potential regulatory conditions. Again, the illustration demonstrates the wide ranges of possible outcomes under varying assumptions. Due to the necessary investments in transmission and transportation systems, natural gas prices usually involve long-term (20-30 yr) contracts often with clauses covering take-or-pay, escalation, rollover, and adjust- ments for alternative future takers, etc. In addition to the above factors, future natural gas prices are sub- ject to considerable regulatory uncertainty. Assuming that new transpor- tation systems will allow Alaskan gas access to the domestic market, a number of possible outcomes can occur under new contracts for old gas or for new gas. Under the current Federal Energy Regulatory Commission (formerly the FPC) ruling 770A, new gas can be priced at the wellhead according to Curve No. 5. However, the present Administration and the House (H.R.-8444) propose that new gas follow a formula pricing based upon the average refinery crude oi] acquisition cost which in early 1977 was approximately $1.98/mm Btu. Assuming inflation plus escalation at a rate of 8% per annum, the new gas could be priced at the wellhead as high as the levels shown by Curve No. 1. 4.9 ESTIMATES OF FUTURE NATURAL GAS PRICES 10; L — ISER HR 8444 NEW GAS") 8% INF. & ESC. [— 5% INF. AVER. REFINERY CRUDE OIL ACQ. PRICE ~__ 5% INF.’ FPC 770A FPC AK. PWR. NEW GAS® $/mm Btu ° | ALASKA PIPELINE RAIL BELT? HR 8444 OLD GAS NEW CONTRACTS RW RETHERFORD ANCHORAGE®: I WELL HEAD”: 0.5}— a ANCH. MUN. LT. AND POWER®) L Re 1 1 ee POSSIBLE LIFE BELUGA FIELD COMMITTED RESERVES 0.1 | | | | | | _| 70 75 80 85 90 95 2000 YEAR FIGURE 4.2. Estimates of Future Natural Gas Prices 4.10 Footnotes for Figure 4.2 Curve No. le Proposed National Energy Act H.R. 8444 - New gas at wellhead. Five and 8% inflation plus escalation assumed in refinery average crude oil acquisition cost from January 1977. This price is at the well- head and does not include federal excise taxes on utility use on transmission cost to the plant. Railbelt gas, Institute for Social and Economic Research. Proposed National Energy Act H.R. 8444 - Old gas at wellhead at 5% inflation rate. "1976 Alaska Power Survey," Federal Power Commission estimate. FPC ruling 770A wellhead price. R. W. Retherford estimate appearing in ISER report, "Electric Power in Alaska, 1976-1995." August 1976, pages 7-25. Contract Provisions. Alaska Pipeline Co. Wellhead cost. Anchorage Municipal Light and Power cost. 4.11 For old gas (i.e., presently producing fields) under new contracts or rollover contracts, the wellhead price might be expected to track Curve No. 3 assuming a 5% general inflation rate and no escalation. 4.3 Coal Costs and Availability Coal prices and availability in Alaska appear much more predictable due to the absence of regulation and the currently limited influence of marketability factors. Two sources of coal supply for the Southcentral and Fairbanks regions are most pertinent to this analysis: 1) The Nenana Coal Field currently being mined by the Usibelli Coal Co. at about 700,000 tons/yr with plans for expansion to 1.5 million tons/yr. This mine currently supplies the Golden Valley Elec- tric Association (GVEA) plant located at Healy and the Fairbanks Municipal Utility System in Fairbanks. 2) A potential future coal source is the Beluga Field in the Cook Inlet region. The latter field is known to contain very substantial re- serves but the new mine development required will be costly due to lack of transportation facilities and mine supporting infrastructure. Figure 4.3 summarizes various previous forecasts of coal prices in the Southcentral and Fairbanks regions. The Nenana Coal Field is the obvious supplier for future interior generation based on coal. Recent cost of coal delivered by truck to the GVEA Healy Plant is $0.70/MMBTU and by rail at Fairbanks, $1.05/MMBTU. For delivery to the Nenana area, additional costs above mine mouth costs, will be incurred including tipple costs (approximately $0.11 per MMBTU currently) and Alaska Railroad tariffs. The latter may be reduced if unit trains were to be employed. The Usibelli Coal Mine, Inc. has indicated that they expect their prices to rise at about 7% per annum. This pricing schedule appears reasonable if it is assumed that a 5% per annum general inflation rate continues and a 2 percentage point markup escalation is appropriate for the resource owner. Early 1977 mine mouth coal costs were $0.60/MMBTU. 4.12 Therefore, assuming mine mouth and tipple costs increase at 7% per annum and that rail transportation costs have an 80% exposure to general infla- tion (i.e., 4% per annum) coal costs appropriate for the Fairbanks-North Star Borrough load center should follow the curve shown in Figure 4.3. The Healy area could also serve the Cook Inlet region via the Alaska Railroad. Tariffs for Healy coal delivered by rail at Anchorage and Portage as provided by the Alaska Railroad are summarized in Table a c 4.5 as a function of annual tonnage and car ownership.‘ ) For the purpose of this analysis we have assumed that the tariff would be about $0.30 per MMBTU resulting in Healy-Anchorage curve as shown in Figure 4.3. The Beluga/Susitna coal field is an obvious source of supply for coal in the Beluga area. The reserves are very Jarge and capable of supporting a world scale mine for export and mine mouth industrial devel- opment. The coal is subbitimunious (Rank C) and of relatively low heating value (v7100 Btu/1b) at run-of-mine but quite low in sulfur (0.15% typical). Coal preparation including washing and drying could raise the heating value to 9,000 Btu/1b. Some of the coal will be of too low a quality for export but would nevertheless be suitable for mine mouth industrial development. Placer Amex Inc., holder of the larger leases, has recently con- ducted considerable exploration to prove out the reserve. They are of the opinion that a 6MMTPY for export mine would be required to support the front end capital investment necessary for such a frontier area opera- tion, in particular for the harbor and loading facilities. Under private 4.13 10 WW T 5 ISER 7 a /, Z - HEALY COAL FOB NENANA HEALY COAL FOB TIPPLE INTERIOR ALASKA ENERGY + ADVISORY TEAM - FAIRBANKS HEALY COAL ANCHORAGE FMUS AA EXPERIENCE BELUGA FPC RAILBELT = o INTERIOR ALASKA ENERGY ADVISORY TEAM - HEALY $/mm Btu ° o | GVEA HEALY EXPERIENCE ( 0.1 l | | | | | 70 75 80 85 90 95 2000 YEAR FIGURE 4.3. Estimates of Future Coal Prices 4.14 SLY (a) TABLE 4.5. Alaska Railroad Tariffs-Healy Origin Anchorage Portage Shipper Carrier Shipper Carrier Annual Owned Cars Owned Cars Owned Cars _Qwned Cars Tonnage %/Ton $MMBTU $/Ton $/MMBTU $/Ton $/MMBTU $/Ton $/MMBTU 200,000 to 500,000 - = 7.67 0.441 - - Tish 0.444 1,000,000 4.2] 0.242 5.51 0.317 4.7] 0.271 6.01 0.345 1,500,000 4.20 0.241 5.18 0.298 4.70 0.270 5.68 0.326 2,000,000 4.10 0.236 5.00 0.287 4.59 0.264 5.49 0.316 (a) Conversion to $/MMBTU based on 8700 BTU/# coal quality. financing conditions the estimated coal price FOB mine would be in the range of $0.85 to $1.00/MMBTU ($12 to 14/ton). A mining operation not involving export facilities, though not having the economies of scale, could produce coal at similar prices for local consumption. The 6MMTPY economic mining scale would support about 2,000 MW of gen- erating capacity, a scale which suggests that mining for export or for other industrial development in combination with onsite use would be required at least initially. If coal were used to provide all process heat requirements for a 150,000 bb1/day oi] refinery, this load alone would require about 2 MMTPY. Other alternative Railbelt coal supply regions include the Mananuska and Kenai fields. The Matanuska field is 50-70 miles northeast of Anchorage and the valley is served by a branch line of the Alaska Rail- road. (4) are separated by shale and sandstone layers. Reserves are estimated at The beds of the Matanuska Valley vary in thickness and the seams only 100 million tons. Coal quality is good however, being bituminous in rank with a heating value in excess of 11,000 Btu/1b and a sulfur content of 0.6% or less. Because of the limited proven reserves and difficult underground min- ing situation in the Matanuska Valley, no further consideration is given to this area as a coal source. The Kenai field (.300 million tons, 7,700 Btu/1b, 0.1-0.4% sulfur) also suffers from having seams 6 ft or less in thickness. In addition, the beds are lenticular, making continuous mining of a seam impossible over large areas. 4.4 Electric Power Table 4.6 presents the costs of electric power in several categories for Alaska. These costs can be compared to the costs shown for the Pacific Coast States of California, Oregon, and Washington as well as some (a) The tracks have been removed past Palmer but the roadbed still exists. 4.16 L4L'v TABLE 4.6. Cost of Power to Ultimate Consumers ($/kWh ) Commercial & Industrial Street & Other Railroads Smal] Light Large Light Highway Public and Inter- State Residential _and Power and Power Lighting Authorities Railways departmental California 0.035 0.033 0.024 0.050 0.010 0.017 0.009 Oregon 0.018 0.017 0.008 0.035 0.008 - 0.009 Washington 0.013 0.014 0.005 0.023 0.009 0.011 0.001 Massachusetts 0.050 0.047 0.037 0.084 0.040 0.062 0.040 Pennsylvania 0.041 0.038 0.026 0.078 0.041 0.029 0.028 Tennessee 0.023 0.027 0.017 0.034 0.024 - 0.019 Alaska 0.034 0.032 0.033 0.060 0.047 0.031 0.035 SOURCE: Edison Electric Institute, Statistical Year Book of the Electric Utility Industry for 1976, New York, 1976, pp. 33-45. representative eastern U.S. states: Massachusetts, Pennsylvania, and Tennessee. As shown in Table 4.6 the cost of power in Alaska in most con- sumer categories is typically higher than the cost of power in the Pacific Coast states. California power costs are only slightly higher, however. The lower electric power costs in Oregon and Washington can be attributed to the large percentage of relatively low cost power produced by hydroelec- tric generating facilities located in the Pacific Northwest. The power costs in Tennessee are also relatively low due mainly to the TVA hydroelectric program. Of the states listing in Table 4.6 Massachu- setts typically has the highest cost of power while Pennsylvania ranks second in most cases. Future costs of electric power in Alaska and the Lower 48 are diffi- cult to predict. Utilities in the Lower 48 are faced with rising construc- tion costs for both coal and nuclear plants due to increased materials and labor costs as well as environmental considerations. Fuel costs for both coal and nuclear plants are also increasing. Alaskan utilities are faced with the same factors in addition to the historically greater construction and operation costs existing in Alaska. One factor that may tend to retard the increase in power costs in Alaska is the possible construction of addi- tional hydroelectric generating facilities in the state. Based on existing cost data there are several possible hydroelectric projects that could pro- (6, p. 8.5) At the pre- sent time there are no similar plans for significant increases in hydro- duce power at a lower cost than thermal facilities. electric power generation in the Lower 48. Based on this analysis there is no reason to believe that the rate of increase in power costs will differ between the two regions. If this is the case, the relationship among the electricity costs shown in Table 4.6 will continue into the future. A recent analysis of the bus bar costs of electric power in Alaska sug- gests that the bus bar cost of electric power from coal steam turbine 4.18 generating plants will increase at a rate about 2.5% above the rate of gen- eral inflation. Hydroelectric power costs including transmission costs are forecasted to increase at a rate about 1.0-1.5% above the rate of gen- eral inflation. (° p. 8.5) Assuming that distribution, customer, and sales expenses increase at a similar rate these estimates could be used as rough estimates of the increases in electricity prices in the future. The electrical transmission and distribution system in Alaska is not nearly as extensive as the systems existing in the Lower 48. The electri- cal transmission and distribution systems in Alaska are typically limited to the immediate proximity of a city or town. Several cities and towns are interconnected in the Anchorage/Homer/Kenai region, however. Fairbanks is interconnected with Healy and Nenana and the Tenana Valley. For these reasons the availability of electric power represents a more serious restriction for industrial siting in Alaska than in the Lower 48. 4.5 Summary of Energy Costs in Alaska From the above discussion, it is obvious that forecasts of future energy costs in Alaska are subject to considerable uncertainty. Neverthe- less, given the assumptions regarding the world Btu market and the National Energy Policy (NEP), at least some rational judgments can be made. As mentioned in Section 4.1.1 the costs of crude oil are expected to increase at about 2 to 3% faster than the rate of general inflation. At this point this assumption appears to also be reasonable for the cost of fuel oil, natural gas and coal. For the purposes of this analysis the fuel prices summarized in Figure 4.4 will be used. Electricity prices will be assumed to increase at about 2% faster the general inflation. 4.19 $/MM/Btu 5.0 RESIDUAL FUEL OIL, NORTH POLE AND NIKISKI NEW GAS WELL = ° \ FEDERAL EXCISE TAX H.R. 8444 —_ HEALY COAL HEALY COAL NENANA HEAD ANCHORAGE \ << HEALY FOB TIPPLE BELUGA ° a 0.1 70 FIGURE 4.4. 75 80 85 90 95 Summary of Probable Fuel Costs - Zero Inflation Rate 4.20 2000 REFERENCES CHAPTER 4.0 North Slope Royalty 0.1 Market, Pricing and Revenue Analysis, Division of Research Services, Legislative Affairs Agency, Alaska State Legislature, March 1978. CIA Sees World 0i1 Shortfall by 1985, The Oil and Gas Journal, April 25, 1977, p. 90. BP Sees Global Oil Shortage in 1990s, The 0i1 and Gas Journal, October 24, 1977, p. 62. Alaskan North Slope Royalty Natural Gas - An Analysis of Needs and Opportunities for In-State Use, Alaska Department of Commerce and Economic Development, Division of Energy and Power Development, August 1977. load Communication, A. Polachek, Alaska Railroad, November 11, Alaskan Electric Power - An Analysis of Future Requirements and Supply Alternatives for the Railbelt Region, Division of Energy and ee ee eran Department of Commerce and Economic Development, larch 1978. 4.21 5.0 CONTIGUOUS STATES ENERGY COSTS AND AVAILABILITY Much of the discussion and data presented in Chapter 4.0 is directly applicable to the energy costs in the Lower 48. The evaluation pre- sented in this chapter is aimed at presenting historical and current data on oil, natural gas and coal costs. In many cases costs of fuel to electrical utilities is presented as representative of large industrial purchases. 5.1 Oil Costs and Availability 5.1.1 Crude Oil As explained in Section 4.1.1 the price of imported crude oi] is controlled by OPEC. Domestic crude prices are presently controlled by a variety of price controls and entitlements. Foreign and domestic crude oil prices and refiner acquisition costs are presented in Figure 5.1 for the 1974-1978 time period. It was pointed out in Chapter 4 that crude oi] and fuel oi] prices are expected to increase at a rate about 2 to 3 percent above the general inflation rate in the future. Imported crude oi] would have essentially the same landed cost in Alaska as in the Lower 48. 5.1.2 Residual and Distillate Fuel Oi] The prices paid for residual fuel oi] by electric utilities in various regions in the Lower 48 are presented in Table 5.1. 5.2 Natural Gas Price and Availability The costs of natural gas delivered to steam electric utility plants for the 1975-1977 period are presented in Table 5.2. The prices for natural gas increased relatively rapidly during the 1975-1977 time period. It is unclear what the natura gas pricing provisions of the National Energy Plan (NEP) will be. In any event, the price of natural gas on a per Btu basis can be expected to increase to be roughly equivalent to the price of residual oi] over the near future (5 yrs). Sou $/BARREL — oO 14 13 — — AVERAGE REFINER ACQUISITION COST OF IMPORTED SAUDI ARABIA ‘~~ A neztte CRUDE AVERAGE REFINER ACQUISITION COST OF DOMESTIC CRUDE CANADIAN x fo oN CRUDE J SOURCE: REFERENCE 1, pp. 69-70 “ REFERENCE 2, pp. 75-76 1974 1975 1976 1977 1978 1979 FIGURE 5.1. Foreign Crude Oil Prices and Refiner Acquisition Costs 52 TABLE 5.1. Electrical Utility Residual Fuel Oil Prices (cents per million Btu) Region June 1975 dune 1976 dune 1977 New England Z201e7) Wie8 216.2 Middle Atlantic 201.5 187.3 22351 East North Central 16353 211.8 248.6 West North Central 165355 148.8 186.6 South Atlantic 189.3 171.9 210.1 East South Central 165.5 166.9 ldiey) West South Central 182.0 176.4 194.3 Mountain 199.0 212.4 Zoa3 Pacific 245.6 229.1 2357, SOURCE: Reference 1, p. 75; Reference 2, p. 83. TABLE 5.2. Electrical Utility Natural Gas Prices (cents per million Btu) Region dune 1975 June 1976 dune 1977 New England Tay VESE7/ 193.9 Middle Atlantic 92.7 108.0 144.2 East North Central 111.6 139.8 Wiles West North Central 58.1 78.1 104.8 South Atlantic Nese 83.1 74.4 East South Central 77.0 12320 134.3 West South Central 69.2 98.1 122.1 Mountain 69.6 go.5 132.9 Pacific 84.1 147.6 200.5 SOURCE: Reference 1, p. 75, Reference 2, p. 83. Deo At this point the availability of natural gas must be examined on a regional basis. Since the price of gas in the intrastate market is not regulated new gas contracts should be available in gas producing states at the market price. Gas supplies in the interstate market are much tighter and would have to be evaluated on a case by case basis. 5.3 Coal Price and Availability The prices paid by utilities for coal during the 1975-1977 time period are presented in Table 5.3. TABLE 5.3. Electrical Utility Coal Prices (cents per million Btu) Region dune 1975 dune 1976 June 1977 New England 116.5 12253 130.1 Middle Atlantic 101.6 102.5 107.4 East North Central 82.4 86.6 95.5) West North Central 5329 64.7 77.0 South Atlantic 98.4 100.7 113.9 East South Central 80.5 84.5 95.0 West South Central 21.0 Use) 63.9 Mountain SIO 3529 47.4 Pacific 58.4 1552 Tee SOURCE: Reference 1, p. 75; Reference 2, p. 83. As can be seen from Tables 5.1 through 5.3, the prices paid by utilities for coal is generally lower than the prices paid for nat- ural gas and fuel oil. There are two primary reasons for this: 1) coal generally requires much more emissions control equipment to meet emissions standards, and 2) coal is less convenient to use and to transport than either natural gas or oil. 5.4 5.4 Electric Power Costs and Availability The costs of electric power in several representative states in the Lower 48 were presented in Section 4.4. 1. Federal Energy Administration, Monthly Energy Review, December 1976, National Energy Information Center, Washington, DC. 2. U.S. Department of Energy, Monthly Energy Review, December 1977, National Energy Information Center, Washington, DC. 5.5 6.0 ALASKA CONSTRUCTION AND CAPITAL COSTS Several methods can be used to estimate the construction or capital cost of industrial facilities. Each method has a different level of un- certainty associated with it. As would be expected, the less the uncer- tainty associated with an estimate, the more time and money required to prepare it. Several factors contribute to the uncertainty of an estimate; rapidly escalating equipment, site materials, and labor costs are perhaps the most important at the present time. The most accurate estimating procedure is to obtain a firm bid for the installed equipment from a supplier. This procedure can be costly, however, since it usually requires site-specific studies and binding commitments from subcontractors. As a result, this method is typically not used unless there are definite plans to purchase the equipment. The next most accurate method of estimating the capital cost of a facility is to obtain an estimate (nonfirm) by a supplier. In most cases with large and expensive equipment, suppliers are reluctant to give such estimates because the total costs are highly dependent on site-specific factors which require a working knowledge of local conditions. In most cases, suppliers with recent experience in the area can give relatively accurate short term estimates. Another relatively accurate estimating procedure is to develop the costs of the proposed facilities based on data from recent purchases of similar equipment of the same size located in a similar location. This technique is not applicable in most cases for Alaska because of limited experience with industrial facilities in the State. For survey analysis such as this, one method of estimating capital costs is to use a construction cost location adjustment factor. Condi- tions that influence the construction cost of facilities differ among various regions. The differences may be due to such things as the rela- tive availability of transportation facilities, labor costs, climate, 6.1 and distance from equipment suppliers. In many cases, these factors com- bine to influence costs in a consistent manner which allows a location adjustment factor to be used. This number is expressed at the ratio between the construction cost of an item at a proposed location and the construction cost of that item at a base location; i.e., : 1 _. Cost at Proposed Location Location Adjustment Factor Cost at Base Location Such a location adjustment factor may be used to estimate the cost of a facility in Alaska given the cost of a similar facility in the Lower 48. Because of the large and diverse nature of Alaska, the "Alaska factor" must be defined for a specific location in the state. The base location in the Lower 48 should also be specified although it is not as critical as in Alaska. A number of Alaska factors are listed in Table 6.1. The Alaska factor can be refined slightly by using different factors to escalate labor and materials. The total cost of the completed project is weighted based on the relative amount of labor and materials used. Labor and material adjustment factors were developed by the Alaska Power Administration (APA), for (t Interim Feasibility Study on the Upper Susitna the materials adjustment factor was 1.1. These numbers are based on Oregon River Hydroelectric Study. The labor adjustment factor was 1.9 and and Washington data and a remote job site in Alaska (approximately 100 miles north of Anchorage). These estimates are also presented in Table 6.1. Assuming that 30% of the total cost is labor (typical estimate for an industrial facility), an overall factor of 1.34 is computed. Overall Factor = 0.3 x 1.9 + 0.7 x 1.1 = 1.34 This figure appears to be generally lower than the other factors shown in Table 6.1. A possible reason for this is: The factor of 1.1 for materials assumes that the cost of transpor- tation including loading and unloading from the Pacific Northwest 6.2 €°9 TABLE 6.1. Alaskan Construction Cost Location Adjustment Factors a 10 pacific Coast Anchorage Beluga Healy Fairbanks Barrow Railbelt Washington, pc «1.0622 7,76) a 75b) pga fb) : - E (c) Pacific Coast - - - - - - 1.1 - Materials 1.9 - Labor — Lower 48 (General) ‘ 1.35(4) a - : : : Anchorage - - - - 1.22) o.gl@) _ Derived for Pacific Northwest - 1.65 2.70 2.35 2.0 Battelle Estimates - 1.50 1.80 2.20 2.0 (a) Based on Handy-Whitman Index for North Atlantic Region and Pacific Region. January 1, 1977 price levels - total plant all steam generation. (b) Letter from Charles A. Debelius, Colonel, Corps of Engineers to M. Frank Thomas, Regional Engineer, Federal Power Commission, May 5, 1975. Based on heavy construction with labor being 50% of the total cost. (c) Upper Susitna River Basin, Interim Feasibility Report, Appendix 1, Part 2. U.S. Army Corps of Engineers, p. H~57, December 12, 1975. Upper value is for materials, lower value is for labor. (d) Electric Power in Alaska, 1976-1995. ISER, University of Alaska, p. G.1.1, August 1976. (Letter from Thomas R. Stahr to A. Tussing, May 10, 1976.) (e) Electric Power in Alaska, 1976-1995. ISER, University of Alaska, p. G.2.1, August 1976. to the Railbelt is $2.37/100 lb. A more recent estimate for materials typical of power plant is $8.00/100 1p. (2) Using this estimate, the mate- rials factor becomes 1.27 (round to 1.25). Using this modified estimate and again assuming that 30% of the total cost is labor, an overall factor of 1.45 is indicated: Overall Factor = 0.3 x 1.9 + 0.7 x 1.25 = 1.45 It appears that an Alaska factor of 1.4 to 1.5 is justified for esti- mating the cost of a plant in the Anchorage area given the cost of a plant in the Pacific Northwest. Previous work done by Battelle for the State of Alaska indicates that a multiplier of 1.5 would be appropriate for a chemi- cal plant using modular construction to minimize site labor. (3) Construction costs at Beluga should be higher than costs in the Anchorage area. The estimate prepared by the Corps of Engineers (2.75) appears to be higher than recent estimates of construction costs in the Beluga area would suggest, however. There are some cost trade-offs which support this viewpoint. Real estate costs might be less in the Beluga area for example. Also, if much of the plant were modularized and prebuilt in Puget Sound even large modules could be barged to the area beaches where off loading could be achieved (using the 25-30 ft tides) without the need of harbor construc- tion. Such large modules could not be handled over normal dock and rail terminal facilities. Housing for labor would be an added cost item at remote locations. The plant site could be only 50 to 70 air miles from Anchorage and a week- ing rotation of crews would be possible. Fuel for equipment and daily sup- plies could come by landing craft type barges from Anchorage or Nikiski. Based on this reasoning an Alaska construction cost factor of 1.80 is used for the Beluga area in Cook Inlet. Plant construction in the interior could not take advantage of the modular construction opportunities available at tide waters. A construc- tion cost factor of 2.2 is used for interior areas on the Railbelt. 6.4 Of course, the sites listed in Table 6.1 do not represent all of the possible industrial sites in the State of Alaska. The estimates pre- sented in Table 6.1 can be used to extrapolate cost multipliers for other regions in the State. 1. Upper Susitna River Basin, Interim Feasibility Report, Appendix I, Part 2, U.S. Army Corps of Engineers, p. H-57, December 12, 1975. 2. John Chapman, Chief-Estimating Section, Alaska District, U.S. Army Corps of Engineers, Personal Communication, Anchorage, AK, October 125 19777 3. Alaskan North Slope Royalty Natural Gas, An Analysis of Needs and Opportunities for In-State Use, Division of Energy and Power Devel- opment, Department of Commerce and Economic Development, State of Alaska, p. VIII-36, September 1977. 6.5 7.0 ANALYSIS OF ALASKAN LABOR COSTS AND ESTIMATION OF WAGE DIFFERENTIAL BY INDUSTRY 7.1. INTRODUCTION Labor costs can be a significant portion of total production costs and vary widely from industry to industry and state to state. For example, in 1970 labor costs were approximately 30 percent of the nation's total production costs. That means that for every $3 of goods and ser- vices produced, $1 was spent for employee compensation. The 3 to 1 ratio is a national average for all industries and of course wide fluctuations will be found in the ratio for specific industries. For example, some service industries may have a ratio of 5 to 4 while for some automated manufacturing industries the ratio may be 5 to 1. The local labor costs must be kept in perspective with total pro- duction costs and other elements considered in siting industrial plants. For example, higher than average labor costs might be offset by less costly raw materials, energy costs, or transportation costs. Therefore, industrial managers will desire sites with relatively low labor costs; but they have a stronger incentive to locate in areas which provide a low or competitive total production cost. Most agree that labor costs are usually greater in Alaska than in the Lower 48 states. The question requiring an answer, however, is how much greater are labor costs in Alaska than the Lower 48? What is the differential in labor costs and how important will these labor costs be with respect to the costs of other factors of production and the total cost of production. For example, products might be identified which require a minimum of labor and then plants designed which are efficient with respect to utilization of labor, close to markets (Japan), and requiring materials which are relatively more available in Alaska than in the Lower 48 states. Heil One can safely assume that when all things are equal industry will locate at a site which allows them to minimize production costs. This makes them the most competitive and most profitable. In reality plant siting turns out to be a series of compromises and production costs are almost always greater than the theoretical minimum; e.g., the pre- ferred site is not obtainable at a reasonable price. In addition there may be and frequently is one dominating factor of production whose avail- ability almost dictates future plant locations independent of labor costs. Therefore, while labor costs are important, they are not the only cost of production and industries and markets should be identifiable for which an Alaskan location will have significant advantages. These need to be identified as well as the labor costs so that the latter can be put in per- spective. For example, if one were to construct a new cement plant, the preferred site would have an adequate supply of low cost energy and labor and a large, adjacent source of limestone. Currently there are no low cost sources of energy, but an assured supply will be attractive. Alaska can provide the latter and in addition limestone sources exist. Given these two positive factors, Alaska might be a preferred site independent of labor costs. 7.2 OBJECTIVE The following sections of this chapter identify the cost of labor for numerous, potential Alaskan industries. The average weekly labor costs were developed for each of these industries located in several states as well as Alaska. The data were selected to identify and illustrate the range of labor costs for selected industries. For each industry. several states were selected on a basis of: 1) large employment in the given industry, 2) proximity to Alaska, 3) potential for competing with industry located in Alaska, and 4) representing the highest or lowest labor cost among the Lower 48 states. dee The results of the analysis include average weekly cost of labor and the percentage of the national average labor cost for 10 industries and selected states. 7.3 IDENTIFICATION OF WAGE DIFFERENCES 7.3.1 Data Data were collected from U.S. Department of Labor, Bureau of Labor Statistics (2) for the years 1965, 1970, 1973, and 1975. The data col- lected was for 12 states, the U.S. average, Pacific Region (Washington, Oregon, California, Alaska, and Hawaii) plus the Western Southcentral states (Arkansas, Louisiana, Oklahoma, and Texas). The states were selected because they represented potential competition for an Alaskan industry, the state had a large fraction of the industry's employees, or the state's employees received the greatest or least weekly salary. For example, Texas is included because it has the greatest number of employees in the oil refining and petrochemicals industries. The industrial classifications selected were: all industries, ] 2) contract construction, w all mining, all manufacturing, nan - oO paper and allied products, ™N chemicals and allied industries, co ) ) ) ) ) petroleum refining and related industries, ) ) ) crude petroleum and natural gas, ) 9 10) transportation, communication and other public utilities. services, and The data were analyzed and utilized for estimating weekly "wage rates" per employee for each of the 10 industries. (a) U.S. Department of Labor, Bureau of Labor Statistics, Employment and Wages - First Quarter, 1965, 1970, 1973, and 1975. dfer3 The wage rates were calculated by 12 states, the total U.S., the Pacific Region and the West Southcentral Region. These data then pro- vided a basis for comparing Alaskan labor costs or wage rates with labor costs in other states for 10 industrial classifications. Quarterly data were utilized as it was the most appropriate for identifying wage differentials, i.e., the difference between Alaskan and other states' wage rates. The published data for employment is by month and the wage data is by quarters. The quarterly data needed to be converted to a per capita income in order to have a basis for compari- son. The quarterly wages were converted to weekly income per employee by dividing by 13 (weeks in a quarter) and the employment for March. The result is an "average weekly wage" per employee based upon the first quarter's earnings. The published data does not include any correction for hours worked so the weekly "wage rate" would be overstated (on a 40-hr/wk basis) for those employees who worked more than the normal 40-hr week. The first quarter data were selected to minimize this data problem as no data is available for “correcting or adjusting" the published data. Large, industrial classifications were also used when appropriate. These larger classifications were required to obtain data for Alaska which would be large enough to provide a reliable wage rate. For example, some industries in Alaska which might be expanded currently have very few employees. The data for these industries might be too small to provide a realistic weekly wage unless aggregated with other industries. These industries were aggregated as necessary and appropriate. The data errors were then reduced by averaging. 7.3.2 Data Analysis Weekly wage rates were calculated for 10 industrial classifications for 12 states, 2 regions and an average for the United States. The rates were calculated for 1965, 1970, 1973, and 1975. The data and wage rates 7.4 are tabulated in Appendix A.7. A summary of the data for each classifi- cation is provided in Tables 7.1 through 7.10 for Alaska, the U.S. average and key states, Figures 7.1 through 7.10 also illustrate the data. The calculated weekly wage rates are for historical data and are used to illustrate the past trend. The data represent the cost of labor for existing plants. No attempt was made to develop estimates or labor pro- ductivity in each of the industries; i.e., production per employee. The labor productivity will also be influenced by the age of the plant; generally the newer the plant the more efficient it will be with respect to labor productivity. Also, any new plant to be constructed in Alaska should have access to the latest technology and in turn be the most efficient in terms of labor. Weekly wages were catculated for the classification, "All Industries," which represents the average for all industries. This is a general classification which includes all employees covered by state unemploy- ment insurance laws and for federal civilian workers covered by the pro- gram of Unemployment Compensation for Federal Employees. Table 7.1 pro- vides a summary of the weekly wage rates for the U.S. (a national aver- age), California, Alaska, and the Pacific Region (Washington, Oregon, California, Alaska, and Hawaii). Table 7.1 also includes values for the percent of national average wage rate. For example, in 1973 the Alaskan average weekly wage rate was 133% of the average national wage rate. In previous years (1970 and 1965) the Alaskan rate was 135 to 140% of the national average. In 1975, however, the average rate increased to 175% of the national average. The data are probably reflecting the inflationary impacts and the long workweeks associated with the Trans Alaskan Pipeline. 15 TABLE 7.1. Weekly Wages by Industry and Region Dollars per Week and Percent of National Average for All Industries(a) 1975 1973 1970 1965 $/Week % aWeek % $/Week % $/Week % United States 186.30 100 161.2 100 137.4 100 105.8 100 California 198.3 106.4 174.3 108.1 149.5 108.8 119.5 112.9 Alaska 326.1 175 214.8 133.3 193.8 141 143.06 135.2 Pacific 197.4 106 172 106.7 147.6 107.4 116.85 110.4 (a) U.S. Department of Labor, Bureau of Labor Statistics, Employment and Wages First Quarter, 1975, 1973, 1970 and 1965. 500 too E ALASKA 300 |~ << 8 CALIFORNIA PACIFIC A” 200 |- ee UNITED STATES 100 | | L ! 1965 1970 1973 1975 FIGURE 7.1 Average Weekly i!age ~ All Industry 7.6 A similar analysis was completed for "Contract Construction". Alaskan employees in contract construction receive a considerably greater wage than the average U.S. contract construction worker. In 1965 the Alaskan employee received 180% of the national weekly wage. In 1975 the contract construction worker's weekly wage was 260% of the national aver- age. This reflects the inflationary impact of the pipeline and additional hours worked per week. One should not interpret this data as meaning that an Alaskan employee receives 2.6 times the hourly rate of the national av- erage worker The rate, independent of a major construction project, is probably closer to 1.8 times the national average. The data is summarized in Table 7 2. TABLE 7.2. Weekly Wages by Industry and Region Dollars per Week and Percent of National Average for Contract Construction(a) 1975 1973 1970 1965 $/Week % SWeek % SWeek % $/Week % United States 229.67 100 189.87 100 164.41 100 116.82 100 Washington 245.67 107 205.72 108.3 178.09 108.3 127.95 109.5 California 273.51 119.1 220.89 116.3 195.06 118.6 147.45 126.2 Alaska 591.01 257.3 316.45 166.7 311.49 189.5 211.05 180.7 Pacific 282.85 123.2 218.64 115.2 192.78 117.3 143.46 122.8 (a) U.S. Department of Labor, Bureau of Labor Statistics, Employment and Wages First Quarter, 1975, 1973, 1970 and 1965. Tad 600 ALASKA al 400 + A PACIFIC Be (200) a Ee CALIFORNIA nal ae 20 a Ween is eee ee WASHINGTON coma UNITED STATES 100 [— L ! 1 em 1965 1970 1973 1975 FIGURE 7.2 Average Weekly Wage - Contract Construction Similar analysis were completed for mining and the seven other industrial categories included in the study. The wage rate for the mining industry is approximately 180% of the national average. The wage rates for all the other industries are also greater than the national average. The general category entitled "manufacturing" has the lowest differential and is 20 to 25% greater than the average U.S. manufactur- ing workers. Workers in the other six categories receive from 125 to 180% of average national workers. The data for these employees is pro- vided in Tables 7.3 through 7.10 and Figure 7.3 through 7.10. 7.8 TABLE 7.3. Weekly Wages by Industry and Region Dollars per Week and Percent of National Average for Mining(a) 1975 1973 1970 1965 $/Week % $/Week % $/Week % $/Week United States 266.13 100 210.39 100 170.99 100 1253 Texas 275.63 103.6 219.49 104.3 180.31 105.5 113. California 294.44 110.6 243.78 115.9 199.79 116.8 149. Alaska 502.68 188.9 355.88 169.2 306.78 179.4 196. Pacific 310.66 116.7 245.40 116.6 206.46 120.7 148. (a) U.S. Department of Labor, Bureau of Labor Statistics, Employment $MWEEK and Wages First Quarter, 1975, 1973, 1970 and 1965. 58 69 90 58 65 600 c ALASKA 500 |— 400 PACIFIC 300 —_ Eee ee UNITED STATES TEXAS aa 100 |- L l l 1 J 1965 1970 1973 1975 FIGURE 7.3 Average Weekly “lage - All itining Tee % 100 90.5 119.4 15655) 118.4 TABLE 7.4. Weekly Wages by Industry and Region Dollars per Week and a of National a Average for Manufacturing 1975 1973 1970 1965 $/Week % $/Week % $/Week % $/Week % United States 215.23 100 182.06 100 149.84 100 116.62 100 Washington 244.81 113.7 205.11 112.7 176.35 117.7 130.08 111.5 California 231.37. 107.5 196.76 108.1 171.59 114.5 136.06 116.7 Alaska 267.03 124.1 186.03 102.2 173.08 115.5 135.96 116.6 Pacific 230.87 107.3 - - - - Issslse wast (a) U.S. Department of Labor, Bureau of Labor Statistics, Employment $MWEEK and Wages First Quarter, 1975, 1973, 1970 and 1965. 506 300 r ALASKA ae 200 + — UNITED STATES 100 LI | | | 1965 1970 1973 1975 FIGURE 7.4 Average “Weekly “age - All “anufacturing 7.10 CALIFORNIA TABLE 7.5. Weekly Wages by Industry and Region Dollars per Week and Percent of National Average for Petroleum Refining(a) 1975 1973 1970 1965 $/Week % $/Week % $/Week % $/Week % United States 309.33 100 244.86 100 197.4 100 Texas 308.75 99.8 245.27 100.2 197.9 100.2 California BSS 24S er2scI i ee 24235) 1086 Alaska 384.62 124.3 332.81 135.9 292.3 148.1 Pacific 349.43 113.0 269.97 110.3 212.3 107.6 (a) U.S. Department of Labor, Bureau of Labor Statistics, Employment and Wages First Quarter, 1975, 1973, 1970 and 1965. 500 re PA L A 4 kin: ALASKA lL ww ea = CALIFORNIASS— = an UNITED STATES AND TEXAS 100 7 L ] \ l i 1965 1970 1973 1975 FIGURE 7.5 Average !Weekly !!age - Petroleum Refinina Toi TABLE 7.6. Weekly Wages by Industry and Region Dollars per Week and Percent of National Average for Paper and Allied Products (a) 1975 1973 1970 1965 $/Week % $/Week % $/Week % $/Week % United States 232.38 100 192.32 100 156.31 100 121.12 100 Washington 267.40 115.1 224.65 116.8 169.63 108.5 132.21 109. California 234.12 100.7 201.39 104.7 160.19 102.8 126.14 104. Alaska 371.79 160.0 319.75 166.3 269.23 172.2 174.83 144. Pacific 249.57 107.4 212.62 110.6 167.11 106.9 130.25 107. (a) U.S. Department of Labor, Bureau of Labor Statistics, Employment and Wages First Quarter, 1975, 1973, 1970 and 1965. 500 400 | ALASKA U 300 |~ WASHINGTON is PACIFIC = - = 2 UNITED STATES 200 [- CALIFORNIA 100 |- | L | 1965 1970 1973 1975 FIGURE 7.G Average eekly !age - Paper and Allied Products 7.12 aow— United States New York Washington California Alaska Pacific TABLE 7.7. Weekly Wages by Industry and Region Dollars per Week and Percent of National Average for Chemicals and Allied Products (a) 1975 1973 1970 1965 $/Week % $/Week % $/Week % $/Week % 269.21 100 223.07 100 181.59 100 142.87 100 287.58 106.8 241.10 108.1 196.80 108. 264.27 98.2 225.34 101.0 190.42 104. 242.38 90.0 209.09 93.7 173.15 | 95. 500.00 185.7 368.47 165.2 312.95 172. 245 ON QleO elO 528 943i 4 5p OG: ON O NM —- wow Pf oO Ff (a) U.S. Department of Labor, Bureau of Labor Statistics, Employment and Wages First Quarter, 1975, 1973, 1970 and 1965. $MWEEK 500 ALASKA 400 300 [- UNITED STATES PACIFIC WASHINGTON 200 |- 100 |- | | | | 1965 1970 1973 1975 FIGURE 7.7 Average '!eekly "lace - Chemicals and Atiied Products Ts 151.93 106. 156.47 109. 140.31 98. 192.31 134. 142.00 99. FP DwWwW oO WwW TABLE 7.8. Weekly Wages by Industry and Region Dollars per Week and Percent of National Average for Crude Petroleum and Natural Gas (2) 1975 1973 1970 1965 se $/Week % $/Week % $/Week % $/Week United States 232.38 100 214.85 100 181.35 100 132.79 Texas 222.02 95.5 222.74 103.7 183.02 100.9 77.38 California 260.73 112.2 250.04 116.4 202.33 111.6 76.92 Alaska 371.79 160.0 257.82 120.0 Pacific 249.57 107.4 = - 77.28 (a) U.S. Department of Labor, Bureau of Labor Statistics, Employment and Wages First Quarter, 1975, 1973, 1970 and 1965. 500 too F ALASKA 2 300 + CALIFORNIA aa 27 ee _ CEXAS 200 |+- = UNITED STATES 100 | L_| | | 1965 1970 1973 1975 TABLE 7.8 Average !leekly ace - Crude Petroleum and Natural Gas 7.14 1975 1973 1970 1965 $/Week % $/Week % $/Week % $/Week % United States 150.93 100 128.82 100 110.04 100 91.88 100 New York 182.07 120.6 158.73 123.2 132.17 120.1 100.81 109.7 Washington 144.98 96.1 121.64 94.4 101.91 92.6 75.51 82.2 California 167.75 111.1 145.35 112.8 124.05 112.7 99.36 108.1 Alaska 245.63 162.7 166.07 129.4 145.12 131.9 110.08 119.8 Pacific 162.91 107.9 139.66 108.4 118.83 108.0 94.39 102.7 TABLE 7.9. Weekly Wages by Industry and Region Dollars per Week and Percent of Nat Average for Services (a) jonal (a) U.S. Department of Labor, Bureau of Labor Statistics, Employment $MWEEK and Wages First Quarter, 1975, 1973, 1970 and 1965. 500 me 0] ALASKA ae /CALIFORNIA #-" PACIFIC 100 er UNITED STATES -- SNasuineton 4 l L 1965 1970 1973 1975 TABLE 7.9 Average ‘eekly age - Services Vous TABLE 7.10. Weekly Wages by Industry and Region Dollars per Week and Percent of National Average for Transportation, Communications and Public Utilities(a) 1975 1973 1970 1965 $/Week $ $/Week % $/Week % $/Week % United States 233.55 Washington 249.30 California 255.36 Alaska 361.65 Pacific 254.17 100 201.86 100 158.54 100 119.15 100 106.7 213.93 106 169.23 106.7 131.23 110.1 109.3 221.09 109.5 174.85 110.3 133.14 111.7 154.8 259.17 128.4 223.99 141.3 175.82 147.6 108.8 218.35 108.2 173.4 109.4 132.63 111.1 (a) U.S. Department of Labor, Bureau of Labor Statistics, Employment and Wages First Quarter, 1975, 1973, 1970 and 1965. $MWEEK 500 ni ALASKA 300 [- CALIFORNIA 200 |— PACIFIC UNITED STATES 100+ WASHINGTON | L |, | 1965 1970 1973 1975 TABLE 7.1 Average "eekly 'lage - Transportation Communications and Public Utilities 7.16 The percentage values in Tables 1 through 10 reveal an interesting trend for several of the Alaskan industries. For most of the industries such as construction, manufacturing, petroleum refining, paper, transpor- tation, communications and public utilities the Alaskan wage differential was decreasing until 1975. In 1975 the trend was reversed and the Alaskan wage differential began to increase again. (One can only speculate as to what the wage differential will be after the Alaskan economy adjusts back to a more normal status from the recent pipeline era, but it will probably decrease. ) ea TABLE A.7.1. Calculated Average Weekly Wage Per Employee By State and Region for All Industries 1965 March Ist Weekly Employment Quarter Wages Wage/Employee Region 1000 $ Million TGS a New York 5283.5 7981.4 116.20 South Dakota 85.8 96.7 86.70 Mississippi 329.2 325.3 76.01 Texas 21311 2657.6 95.93 Idaho 132.4 157.3 91.39 Colorado 410.2 546.4 102.46 Washington 673.4 975.1 111.39 Oregon 470.7 635.7 103.89 California 4609.6 7162.6 119.53 Montana V7 142.6 93.28 Hawaii 210.6 269.7 98.51 Alaska 50.0 93.1 143.23 Pacific 6014.4 9136.2 116.85 W. So. Central 3560.4 4344.4 93.86 U.S. Average 46390.0 63808.0 105.81 SOURCE: Tables C-5 and C-6, Em nd vi! Fi ; » Employment and Wages, First Quarter 7 j Dept. of Labor, Bureau of Labor eel il il ae A.7.1 TABLE A.7.2. Calculated Average Weekly Wage Per Employee By State and Region for Contract Construction 1965 March Ist eekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) ($) New York 22356 395.4 136.03 South Dakota 520) 6.6 101.54 Mississippi 23:0 24.4 81.61 Texas 166.3 214.1 99.03 Idaho 9.0 11.9 101.71 Colorado 26.8 42.3 121.41 Washington Aico 68.2 127.95 Oregon 30.9 49.9 124.22 California 309.1 592.5 147.45 Montana 8.8 11.9 104.02 Hawaii 17.4 28.7 126.88 Alaska 329) 10.7 211305 Pacific 402.2 750.1 143.46 W. So. Central 283.4 356.6 96.79 U.S. Average 2655.6 4033.1 116.82 SOURCE: Tables C-5 and C-6, Emplcyment and Wages, First Quarter 1965, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.2 TABLE A.7.3. Calculated Average Weekly Wage per Employee by State and Region for Mining Industry 1965 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) New York 8.4 17.3 158.42 South Dakota 1.6 1.8 86.54 Mississippi 5.7 8.2 110.66 Texas 107.2 189.1 113.69 Idaho 3.3 5.2 121.21 Colorado 11.4 20.2 136.30 Washington 1.8 2.9 123.93 Oregon 31.2 60.8 149.90 Montana 7.0 11.2 123.08 Hawaii 0.05 0.07 107.69 Alaska 0.9 2.3 196.58 Pacific 35.5 68.6 148.65 W. So. Central 200.0 347.3 133.58 U.S. Average 609.3 994.7 125.58 SOURCE: Tables C-5 and C-6, Emntovient aiu Wages, First Quarter 1965, U.S. Dept. of Labor, Bureau of Laver Statistics. A.7.3 TABLE A.7.4. Calculated Average Weekly Wage Per Employee ili) by State and Region for All Manufacturing 1965 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) New York 1816.7 2926.2 123.90 South Dakota 12.4 ie0 105.46 Mississippi 144.5 136.9 72.88 Texas 555m0 795.5 110.16 Idaho 30.6 40.3 ORS Colorado 82.4 132.6 123.79 Washington 213E9 361.7 130.08 Oregon 147.9 2230) 116.29 California 1370.8 2424.6 136.06 Montana 2021 29.8 114.05 Hawaii 225 27.4 93.68 Alaska 4.3 7.6 135.96 Pacific 1759.5 3045.1 133513) W. So. Central 930.4 1270.5 105.04 U.S. Average 17,656.4 26,767.1 116.62 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1965, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.4 TABLE A.7.5. Calculated Average Weekly Wage Per Employee by State and Region for Petroleum Refining and Related Industries. 1965 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) ($) New York 9.6 24.3 194.71 South Dakota - - - Mississippi 1.0 1.4 107.69 Texas 36.7 69.4 145.46 Idaho - - - Colorado 0.6 1.0 128.21 Washington 1.2 2.4 153.85 Oregon 0.3 0.5 128.21 California 29.5 64.2 167.41 Montana 1.1 2.2 153.85 Hawaii - - = Alaska - - - Pacific 31.3 67.6 166.13 W. So. Central 56.7 106.1 143.94 U.S. Average 182.4 362.5 152.88 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1965, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.5 TABLE A.7.6. Calculated Average Weekly Wage per Employee by State and Region for Paper and Allied Products 1965 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) ($) New York 65.8 102.0 119.24 South Dakota - - - Mississippi Sad 7.9 114.66 Texas 11220) 18.2 116.67 Idaho - - - Colorado 130 15 115.38 Washington 19.2 3320 132.21 Oregon Tes 12.7 133.38 California 30.0 49.3 126.14 Montana - - 126.14 Hawaii 052 0.2 76.92 Alaska esl 255 174.83 Pacific 57.7 97.7 130.25 W. So. Central 34.3 53.5 119.98 U.S. Average 629.9 991.8 Vile SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1965, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.6 TABLE A.7.7. Calculated Average Weekly Wage per Employee by State and Region for Chemicals and Allied Products 1965 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) _($ Million) ($) New York 88.2 174.2 151.93 South Dakota 0.05 0.08 123.08 Mississippi 4.8 6.3 100. 96 Texas 50.7 140.5 213.17 Idaho lz2 2.0 121.46 Colorado 1.9 3.0 121.46 Washington 8.8 ‘17.9 156.47 Oregon 1.9 2.0 80.97 California 46.6 85.0 140.31 Montana 0.4 O=7 134.62 Hawaii 0.5 0.7 107.79 Alaska 0.04 0.1 192.31 Pacific 57.8 106.7 142.00 W. So. Central 73.5 140.5 147.04 U.S. Average 896.0 1664.1 142.87 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1965, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.7 TABLE A.7.8. Region New York South Dakota Mississippi Texas Idaho Colorado Washington Oregon California Montana Hawaii Alaska Pacific W. So. Central U.S. Average SOURCE: Calculated Average Weekly Wage per Employee by State and Region for Crude Petroleum and Natural Gas Industries. March Employment (1000) 1.8 0.01 4.8 100.9 0.002 4.4 0.09 0.01 Zoe lee: 0.5 21.8 185.6 276.5 1965 Ist Weekly Quarter Wages Wage/Employee ($ Million) ($) 158 76.92 0.009 69.23 4.8 76.92 NOISS 77.38 0.003 115.38 4.4 76.92 0.09 76.92 0.007 5365 (ABC 76.92 Uz 76.92 0.6 92.31 21.9 77.28 187.1 77.54 477.3 132.79 Dest. of Labor, Bureau of Labor Statistics. A.7.8 Tables C-5 and C-6, Employment and Wages, First Quarter 1965, U.S. TABLE A.7.9. Calculated Average Weekly Wage per Employee by State and Region for Service Industry. 1965 March Ist Weekly Employment Quarter Wages Wage/Emp loyee Region (1000) ($ Million) ($) New York 699.4 916.6 100.81 South Dakota USS 55 57.96 Mississippi 23.8 16.9 54.62 Texas 23a 190.7 65.67 Idaho 17.6 Wes) 75.61 Colorado 6750 56.2 64.52 Washington 81.4 79.9 SE) Oregon 5356 47.6 83.98 California TAUQE2 929.0 99.36 Montana 1SE9 TARO 60.87 Hawaii 35.1 33750) 73.64 Alaska 5.8 S38 110.08 Pacific 895.1 1098.4 94.39 W. So. Central 364.5 302.8 63.90 U.S. Average 4398.1 5253.4 91.88 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1965, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.9 TABLE A.7.10. Calculated Average Weekly Wage per Employee by State and Region for Transportation, Communities and Public Utilities. 1965 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) ($) New York 420.0 724.4 132.67 South Dakota 7.6 10.3 104.25 Mississippi 20.4 24.9 93.89 Texas 188.5 248.6 101.45 Idaho 8.7 12.3 108.75 Colorado 327.7 567.2 133.14 Washington 46.6 79.5 131.23 Oregon 34.4 5152 127.91 California 327.7 567.2 133.14 Montana 9.6 13.5 108.17 Hawaii 15.7 24.5 120.04 Alaska 6.3 14.4 175.82 Pacific 430.8 742.8 132.63 W. So. Central 326.2 432.9 102.08 U.S. Average 3192.6 4945.2 119.15 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1965, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.10 TABLE A.7.11. Calculated Average Weekly Wage per Employee by State and Region for All Industries 1970 March Ist Weekly Employment Quarter Wages Wage/Emp loyee Region (1000) ($ Million) ($) New York 5806.4 1359252 153.57 South Dakota 100.06 138.24 106.27 Mississippi 402.05 550.16 105.26 Texas 2730.44 4565.12 128.61 Idaho 155.72 237.69 117.41 Colorado 537.42 930.35 133.16 Washington 839.97 1591.33 145.73 Oregon 550.77 937.45 130.93 California 5568.30 10,822.29 149.50 Montana 127.72 193.28 116.41 Hawaii 288.51 509.80 135.92 Alaska 67.48 170.00 193.79 Pacific 7315.03 14,030.87 147.55 W. So. Central 4425 .37 7,243.37 125.89 U.S. Average aa") 98,709.3 137.38 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1970, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.11 TABLE A.7.12. Calculated Average Weekly Wage per Employee by State and Region for Contract Construction. 1970 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) $ New York 235.56 583.62: 187.32 South Dakota 4.74 7.92 128.53 Mississippi 27.37 39.10 109.89 Texas 201.48 366.93 140.09 Idaho 9.01 18.07 154.27 Colorado 33.50 73.27 168.24 Washington 50.39 116.66 178.09 Oregon 26. 38 57.00 166.21 California 294.66 747.19 195.06 Montana 7.23 13.61 144.80 Hawaii 26.19 67.48 198.20 Alaska 5.27 21.34 311.49 Pacific 402.88 1009.66 192.78 W. So Central 323.42 583.15 138.70 U.S. Average 3097.32 6620.08 164.41 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1970, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.12 TABLE A.7.13. Calculated Average Weekly Wage per Employee by State and Region for Mining Industry. 1970 March Ist Weekly Employment Quarter Wages Wage/Emp loyee Region (1000) ($ Million) ($) New York 75 20.93 214.67 South Dakota 2.39 4.34 139.68 Mississippi 6.61 11.84 137.79 Texas 100.16 234.78 180.31 Idaho Bulge 6.91 160.10 Colorado 13.67 33.72 189.75 Washington 1257 3.42 167.56 Oregon 1.19 2.34 151.26 California 31.51 81.84 199.79 Montana 6.12 12.77 160.51 Hawaii - - - Alaska 3.37 13.44 306.78 Pacific 37.68 101.134 206.46 W. So. Central 192.92 449.17 179.94 U.S. Average 603.64 1341.78 170.99 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1970, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.13 TABLE A.7.14. Calculated Average Weekly Wage per Employee by State and Region for Manufacturing 1970 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million), ($) New York 1817.4 3876.2 164.06 South Dakota 14.97 25.02 128.56 Mississippi 179.05 239.82 103.03 Texas 749.63 1395.68 143.22 Idaho 38.39 64.19 128.62 Colorado 114.10 231.86 156.31 Washington 248.71 570.18 176.36 Oregon 166.68 324.94 149.96 California 1598.47 3565.71 171.59 Montana 22553) 39.61 135.24 Hawaii 23.79 40.94 132.38 Alaska 6.04 133159) 173.08 Pacific - - - W. So. Central 1220.08 ZU Alis 32 136.90 U.S. Average. 1984] .] 3e020.U0 149.84 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1970, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.14 TABLE A.7.15. Calculated Average Weekly Wage per Employee by State and Region for Petroleum Refining and Related Industry. 197 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) $ New York 10.8 3720 263.5 South Dakota N.D. N.D. - Mississippi 1.3 2.5 147.9 Texas 38.1 98.0 197.9 Idaho - - - Colorado 0.8 Hii) 144.2 Washington Tae 2.8 179.5 Oregon 0.5 0.9 138.5 California 30.4 84.7 214.3 Montana lier 230 174.8 Hawaii 0.38 At 222.7 Alaska 0.05 0.19 292.3 Pacific 32.5 89.7 212.3 W. So. Central 58.8 147.1 192.4 U.S. Average 192.06 492.9 197.4 SOURCE: Tables C-5 and.C-6, Employment and Wages, First Quarter 1970, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.15 TABLE A.7.16. Calculated Average Weekly Wage per Employee by State and Region for Paper and Allied Products 1970 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) New York 64.7 127.3 151.35 South Dakota - - - Mississippi 7.2 14.4 153.85 Texas 17.2 31.9 142.67 Idaho 1.0 2.08 160.8 Colorado 1.3 2.3 136.10 Washington 19.5 43.0 169.63 Oregon 9.2 21.5 179.80 California 36.4 75.8 160.19 Montana - - - Hawaii 0.2 0.3 115.38 Alaska 1.0 305 269.23 Pacific 66.3 144.1 167.11 W. So. Central 44.0 88.2 154.20 U.S. Average 710.9 1444.6 156.31 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1970, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.16 TABLE A.7.17. Calculated Average Weekly Wage per Employee by State and Region for Chemicals and Allied Products. 1970 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) $ New York O17 234.6 196.8 South Dakota - - - Mississippi Se 9.3 130.07 Texas 65.1 161.7 191.07 Idaho lis Sue 164.10 Colorado (268) 4.7 157.19 Washongton 6.1 St 190.42 Oregon 2.9 4.8 27232 California 56.2 126.5 173.15 Montana 0.4 0.7 134.62 Hawaii 0.6 1.2 153.85 Alaska 0.205 0.834 312.95 Pacific 65.4 148.4 174.55 W. So. Central 95.4 236.3 190.53 U.S. Average 1064.0 2511.7 181.59 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1970, U.S. Dept. of Labor, Bureau of Labor Statistics. L\er/olW/ TABLE A.7.18. Calculated Average Weekly Wage per Employee by State and Region for Crude Petroleum and Natural Gas. 1970 March Ist Weekly Employment Quarter Wages Wage/Emp loyee Region (1000) ($ Million) ($) New York 1.3 4.5 289.94 South Dakota - i = Mississippi 5.8 10.9 187.93 Texas 93.6 222.7 183.02 Idaho - - - Colorado 6.2 1/52 213.40 Washington - - - Oregon - - - California 21.1 55.5 202.33 Montana Vee: 3.8 171.95 Hawaii - - - Alaska - - - Pacific - - ~ W. So. Central 177.6 422.1 237.67 U.S. Average 263.5 621.2 181.35 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1970, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.18 TABLE A.7.19. Calculated Average Weekly Wage per Employee by State and Region for Services. 1970 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) — $ New York 865.3 1486.8 132.17 South Dakota 11.9 11.1 71.75 Mississippi 31.9 34.3 107.52 Texas 335.4 421.8 96.74 Idaho 21.6 26.7 95.09 Colorado 93.5 110.9 91.24 Washington 117.9 156.2 101.91 Oregon 72.7 82.5 87.29 California 975.7 1573.5 124.05 Montana 1723 16.9 75.14 Hawaii 54.7 70.9 99.70 Alaska 9.7 18.3 145.12 Pacific 1230.8 1901.3 118.83 W. So. Central 526.4 636.4 121.13 U.S. Average 6688.6 9568.2 110.04 SGURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1970, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.19 TABLE A.7.20. Calculated Average Weekly Wage per Employee by State and Region for Transportation, Communications and Public Utilities. 1970 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Mil lion) New York 463.6 1095.4 181.8 South Dakota 8.6 14.2 127.0 Mississippi 24.1 39.8 127.0 Texas 219.1 413.8 145.3 Idaho 9.9 17.4 Ws5e2 Colorado 43.4 90.5 160.0 Washington 59.7 131.2 169.1 Oregon 38.8 81.4 161.4 California 410.1 932.1 174.8 Montana Os) 18.5 138.2 Hawaii 23.4 48.2 158.5 Alaska 8.5 24.8 224.4 Pacific 540.4 1217.8 173.4 W. So. Central 373.9 700.6 144.14 U.S. Average 3797.3 7826.1 158.5 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1970, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.20 TABLE A.7.21. Calculated Average Weekly Wage per Employee by State and Region for All Industries. 1973 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) New York 6073.0 14,613.00 185.09 South Dakota 146.0 227.0 119.60 Mississippi 548.0 865.0 121.42 Texas 3504.0 6583.0 144.52 Idaho 201.0 356.0 136.24 Colorado 764.0 1552.0 156.26 Washington 961.0 2097.0 167.85 Oregon 674.0 1368.0 156.13 California 6513.0 14,755.0 174.27 Montana 165.0 291.0 135.66 Hawaii 331.1 668.31 155.27 Alaska 79.76 222.75 214.83 Pacific 8558.5 19,131.3 171.95 W. So. Central 5712.0 10;545.0 142.01 U.S. Average 65,742.0 137,786.0 161.22 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1973, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.2] TABLE A.7.22. Calculated Average Weekly Wage per Employee by State and Region for Contract Construction. 1973 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) ($) New York 252.2 781.6 238.39 South Dakota 8.03 15.25 146.09 Mississippi 38.65 60.06 119.53 Texas 260.8 510.8 150.66 Idaho 12.2 27.5 173.39 Colorado 66.1 158.0 183.87 Washington 51.9 138.8 205.72 Oregon 36.3 89.2 189.02 California 302.0 867.2 220.89 Montana 11.1 23.4 162.16 Hawaii 25.6 80.1 240.69 Alaska 5.18 21.31 316.45 Pacific 421.0 1196.6 218.64 W. So. Central 413.57 809.19 150.51 U.S. Average 3705.4 9146.3 189.87 SOURCE: Tables C-5 and C-6, Employinent and Wages, First Quarter 1973, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.22 TABLE A.7.23. Region New York South Dakota Mississippi Texas Idaho Colorado Washington Oregon California Montana Hawaii Alaska Pacific W. So. Central U.S. Average SOURCE : Calculated Average Weekly Wage per Employee by State and Region for Mining. March Employment (1000) 7 2 6.4 0 2.65 IWsa72 ley 1.54 29.55 6.08 1.807 34.65 197.3 622.5 Tables C-5 and C-6, Employment and Wa 1973 Ist Quarter Wages ($ Million) 29.1 5.7 S335) 299.6 7.18 42.18 4.55 In 92 93.65 16.13 8.36 110.54 547.18 1702.6 Dept. of Labor, Bureau of Labor Statistics. A.7.23 Weekly Wage/Employee 290. 199. 162. -49 219 208. 236. 202. 195. 243. 204. 355: 245. alas 210. 7] 30 26 51 49 31 80 78 21 88 40 33 39 ges, First Quarter 1973, U.S. TABLE A.7.24. Calculated Average Weekly Wage per Employee by State and Region for Manufacturing. 1973 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) $ New York 1618.7 4219.8 200.53 South Dakota 18.7 36.0 148.09 Mississippi 216.5 349.6 124.21 Texas 780.6 1690.6 166.6 Idaho 44.7 90.7 156.08 Colorado ste 334.7 187.65 Washington 235.0 626.6 205.11 Oregon 185.9 439.8 181.98 California 1592.6 4073.6 196.76 Montana 23.4 51.3 168.64 Hawaii 22.94 46.11 154.62 Alaska 7.60 18.38 186.03 Pacific - - - W. So. Central 1308.4 2712.4 159.47 U.S. Average 19,907.8 47118.1 182.06 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1973, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.24 TABLE A.7.25. Calculated Average Weekly Wage per Employee by State and Region for Petroleum Refining and Related Products. 1973 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) $ New York 10.3 a7 351.76 South Dakota 0.15 0.43 220.51 Mississippi 1.4 3.8 208.79 Texas 36.6 116.7 245.27 Idaho - - - Colorado 0.54 539 198.01 Washington 1.39 5.05 279.47 Oregon 0.65 1.47 173.96 California 24.5 86.7 272.21 Montana eal S55 230.77 Hawaii 0.43 1.46 260.57 Alaska 0.049 0.212 332.81 Pacific 27.04 94.9 269.97 W. South Central STA 174.2 234.68 U.S. Average 190.0 604.8 244.86 SOURCE: Tables C-5 and C-6 Employment and Wages, Fir i 2 rd Wy st Quarter 197 ae Dept. of Labor, Bureau of Labor Statistics. ; il aii A.7.25 TABLE A.7.26. Calculated Average Weekly Wage per Employee by State and Region for Paper ana Allied Products. 1973 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) ($) New York 54.46 ciiee! 185.60 South Dakota - - - Mississippi 46.5 1551 190.41 Texas We 41.5 182.42 Idaho 1.109 2.611 181.11 Colorado 1152 3.208 162.35 Washington 17.36 50.7 224.65 Oregon 9.4 225 223.00 California 35.4 92.68 201.39 Montana - = = Hawaii 0.271 0.547 155.27 Alaska 1.008 4.19 319.75 Pacific 63.44 WHSs35 212.62 W. So. Central 47.4 117.9 191.33 U.S. Average 705.64 1764.2 192.32 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1973, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.26 TABLE A.7.27. Calculated Average Weekly Wage per Employee by State and Region for Chemicals and Allied Products. 1973 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) WG Million) — ($) New York 78.2 245.1 241.10 South Dakota - - - Mississippi 5.8 12.4 213.80 Texas 62.0 196.5 243.80 Idaho 1.7 4.8 217.20 Colorado sie. 5.6 195.80 Washington 5.5 16.2 226.57 Oregon 2a 5.5 201.47 California 53.1 144.4 209.20 Montana 0.4 1.0 192.30 Hawaii 0.665 1.51 174.67 Alaska 0.181 0.867 368.47 Pacific 61.6 168.45 210.30 W. So. Central 93.8 293.6 240.77 U.S. Average 1035.8 3003.7 223.10 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1973, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.27 TABLE A.7.28. Calculated Average Weekly Wage per Employee by State and Region for Crude Petroleum and Natural Gas. 1973 March Ist Weekly Employment Quarter Wages Wage/Employment Region (1000) ($ Million) ($) New York 1.96 11.2 439.56 South Dakota - - - Mississippi 53 11.7 169.81 Texas 98.95 285.94 222.74 Idaho - - - Colorado 6.7 21.9 251.44 Washington - - - Oregon - - - California 20.2 65.66 250.04 Montana 1.4 3.8 208.79 Hawaii - - - Alaska 21.9 73.4 257.82 Pacific - - - W. So. Central 183.84 517.17 216.40 U.S. Average 268.27 749.3 214.85 SURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1973, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.28 TABLE A.7.29. Calculated Average Weekly Wage per Employee by State and Region for Services. 1973 March Ist Weekly Employment Quarter Wages Wage/Employment Region (1000) ($ Million) ($) New York 1313.91 2711.29 158.73 South Dakota 31.19 33.80 83. 36 Mississippi 65.72 82.47 96.53 Texas 579.51 829.10 110.05 Idaho 33.95 50.42 114.24 Colorado 149.28 226.69 116.81 Washington 170.24 269.2 121.64 Oregon 113.73 162.3 109.77 California 1295.00 2446.96 145.35 Montana 33.13 40.21 93.36 Hawaii 68.0 107.10 121.15 Alaska 13.50 29.25 166.67 Pacific 1660.5 3014.8 139.66 W. So. Central 907.73 1277.66 108.27 U.S. Average 11,245.3 18,832.1 128.82 SOURCE: Tables C-5 and C-6,: Employment and Wages, First Quarter 1973, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.29 TABLE A.7.30. Region New York South Dakota Mississippi Texas Idaho Colorado Washington Oregon California Montana Hawaii Alaska Pacific W. So. Central U.S. Average Calculated Average Weekly Wage per Employee by State and Region for Transportation, Communications and Public Utilities March Employment (1000) 443. 10. 30. 244, Ae 50. 59. 42. 417. 6 1 24. 9. 409. 4029. 3 48 64 84 62 93 02 42 13 84 02 5 2 1973 Ist Weekly Quarter Wages Wage/Employment _($ Million) ($) 1323.6 229.68 21.66 158.98 60.86 152.79 571.32 179.50 24.68 163.38 139.5 210.70 164.14 213.93 109.60 198.75 1198.92 221.09 2519 169.10 65.05 201.44 30.39 259.17 956.17 179.61 10,573.4 201.86 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 19/73, U Dept. of Labor, Bureau of Labor Statistics. A.7.30 S TABLE A.7.31. Region New York South Dakota Mississippi Texas Idaho Colorado Washington Oregon California Montana Hawaii Alaska Pacific W. So. Central U.S. Average SOURCE: Calculated Average Weekly Wage per Employee by State and Region for all Industries. March Employment (1000) 5758.0 159.0 535.0 3758.0 218. TIS 1024. 761. 6717. ooo°o°o 341.0 120.0 8963.0 6064.0 66,588.0 1975 Ist Quarter Wages ($ Million) 15,941.0 299.0 1913.0 8547.0 454.0 1839 2612.0 1767.0 17,313.0 799.0 510.0 23,000.0 13,530.0 161,288.0 Dept. of Labor, Bureau of Labor Statistics. A.7.31 Weekly ee 212.96 144.37 145.65 174.95 160.44 182.57 196.25 178.51 198.27 180.28 326.13 197.39 171.64 186.30 Tables C-5 and C-6, Employment and Wages, First Quarter 1975, U.S. TABLE A.7.32. Region New York South Dakota Mississippi Texas Idaho Colorado Washington Oregon California Montana Hawaii Alsaka Pacific W. So. Central U.S. Average SOURCE : Calculated Average Weekly Wage per Employee by State and Region for Contract Construction. March Employment (1000) 193. Ts 36. 278. woo - ese 45. Uc 30. 268. 10. —- nwo wy Oo ie 5 20.2 397.6 444.2 3240.2 1975 Ist Quarter Wages ($ Million) 662.3 19. 74, 718. wo oO - 36. Ueki 163. 94. 954. 27. ann O MY fF OO 94. 115522 Oo 1462.0 1125.5 9674.4 Dept. of Labor, Bureau of Labor Statistics. Aoiese Weekly 263. -90 64 198. 188 157 217 273 262. -01 591 282. 91 229° 194 Wage/Employee 42 7) 3/5 230. 245. 240. sol 210. 43 67 92 21 94 85 67 Tables C-5 and C-6, Employment and Wages, First Quarter 1975, U.S. WABLEERAR nr 33s Region New York South Dakota Mississippi Texas Idaho Colorado Washington Oregon California Montana Alaska Pacific W. So. Central U.S. Average SOURCE: Calculated Average Weekly Wage per Employee by State and Region for Mining. March 1975 Employment (1000) 7734.0 Cad 6.6 132.9 3.56 ISe3 1.8 1.4 See, 6.9 4.0 39.454 237.87 Tore Ist Quarter Wages ($ Million) 34.5 6.6 17.0 476.1 10.4 68.104 5.89 4.05 123.4 22.98 26. 159.338 833.3 2544.0 Dept. of Labor, Bureau of Labor Statistics. A.7.33 Weekly Wage/Employee 343.48 ZN Sol 199.35 275.63 224.91 286.52 251.93 216.04 294.44 254.56 502.68 310.66 269.49 266.13 Tables C-5 and C-6, Employment and Wages, First Quarter 1975, U.S. TABLE A.7.34. Calculated Average Weekly Wage per Employee by State and Region for Manufacturing 1975 March Ist Weekly Employment Quarter Wages Wage/Employee Region _(1000) ($ Million) New York 1418.8 4425.0 239.91 South Dakota 18.9 43.1 75242 Mississippi 190.1 374.0 S32 Texas 792.6 2099.5 203.76 Idaho 44.1 105.0 183.15 Colorado 1332 394.0 227.54 Washington 239.9 763.5 244.81 Oregon Al) 469.5 eleZzo California 1552.2 4668.7 231537) Montana 20), 54.7 2035127) Hawaii 23eil 56.3 187.48 Alaska 7.0 24.3 267.03 Pacific 1993.2 5982.2 230.87 W. So. Central 1286.2 3274.5 195.84 U.S. Average 18102.2 50,649.8 25323 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1975, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.34 TABLE A.7.35. Calculated Average Weekly Wage per Employee by State and Region for Petroleum Refining. 1975 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) New York 10.0 58.4 449.23 South Dakota 0.2 0.6 230.77 Mississippi jo 5.5 282.05 Texas 36.3 145.7 308.75 Idaho 0.001 0.005 384.62 Colorado 0.6 1.9 243.59 Washington 1.9 7.8 315.80 Oregon 0.5 1.4 215.38 California 25.3 116.8 355.12 Montana 0.9 3.16 307.69 Hawaii 0.5 1.9 292.31 Alaska 0.06 0.3 384.62 Pacific 28.2 128.1 349.43 W. So. Central 56.1 217.5 298.23 U.S. Average 188.3 757.2 309.33 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1975, U.S. Dept. of Labor, Bureau of Lahor Statistics. A.7.35 TABLE A.7.36. Calculated Average Weekly Wage per Employee by State and Region for Paper and Allied Products. 1975 March Ist Weekly Employment Quarter Wages Wage/Emp loyee Region (1000) ($ Million) $ New York 46.8 134.7 221.40 South Dakota 0. 04 0.2 384.62 Mississippi 6.3 18.6 227.11 Texas 16.7 48.2 222.02 Idaho 1.0 3.5 269.23 Colorado 1.5 ol 210.26 Washington 16.8 58.4 267.40 Oregon 9.5 32.2 260.73 California 34.4 104.7 234.12 Montana - - - Hawaii 0.3 0.7 179.49 Alaska 1.2 5.8 371.79 Pacific 62.2 201.8 249.57 W. So. Central 43.8 129.8 227.96 U.S. Average 629.2 1900.8 232.38 First Quarter 1975, U.S. : Tables C-5 and C-6, Employment and Wages, SOURCE Dept. of Labor, Bureau of Labor Statistics. A.7.36 TABLE A.7.37. Calculated Average Weekly Wage per Employee by State and Region for Chemicals and Allied Products. 1975 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) — ($) New York 73.8 275.9 287.58 South Dakota 0.2 0.4 153.85 Mississippi 6.7 17.6 202.07 Texas 67.4 256.1 292.28 Idaho 2.2 7.5 262.24 Colorado 5.2 16.9 250.00 Washington 6.2 23 264.27 Oregon 2.1 6.6 241.76 California 56.3 177.4 242.38 Montana 0.5 1.6 246.15 Hawaii 0.7 2.1 230.77 Alaska 0.2 1.3 500.00 Pacific 65.5 208.7 245.10 W. So. Central 102.4 386.1 290.04 U.S. Average 1031.0 3608.2 269.21 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1975, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.37 TABLE A.7.38. Calculated Average Weekly Wage per Employee by State and Region for Crude Petroleum and Natural Gas. 1975 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) ($) New York 2=2 13.6 475.52 South Dakota 0.04 0.1 192.31 Mississippi 55 14.8 210.83 Texas 126.2 458.2 279.29 Idaho 0.02 6.04 153.85 Colorado 8.6 34.6 309.48 Washington 0.06 0.2 256.41 Oregon 0.007 0.02 219.78 California 23.4 92.3 303.42 Montana 2.0 6.2 238.46 Hawaii - - - Alaska 3.8 25.0 506.07 Pacific N.D. N.D. W. So. Central 223.5 794.1 273.31 U.S. Average 326.8 1154.6 271.77 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1975, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.38 TABLE A.7.39. Calculated Average Weekly Wage per Employee by State and Region for Service. 1975 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) New York 1356.7 seule 182.07 South Dakota 34.2 44.6 100.31 Mississippi 72.0 107.9 115.28 Texas 655.4 S33) 135.36 Idaho 38.7 69.2 137.55 Colorado 165.0 306.2 142.75 Washington 193.5 364.7 144.98 Oregon 123.0 a3 134.02 California 1403.2 3060.1 167.75 Montana 3729 53.9 109.40 Hawaii 67.1 121.2 138.94 Alaska 21.9 70.5 247.63 Pacific 1808.8 3830.8 162.91 W. So. Central 1019.6 1745.4 131.68 U.S. Average 12,146.7 23,833.6 150.93 SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1975, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.39 TABLE A.7.40. Calculated Average Weekly Wage per Employee by State and Region for Transportation, Communications and Public Utility. 1975 March Ist Weekly Employment Quarter Wages Wage/Employee Region (1000) ($ Million) $ New York 409.8 1453.2 272.78 South Dakota 10.9 Z26n3) 185.60 Mississippi 30.4 72.4 183.20 Texas 260.8 iow) 210.98 Idaho 1235 Sie 192.00 Colorado 527, 163.4 238.51 Washington 60.2 195.1 249 .30 Oregon 41.3 23a 229.28 California 419.1 NSIS 255.36 Montana 12.4 S9 197.89 Hawaii 2547, i) 22718 Alaska 14.4 G70, 361.65 Pacific 560.8 1853.0 254.17 W. So. Central 435.5 1188.7 209.96 U.S. Average 3973.9 12,065.3 233555) SOURCE: Tables C-5 and C-6, Employment and Wages, First Quarter 1975, U.S. Dept. of Labor, Bureau of Labor Statistics. A.7.40 8.0 ECONOMIC FACTORS OF PRODUCTION AND MARKETS FOR ALASKA'S ENERGY INTENSIVE INDUSTRIES 8.1 ECONOMIC FACTORS OF PRODUCTION The usual factors of production are raw materials (including energy), land, labor, and capital. In the U.S. these factors of production must be combined in a manner which results in production of products which can be sold in competitive markets. The market price must also be sufficient to include a profit which is required to offset potential risks and provide investors with appropriate incentives. Existing markets will usually deter- mine what the market price is and in turn, firms that can sell their prod- ucts at that price usually obtain a share of the market. The process is dynamic however, and as a new firm enters the market, the market price has a tendency to fall as more products are offered; i.e., as supply increases, the price declines in order to clear the market of available supply. New firms or industries desiring to locate or expand existing firms in Alaska will face these same economic facts. They will have to find the appro- priate combination of production factors (raw materials, land, labor, energy, and capital) which will allow them to produce their products at a competi- tive price. The existance of profitable firms in Alaska obviously verifies the fact that this is possible for some industries; e.g., pulp, fish pro- cessing, forest products, and fertilizer production. The challenge before Alaska, assuming it desires new and expanded industries, is to identify the appropriate combination of production factors given potential markets for Alaskan products. In addition, each geographic region usually has some unique, economic advantage ‘over other areas; e.g., Alaska has a latent sup- ply of raw materials, energy, and is close to Asian markets. The challenge is to identify these unique economic advantages and then capitalize on them. Industrial managers have an ability to identify these unique advan- tages which are not always apparent to the lay person. They will then capitalize on the advantages assuming appropriate incentives are foresee- able. For Alaska, this may require some deviations from past operating practices and some untried combinations of production factors may also be reauired. This may be necessary if Alaskan industries are to be competitive: e.g., more capital might be required as a substitute for relatively costly 8.1 Alaskan labor. In addition, Alaska may find that its primary markets are in the Pacific Rim, Japan for example, and not the lower 48 states. A cur- sory evaluation of logical candidates is necessary to identify the probable industries and most attractive markets. A detailed analysis of the probable industries should then be completed to identify the more feasible opportunities. The fact is that industries locating in Alaska must be able to compete in either the intrastate market, the “export markets" (the other 49 states and foreign countries) or both if they are to survive. In order to compete, Alaskan industry must find a cost advantage as was stated earlier. The market clearing price or market price will be essentially the same for each product independent of where they are produced. The cost of each item or factor of production may vary, however, dependent upon the site. The major cost items for any producer will be: 1) labor, 2) energy, 3) raw materials, and 4) capital (investment). A competitive Alaskan producer must combine these items in a manner such that he is competitive; i.e., his tota? production costs are less than or equal to his competitors within and outside of the State. (The non-Alaskan producer will also have the cost of transporting his products to Alaska.) Therefore, if the Alaskan producer can produce a Product at the same cost as a non-Alaskan producer, the Alaskan producer can become the price setter as he has an advantage over the foreign or non- Alaskan producer; i.e., the cost of transporting products to Alaska. Similarly, for the Alaskan export market Alaskan producers must be competitive if they wish to compete in foreign markets. This time, however, the Alaskan producer will have the additional transportation cost as compared to the overseas domestic producer. This should be possible for some Alaskan products and markets. A likely product might be aluminum produced in Alaska and sold in Japan. For some cases such as mining, the location of a plant is almost dic- tated by the presence of the ore independent of other factors of production. For example, ore processing plants (concentrators) are usually at the mine independent of the cost of labor, land, etc., at the mine site. The concentrator is located at the mine because the cost of transporting the ore to another site would be overwhelming. The most economical arrangement is to move 8.2 workers to the mine site, concentrate the ore, and ship the concentrates to a smelter while leaving the tailings at the mine. This is a simplistic example, but others exist for most regions including Alaska. Identifying other examples with appropriate markets should be achievable. Two other factors apparently or potentially available in Alaska may also influence the location of new industries in Alaska. The first is an apparent hospitality for new industry and the second is a large, potential supply of energy, both fossil and potential hydro; e.g., the Upper Susitna River. For example, these two factors might be sufficient to attract an aluminum reduction plant to Alaska. 8.2 THE ALUMINUM INDUSTRY AND JAPANESE markets (1) The aluminum industry has been attempting since 1966 to locate a new plant in the Pacific Northwest and has not been totally successful to date. For example, Alumax Pacific Corporation proposed to build a new aluminum reduction plant in the Pacific Northwest. They attempted to locate the plant in Warrenton, Oregon, but failed to gain the necessary permits. More recently, Alumas proposed to relocate the plant to McNary, Oregon. The necessary permits have been delayed and construction is still pending. In addition, the Bonneville Power Authority has notified the existing aluminum industry that when their current contracts expire, they will not be renewed. Any new contracts, if granted, will certainly be at a greater cost, as the existing hydro generating capacity in the Pacific Northwest is essentially fully utilized. A power contract is especially important to an aluminum reduction plant. These plants consume large quantities of electric energy (5 to 8 kWh/1b of product depending upon the process utilized). The cost of a relatively uninterrupted supply of this power is also important. For example, using 25 mil power, the electrical costs will be $0.12 to $0.20/1b and for 60 mil power the electrical energy costs will be $0.30 to $0.48/1b. Ata U.S. market price of $0.45/1b, one can see that the cost of power accounts for at least 25% of the production costs in the U.S. (using 25 mil power) but greater than two-thirds of the production cost using 60 mil power. (1) A more detailed evaluation of this aluminum industry is provided in Volume II of this report series. 823 The availability and cost of power have been the primary factor in siting an aluminum reduction plant, assuming a permit can be obtained. These recent problems with plant siting and inadequate future power supply tend to make Alaskan sites more attractive. An Alaskan site could be competitive assuming electric power is avail- able at a competitive price offsetting higher construction and operating costs. Given a low cost power supply, a primary aluminum smelter may be one of those industries which could be sited in Alaska independent of the costs of other factors; e.g., labor rates. An Alaskan plant would have to compete with aluminum reduction plants in the lower 48 states and other countries. Domestic siting competition appears to be diminishing however, as new plants are not moving forward, and the cost of electrical energy in other regions will probably escalate more rapidly than in Alaska due to Alaska's abundance of 011, coal, and gas resources. An Alaskan plant should also find a market in Japan and have an advan- tage over Japanese plants. Currently, Japan imports approximately 550,000 tons of aluminum ingot annually. Their total consumption is nearly 2 million tons per year and grew at 8%/yr during the early 1970's. The growth rate slowed during the recent recession but has begun to recover and could approach 6 to 8% again. Most areas such as Alaska should have less costly energy than Japan as their industrial energy costs are reported to be approaching 60 mills/kWh. Thus, if an Alaskan reduction plant could obtain power at even 25 mills/kWh, they should be more than competitive with Japanese aluminum industry. Because of energy costs, Japan should prefer to import more aluminum and produce less with their relatively expensive energy. The transportation costs to Japan should not cause a problem as they are estimated to be approximately $0.01/1b against a current domestic (U.S.) selling price of $0.56/1b. Thus, the transportation costs of shipping aluminum to Japan in foreign vessels will be almost insignificant. 8.4 More detailed analysis is admittedly necessary to quantify the appar- ent competitiveness of an Alaskan aluminum reduction plant designed to sup- ply the Japanese markets. Additional analysis is also needed to identify other industries where Alaska has a unique advantage due to its availability of energy and natural resources. Alaska's proximity to Japan and the Pacific Rim is an advantage for Alaska's industry and trade with this region should continue to expand. Recently, trade relations with Japan have continued to improve and Japan now has a stronger desire to import U.S. products. Some of the reasons why Japan has and will continue to increase her imports from the U.S. and Alaska are: © In 1977, Japan had a $7.3 billion surplus of trade with the U.S. Japan is now being pressured to reduce this surplus and increase her imports of U.S. goods. As a result, the Japanese Government has relaxed import controls and is now encouraging increased imports and more foreign investments. Japan is almost totally dependent upon imports for natural resources such as energy and minerals. They prefer to have several sources for each commodity as opposed to a few. Alaska could become a more impor- tant supplier and currently supplies natural gas, logs, pulp, urea, and fishery products to Japan in significant quantities. Japan is desperately short of land for industrial parks. Thus, they are investing in new plants in foreign countries and may wish to invest more in Alaska. To date, they have made major investments in the Kenai ammonia/urea and gas liquefaction plants and the pulp mill. Japan's labor forces, though currently experiencing high unemployment, may recover in the near future and Japan's industry may increase abroad to gain access to the necessary labor. 8.5 9.0 ENERGY INTENSIVE INDUSTRY SCREENING AND EVALUATION 9.1 INTRODUCTION The definition of “energy intensive industries" is to some extent subjective but is usually thought to imply a high ratio of energy (Btus) input per unit of production. The energy input can be construed as including both raw material energy content (e.g., oi], natural gas, coke, oxygen, etc.) where the feed stock itself has an intrinsic energy energy content) or as applied process energy. Aluminum is an example of the latter case where electric power is used in the electrochemical reduction process and results in the most energy intensive material pro- duct on a weight basis. Table 9.1 summarizes the 17 most energy inten- sive products currently produced by U.S. industries. The basic characteristics of energy intensive industries that would tend to locate in Alaska as opposed to other locations are: 1) The product is produced in large volumes by world scale facilities and can readily be shipped in bulk form. This has a tendency to overcome the cost of transportation disadvantage associated with Alaska's remoteness from major markets. 2) Energy as a factor in production should be a large fraction of the total production cost, hence decreasing the significance of the other factors such as labor and capital charges. 3) The labor cost contribution to the total cost should be low to help offset the higher cost of labor in the State. This suggests that the industries that may be attracted are those that can be highly automated and generally use continuous as opposed to batch processes. 4) The industry should be a primary industry, i.e., its products should not be dependent upon the availability of intermediates that might have to be imported into the State in order to produce the finished product. In addition, the process should 9.1 2°6 TABLE 9.1. Energy Intensive Industrial Products Total Annual Energy Consumption Value Energy Consumption Production in Product in BTU/Pound $/Pound in BTU/$ Product 102 Pounds Aluminum) 122,000 0.447 272,930 9.06 Phosphorus (4) 86,000 0.66 130,303 1.05 Copper!” 56,000 0.70 80,000 3.74 Carbon Black (>) 21,430 0.12 178,580 3.50 Ethylene (>) 31,250 0.13 240,384 22.4 Ammonia 19,500 0.12 162,500 64.0 Paper 16,130 -- -- 124.0 Methanol (©) 16,100 0.076 211,842 6.8 Caustic Soda 14,950 0.25 59,800 23.1 Ethy1benzene ©) 14,460 = 7 6.5 Styrene (©) 13,000 0.21 61,904 6.0 steel (4) 12,000 0.15 80,000 256.0 Chlorine 10,350 0.073 141,780 20.6 Glass (4) 8,800 -- = 25.0 Lime‘) 4,250 0.0145 293,100 42.2 Portland Cement!) 3,800 0.0160 237 ,500 171.0 Petroleum Refining ©) 2,074 0.053 39,130 1,350.0 (a) Includes all energy from ore mining through smelting and refining of products. (b) Includes energy in feed material, plus process energy requirements. (c) Process energy requirements only, feed material not included. be such that few if any by-products are produced, particularly those that cannot be marketed directly but require additional upgrading or combination with other materials not readily available. The criteria of energy intensiveness listed as Number 2 above is particularly important to this analysis. Although the energy inten- siveness measurement of Btu/1b of product is significant, a more appro- priate measure appears to be the ratio of Btu/$ value. Given comparable production cost contributions for other factors of production and trans- portation of products, this ratio appears to capture most of the attrac- tive aspects of a lower cost energy region better than the Btu/1b ratio. Thus column 4 in Table 9.1 presents the ratio of Btu's of input energy to the current domestic value of product. Aside from meeting intrastate demands for energy products, the industrial utilization of energy can be thought of as a means of con- verting the energy into an alternative product form, e.g., conversion of energy equivalents into pounds of product. Thus Alaska as an energy resource-ricn state can export Btu's as might be represented by barrels of oi], or it can export the equivalent amount in terms of a product such as aluminum ingots or slabs. With the exception of ethylene, all of the products listed in Table 9.1 are produced in large scale and suitable for bulk shipment and at comparable rates per ton. Thus those industries whose products contain the highest ratios of Btu per dollar of product value will be the most likely attracted to regions with low delivered energy costs assuming other costs are not significantly different from those in alternative locations. Thus, from Table 9.1 the industries most likely to be attracted to the energy resource area are, in order of merit: 9.3 1. Lime 6. Ammonia 2. Aluminum 7. Chlorine 3. Portland Cement 8. Phosphorus 4. Methanol 9. Steel 5. Carbon Black 10. Copper Steel, copper, and phosphorus can be eliminated from the above list as there are currently no sources of nonenergy raw materials in the State that can compete with other lower cost domestic sources, i.e., the cost of importing raw materials into Alaska coupled with the cost of export- ing the finished product will preclude development until such time as raw material sources within the State are opened up. Due to a variety of market and institutional factors such as the D-2 lands debate, such is not expected within the next 10 to 15 years. In addition, the market for these products within the State is not sufficient to support the scale of industrial development necessary for competitive plants and essentially all products would have to be exported. Although importing alumina would be necessary for support of an aluminum reduction plant, over 80% of the U.S. domestic supply is already based upon foreign imports from Australia, Jamaica, Surinam, and the Dominican Republic; and Alaska should not be seriously disadvantaged although the intrastate market for aluminum will not support a competi- tively scaled plant. Aluminum reduction is so strongly dependent upon low cost hydroelectric power, costs of product export are not a major inhibitor. Carbon black, primarily used in the manufacture of motor vehicle tires, does not appear attractive as the product is bulky and the major market is in the interior U.S. and would entail the additional rail freight cost. Lime and Portland cement are two products which have a significant intrastate market in support of construction projects. Successful development of these industries could result in reduced costs of con- struction in Alaska and, in turn, reduce the currently high cost of 9.4 capital facilities that inhibit other industries which might otherwise be located in the State. These two products are literally and figuratively the foundation for other industrial developments. Construction of the Upper Susitna hydroelectric products alone could require a major Portland cement plant. Ammonia and its natural coproduct urea production have already attracted to the State the world scale plants based on very low cost natural gas then available from the Cook Inlet region. Elemental phosphorus is not a primary industry in that it must be preceded by a phosphorus acid process based on phosphate rock for which Lower 48 domestic supplies are plentiful and closer to the agricul- tural markets. The petrochemicals industry is of great current interest in Alaska due to the possible availability of natural gas and liquids from future North Slope natural gas production and a proposal for processing the 12-1/2% royalty fraction of the North Slope oil production through a major petrochemical facility to be located in the State with products to be marketed largely in Japan. The above industries are discussed and evaluated in the following pages. 9.5 9.2 THE ALUMINUM METAL INDUSTRY Aluminum is the most prevalent metallic element in the earth's crust. Furthermore, it ranks as the third most prevalent among all of the ele- ments of the earth's crust being exceeded only by the elements oxygen and silicon. However, it never exists naturally as the free metallic material, it being always in compound form mainly as oxide and silicates. Although there are many important large-scale uses for processed aluminum compounds in the form of pulp and paper chemicals, refractories, abrasives and water treatment chemicals as well as unprocessed compounds in the form of Port- land cement and clay ceramics, the demands for the pure and alloyed metal exceeds that of all of the processed compounds. The remainder of this summary is concerned with a discussion of aluminum in metallic form. In the following, therefore, whenever aluminum is mentioned it is considered to be in the pure metallic form or in the form of alloys of high aluminum metal content. The Metal Aluminum is a light, silvery colored metal of very low density being nearly one-third the density of iron. In aboveground situations it has excellent resistance to corrosion. It is an outstanding electrical con- ductor. Similarly it is an outstanding heat conductor. It also has excellent corrosion resistance to most food liquids such as fruits and juices. In addition it has unique corrosion resistance to strong oxidiz- ing acids such as nitric. As polished surfaces it has durable and high reflectivity for light. Mechanically it is easily worked and formed. Although in some form, particularly in the purest state, it is quite soft, many of its simplest alloys are of very high strength. It can easily be produced in cast form; it can be welded; it can easily be extruded in a variety of complex shapes; it can be rolled and embossed sheet form or in the form of very thin foils. These many attractive properties have encouraged its use in a number of important applications. Because of these features in terms of volume and value it exceeds all metals except iron. However, among all major 9.6 products, it requires much more energy to produce than any other--a total of 122,000 Btu per pound compared with 56,000 for copper and 12,000 for steel. Aluminum is produced exclusively by the electrolysis of pure aluminum oxide which has been dissolved in molten cryolite which is mainly the xynthetic mineral of sodium aluminum fluoride, NazAlFe. The tempera- ture of this process is about 950°C. The 31 plants which conduct this process in the United States have a combined annual capacity of nearly 4,500,000 metric tons. Uses The many unique properties of aluminum has encouraged its use in a wide variety of major applications; principal among these are: Transportation Equipment (because of high strength, corrosion re- sistance and light weight)--air and space craft, trucks, railroad equip- ment, automobiles, travel trailers and mobile homes. Power (because of high strength, low density, high light reflec- tivity, and high electrical conductivity)--high voltage, electrical trans- mission lines and solar energy applications. Construction (because of attractive finish, corrosion resistance, strength, light weight, ease of fabrication)--exterior surfaces, framing for doors and windows and decorative fittings. Containers (because of attractive finish, corrosion resistance, ease of fabrication, light weight)--fruit, vegetable, juice, beer, soft drink and food containers. Machinery (because of light weight, high strength, corrosion resis- tance and ease of fabrication including welding, casting and forming)-- heat exchange equipment, cast parts, frames, wheels, housings, and mount- ings. Appliances and Equipment (because of light weight, strength, corrosion resistance, and heat conduction)--heating and air conditioning, furniture, tools, cooking and garden equipment. 9.7 Surface Finishing (because of high and durable light reflectivity, light weight and ease in forming into foil and powdered forms, corrosion resistance and decorative features including capability of compounding with colors)--embossed, etched, colored and other decorative thinsheet forms, paint formulation and heat reflective insulation. The Process Aluminum is produced by the electrolysis of molten cryolite (Na,A1F¢) in which relatively pure aluminum oxide is dissolved. Some additives are also used to improve the physical and electrical properties of the melt; these include minor amounts of aluminum fluoride, calcium fluoride (fluorspar) and lithium fluoride. The aluminum oxide concentration in the molten solution ranges from about 2 to 6 percent. The essential chemical reaction is about as follows: Na.,AlF Al,03 th c 2) 6 2-Al--+ CO, +60 aluminum oxide carbon cryolite, solvent The ratio of these feed material waste gases is variable Although the above equation is representative, there are other factors which significantly influence the efficiency and raw material requirements. Principal among these are the design and operation of the individual elec- trolysic cells and the design and processing of the electrode (anode) carbon. A typical electrolysis cell for aluminum production is shown in the following sketch. In this process the feed material (aluminum oxide) is added inter- mittently through the top crust. Also the molten aluminum is drawn off intermittently. The carbon anodes which are continuously consumed in the process are formed and introduced almost continuously. Although the cell structures are rugged and durable, they eventually fail and must be totally rebuilt. The life of a cell is usually a few years. An array of cells which may number in the hundreds is called a pot line. A number of pot lines comprise a whole reduction plant. A representative reduction plant 9.8 { BUS BAR eats CARBON o . FROZEN CRUST ANODE 4 i OF ELECTROLYTE oe AND ALUMINA ELECTRIC” [* INSULATION f- CARBON LINING MOLTEN ELECTROLYTE MOLTEN ALUMINUM Cross-Section of an Aluminum Production Cell may have an annual capacity of 100,000 short tons of pure metal. The largest plant in the U.S. is the Rockdale, Texas, plant of the Aluminum Company of America with 285,000 tons. The smallest in the United States is the plant of Conalco at Lake Charles, Louisiana, with 36,000 tons per year (1973). (1) The raw materials, energy and labor requirements for the two major process (anode) types are reported as follows: (1) See U.S. Bureau of Mines Bulletin 667, "Mineral Facts and Problems, Bicentennial Edition," 1975. 9.9 Estimated ranges of alumina, energy,' labor, and raw materials to make 1 short ton of primary aluminum metal. ‘Type of anode Prebaked Soderberg Alumina - 19-195 19-195 Makeup cryoite (Na AIF,) pounds... 10-70 10-70 Makeup aluminum fluoride (AIF do... 25-60 25-60 Calcium fiuonde (CaF2) -.do.. 48 48 Energy, million Btu: ? Alumina reduction (electricity) .........-.----- 45-56 55-60 Electrode carbon Petroieum coke, calcined (700-950 pounds) 12 9-10 Pitch (280-330 pounds) - uw uM Anthracite coal (40-80 pounds) _ - &7 7-4 Anode and cathode baking (oil, gas, electnc- 55 55 o=2. operations (gas, oil, electricity)... 5.2-7.8 5.2-7.8 Total labor and supervision _..___... man-hours.. 6-15 10-20 1 Assumed energy equivalent of oil is 150,000 Btu per gallon: natural gas. 1,000 Btu per cubic toot: coal and pitch, 24 million Btu per short ton; petroleum coke, 26 million Btu per short ton; electricity, 3,413 Btu per kilowatt-hour. 2 Excludes erergy required to produce fluorine compounds, estimated at 2-7 milion Btu per ton of primary aluminum, and to caicine petroleum coke. equivalent to about 1-2 milion Btu per ton of primary aluminum. The principal raw material, alumina (refined aluminum oxide), is largely imported, mainly from Jamaica, and other Carribean countries, Australia, and Africa which have large resources of the desired mineral, buaxite. This mineral in these producing countries is in some cases processed for economic as well as political reasons to alumina. However, the largest portions of the imported bauxite mineral are still processed in the United States. Depending on geography and beneficial contracts a significant portion of U.S. reduction plants continue to depend on imported, refined alumina. Furthermore, it is expected that unless significant or unreasonable price increases develop over the years, the U.S. will continue to be dependent upon such imported bauxite and increas- ingly on refined alumina as well. However, if there are major indigenous deposits of suitable bauxite (or other aluminum minerals such as alunite, anorthosite, ferruginous bauxite and kaolin) alumina production may also be considered as a local and integrated part of an overall aluminum industry. Reference (1) diagrams the flow of bauxite and alumina to the U.S. aluminum industry as follows: 9.10 DISTRIBUTION OF U.S. BAUXITE AND ALUMINA SUPPLY AND ALUMINUM PLANT CAPACITIES 1973 (THOUSAND SHORT TONS OF ALUMINUM CONTENT) ‘ METALLURGICAL GRADE BAUXITE suppty [-] [=] TOTAL 3.8 [*] LG 2. = ALUMINA IMPORTS TOTAL 1,775 ALUMINA CAPACITY AUSTRALIA sannica, Summa TOTAL 4,044 [| Boren Counrmes. PRIMARY ALUMINUM CAPACITY TOTAL 4.893 “meson samt, El eh somes mL aneaat rma, maaan, Lencvaw, Taurens, WEY: = (A) ALCOA (ET) EASTALCO (MM) MARTINMARIETTA (0) ORMET (AN) ANACONDA (IN) INTALCO (NR) NORANDA (RV) REVERE (CM) COWALCO (K) KAISER (NS) MATIONAL-SOUTHWIRE (RA) REYNOLDS Except for carbon for anode production the other raw materials are rather minor; however, most of the fluoride, mineral raw material is also imported. Carbon for anode production is in the form of so-called pitch and petroleum coke; both are by-products of the petroleum refining industry and are generally available locally in the U.S. Some anthracite coal is also used in electrode fabrication. Since about 0.6 1b of such carbon is consumed for each pound of aluminum produced, carbon is a major raw material. With regard to capital requirements for the aluminum industry, reference (1) also states as follows: "A new bauxite mine in an 9.11 undeveloped area might cost as much as $80 per ton of annual capacity. The cost of new alumina production facilities in 1974 was believed to be $300 to $500 per ton of annual capacity. Estimated cost of primary aluminum plants built in 1974 ranged from $1200 to $1800 per annual ton capacity." Assuming then that it takes about 4.5 tons of bauxite to provide a ton of metal and also about 2 tons of alumina, the total capital cost per ton of metal starting from the mine would be about $2500 per ton of annual capacity. In addition the cost of new electric powder generat- ing facilities "would add another $600 to $1200 per ton of annual metal capacity." (This estimate was based on the use of about 8.5 kWh per pound of metal.) The same reference indicated operating costs (exclusive of profit) to be about as follows: Bauxite $ 22 to 110 per ton of metal Alumina 90 to 160 per ton of metal Primary Aluminum 300 to 600 per ton of metal Total $ 412 to 870 per ton of metal (or $0.206 to $0.435/1b) In addition to these costs there is the cost for delivery of the ingot aluminum to the consumer. Thus the three major costs in aluminum manufacture relate to the cost of power, the cost of alumina and the cost of delivery of ingot to the consumer. Although the chart shown on an earlier page shows that a dozen com- panies are producing metal in the U.S., three of these produce two-thirds of the total U.S. production. About half of all these companies own foreign ore and alumina processing plants. In 1975 the total metal pro- duced in the U.S. as ingot and mill products had a value of about $7 billion. 9.12 Present Status of the Industry Although aluminum reduction plants are widely distributed across the U.S. there is centralization around areas of former and recent low cost electric power. For earlier plants this was almost exclusively hydroelec- tric power--in the Pacific Northwest, the Tennessee Valley, the Ohio Valley, the St. Lawrence Valley and North Carolina. Geographical Distribution of Aluminum Production 2? (2) C. A. Rohrmann, et al, Battelle-Northwest Report BNWL-2137 for U.S. DOE, November 1977, "Chemical Production from Waste Carbon Monoxide - Its Potential for Energy Conservation." 9.13 Factors other than power costs have been involved in some of these plant locations--such as sea coast sites which are available to imported alumina, proximity to users (and fabriactors) of the product, and avail- ability of other low-cost energy sources such as natural gas in Texas (when it was much cheaper than it is today). These plants have a very wide range of capacities--285,000 down to 36,000 tons per year. The growth rate has been impressive with a domestic demand growth averaging 7.4% per year. Foreign demand growth has been at the rate of 9.5%. Although such figures are impressions in themselves, if any significant increase in the standard of living of both the develop- ing and underdeveloped populations is achieved the demand for the metal because of its favorable properties could significantly exceed these existing growth rates. These possible developing needs and the associated power demands would be prodigious indeed and suggest a continuing bright future for the expansion of this industry. Furthermore, if the price of copper improves (as it is likely to do) to the level it was before the recent recession aluminum metal is certain to displace more of this metal in the electrical field. Future Prospects Although bauxite of foreign origin is likely to continue to be the principal raw material for metal production, there are strong political and security reasons for shifting toward the use of more domestic minerals for a significant fraction of the industry. This would result in new industries for alumina production based on kaolin, ferruginous bauxite, alunite and anorthosite. These minerals are continuing to be investigated at the process development level but a clearly favorable economic justifi- cation has yet to be apparent. There will certainly be a continuing need to make even small gains in more efficient use of energy by improvements in cell design, electro- lyte and electrode materials. Some concepts suggest that improvements to the cell designs to assure collection of higher strength carbon monoxide 9.14 waste gas may contribute significantly to energy conservation (see Reference 2 mentioned previously). Similarly the waste carbon resulting from reconstruction of wornout cells may be productively converted to raw or intermediate Btu gas with attendant recovery of valuable fluoride chemicals for recycle. Such a development could achieve even greater economic as well as favorable material conservation results. Radical changes in processes are not anticipated; however, the effort of Alcoa to develop a process based on chlorides rather than fluorides should be noted. It is claimed that this process would reduce ceil power require- ments by about 30%. Furthermore it would contribute to the solution of some nagging air pollution problems associated with the present fluoride based processes. Conclusions Aluminum represents a particularly interesting prospect for Alaska, particularly in relationship to the Japanese or other Asian markets. Japan, for example, faces very high costs of electric power (40-60 mills/kWh industrial rate) due to their heavy dependence on costly imported oil. As a consequence, the Japanese metals industry is moving overseas--an example being the 50% Japanese participation in the proposed Alumax plant on the Columbia River in Oregon to utilize alumina imported from Australia. The cost of transporting aluminum ingot or slab from South Central Alaska to Japan should, if anything, be somewhat less than transporting (approxi- mately 13500 k-miles) the same commodity from Portland, Oregon (approxi- mately $20/ton at 4100 k-miles). Compared to the high intrinsic value of aluminum (approximately $1120/ton) the product transportation cost’ is near negligible. Cost of importing alumina from Australia to Alaska will similarly be slightly less than to the Pacific Northwest. The Japanese market for aluminum is also attractive from the stand- point of the balance of trade standpoint. Alaska may be in the position of being able to provide lower cost hydroelectric power surplus to utility needs. This situation could come about only if the Upper Susitna or other major hydroelectric project is Sat constructed. The Alaskan utility loads are strongly winter peaking whereas the availability of hydropower tends to scale during the spring and summer months. Thus an aluminum industry could operate on interruptible power during the off-peak months and absorb hydroenergy that might otherwise be "spilled." This is the current situation in the Pacific Northwest states where more than 30 percent of the U.S. aluminum production capacity is located. By purchasing off-peak power a significant reduction in the total cost of power to the consumer can be achieved through careful inte- gration of an interruptible load into the power system. A full evaluation of the potential for an aluminum reduction industry location in Alaska will require integration with a thorough analysis of future loads and generating resources, power marketing studies and hydro- logic evaluation of the hydroelectric system to be selected. Neverthe- less, at this stage an aluminum industry development has a number of factors working towards its success and it must be considered a leading contender. It also has the added positive attribute of being dependent upon a renewable source of energy (hydropower). 9.16 CEMENT INDUSTRY 9.3 CEMENT INDUSTRY A. GENERAL CHARACTERISTICS 1. Location of Major Production Regions Delaware, Massachusetts, Minnesota, New Hampshire, New Jersey, North Dakota, Rhode Island, and Vermont. (2) All but three of these states are in the Northeastern Region of the U.S. 2. Markets For the most part cement companies market their product locally, (1) Cement has a high weight-to-value ratio; therefore, it is generally trans- where they may be competing with as many as 15 to 20 other companies. ported on land by rail or truck over a radius of 200-300 miles surround- (1) considerably beyond a 300-mile radius. ing the cement plant, where access to water transportation is extended (1) 3. Industrial Structure In 1974, 51 companies operating 175 integrated plants and grinding only plants produced over 80 million short tons of cement in the U.S. The 10 largest U.S. cement companies provided over 50% of the U.S. market (3) for cement. 4. Process Description There are two main processes for producing cement--the wet process and the dry process. Cement production by the wet process has been decreasing, and cement production by the dry process has been increasing in the past several years. One reason for this is that the dry process uses less energy than the wet process. Therefore, the dry process was chosen as the cement industry representative for this study. Since more than 90% of the cement produced in the U.S. is Portland cement, the pro- cess description is based on the production Portland cement. 9.17 The manufacture of Portland cement by the dry process involves four steps: ° Acquiring raw materials, Preparing raw materials, * Producing clinker, and Grinding and mixing product cement. The acquisition of raw materials involves mining of calcareous (lime- bearing) materials, mining of argillaceous (clayey) materials, and acquiring other raw materials such as blast furnace slag, sand, sandstone, iron materials, and coal-ash. These raw materials are transported to the cement plant. The raw materials are prepared for clinkering or "burning" by first being crushed and, if necessary, dried. Next, the raw materials are dry ground to reduce the size of particles. Roller mills are increasingly being used for this grinding step in the dry process. Following grinding the mate- rials are thoroughly mixed and blended. The production of clinker is accom- plished by "burning" the ground raw materials in various types of kilns. Two types of kilns are long rotary kilns and short rotary kilns with pre- heaters and possibly flash calciners. For this study a short rotary kilm with a suspension preheater was chosen. In the kiln the materials chem- ically react at elevated temperatures and exit from the kiln as hard granu- lar masses called clinker. The final grinding and mixing step consists of grinding the clinker to powder with about 5% by weight of gypsum added dur- ing grinding. The gypsum is added to control the time required for the cement to set once water is mixed with it. The wet process differs from the dry process only in the raw materia? preparation step. In the wet process, the raw materials are crushed and then wet ground in tube or ball mills. The slurry is then mixed, filtered, and fed into the kiln. The remainder of the wet process is the same as the dry process. 9.18 5. Trends in Process Development The general trend in the cement industry seems to be a shift from wet process plants to dry process plants. Preheaters and flash calciners are being used in dry process plant to decrease the size of kiln neces- sary for a given output and to utilize fuel more economically. There is also a trend to converting to coal fired kilns rather than oil or gas fired kilns. A possible future process may be a fluidized bed cal- ciner but at present this has problems associated with its heat recovery system. 6. Economic Plant Scale (3) a dry process cement plant is about 500,000 short tons/year. In talks According to 1974 information the average production size of with a couple of representatives of cement plant construction companies, the figure of 1,000,000 short tons/year seems to be the economic plant scale of the near future. A plant production size of 445,500 short tons/year was chosen for this study due to the necessary information available for evaluation and also due to the limited markets served economically by an Alaska plant. 7. Capital Cost The capital cost is a major factor in the development of a new cement plant. The capital cost for the hypothetical cement plant using the dry process chosen for this study is $80,858,000. This includes a 1.65 scale-up factor from costs in the Lower 48 states to costs in Alaska, no costs for land on which the plant is built, and fixed capital and working capital. This capital investment represents about $180/ton of cement produced per year. 8. Labor Requirements The total number of employees estimated to be needed to run the hypothetical cement plant is about 100 employees. This represents about 1 employee/13.5 tons of cement produced per day. 9.19 10. Q) (3) Cost Data Sheet References Environmental Considerations of Selected Energy Conserving Manufac- turing Process Options: Volume X. Cement Industry Report, Report for Industrial Environmental Research Lab, Cincinnati, OH, by Arthur D. Little, Inc., Cambridge, MA, PB-264-276 (EPA-600/7-76-034j) , December 1976. The American Cement Directory 1977, Bradley Pulverizer Co., 123 S. 3rd St., Allentown, PA, 18105, March 15, 1977. Industrial International Data Base - The Cement Industry, Rational Use of Energy Program Pilot Study, Report for Committee on the Challenges of Modern Society, North Atlantic Treaty Organization, by Gordian Associates, Inc., New York, 1976, NATO/CCMS-46. 9.20 Pwr — SOND 10. Process - Portland Cement, Dry Process, Rotary Kiln with Suspension Preheater Capacity - 445,500 TONS/YR, 1350 TONS/DAY, 330 DAYS/YEAR‘?) Capital Investment - $80,858,250'2) Feedstock Reau iene aoe Limestone 610,000 TONS/YR, CLAY/SHALE 64,000 TONS/YR, Sand and Miscellaneous 25,000 TONS/YR, GYPSUM 21,000 TONS/YR Total Product Cost: I. Manufacturing Costs - A. Direct Production Costs 1) Feedstock Costs 2) Chemicals 3) Direct Operating Labor 4) Direct Supervision @ 10% Direct Operating Labor 5) Utilities Fuel (as coal) @ $1.00/10°BTU Electrical Power @ $0.04/KWH Process Water Cooling Water Makeup @ $1.20/1000GAL Cooling Water Circulation @ $0.07/1000 GAL 6) Maintenance (Includes Labor, Supervision, and Supplies) @ 2% Fixed-Capital 7) Operating Supplies A. TOTAL B. Fixed Charges 1) Depreciation, 10% S.L. 2) Taxes and Insurance @ 2% of Fixed Capital B. TOTAL C. Plant Overhead @ 50% of I.A. 3, I.A. 4, and I.A. 6 II. General Expenses Administrative Costs @ 15% of I.A.3, I.A.4, and I.A.6 Total Annual Product Cost By-Product Credits: Net Product Cost ROI, 25% Before Taxes on Fixed-Capital Plus 10% on Working Capital Net Costs and ROI 9.21 $ 2,856,000 (4) om 3,626,000 (9) 363,000 1,559,000 (6) 2,406,000 7) rn 241,000 (8) 14,000 §9) 1,470,000'19) 147,000!17) $12,682,000 7,351,000(12) 1,470,000 $ 8,821,000 $ 2,730,000 819,000 $25,052,000 $25,052,000 -0- $19,112,000 $44,164,000 Tie 12. 13. Net Transfer Price/TON Cement Shipping Costs/TON Cement (Tanker to Portland/Japan) Current Price/TON Cement At Seattle At Ankorage At Fairbanks 9.22 $ 99.13 $ 19.60!13) $ 49.00'14) $ 78.40/14) $102.00!14) (1) (2) FOOTNOTES Based on the capacity of the reference plant dealt with in Reference 1, page 29. Based on information from 6 private firms a value of $100/TON/year was chosen as reasonable for construction in the lower 48 states. It is assumed that this figure is just fixed-capital and that it includes air pollution control. A scale-up factor of 1.65 is used to adjust the cost to Alaska. Therefore; 445,500 TONS X $100 X 1.65 = $73,507,500 is fixed-capital investment and YR TON/YR $73,507,500 X 0.10 = $7,350,750 is working capital. $73,507,500 + $7,350,750 = $80,858,250 for total capital investment. Based on information from Reference 2 page 26 & 27 that gave values as follows: limestone 1.370 tons/ton cement clay/shale 0.144 tons/ton cement sand & misc. 0.057 tons/ton cement gypsum 0.048 tons/ton cement Therefore; 1.370 tons limestone X 445,500 tons cement = 610,335 tons limestone ton cement YR YR 0.144 tons clay/shale X 445,500 tons cement = 64,152 tons clay/shale ton cement YR YR 0.057 tons sand & misc. X 445,500 tons cement = 25,394 tons sand & misc. ton cement YR YR 0.048 tons gypsum X 445,500 tons cement = 21,384 tons gypsum ton cement YR YR Based on approximate figures given in a phone conversation with Wayne Williams of Lone Star in Seattle limestone $3/TON clay/shale $10/ton gypsum $16/ton The cost for sand & misc. was obtained from Reference 3, page 146 as »$2/ton Therefore; 610,000 tons limestone/yr X $3/ton $1,830,000 64,000 tons clay/shale/yr X $10/ton = 640,000 25,000 tons sand & misc/yr X $2/ton = 50,000 21,000 tons gypsum/yr X $16/ton = 336,000 $2,856,000 9.23 (5) Based on 0.17 man-hr/376 1bs cement for direct labor from Reference 4, page 171 assuming $9.00 man-hr for direct labor Therefore; 0.17 man-hr_ -X 20001bs X 445,500 tons cement X $9.00 = $3,625,612/yr 3761bs cement TON YR man-hr This value is assumed to include the direct labor for pollution control also. (6) Based on a range of values given in literature it was assumed that 3.5X10°BTU/ ton cement was the fuel requirement and it was assumed that coal cost $1.00/10°BTU Therefore; 3.5 X 10° BTU X $1.00 X 445,500 tons cement = $1,559,250/yr TON cement TOOBTU YR (7) Based on a range of values given in the literature it was assumed that 135 KWH/ ton cement was the electricity requirement and it was assumed that electricity cost $0.04/KWH. The electricity for pollution control is assumed to be included. Therefore; 135 KWH X $0.04 X 445,500 tons cement = $2,405,700 TON cement KWH YR YR (8) Based on 450 GAL/TON cement from Reference 1, page 28 and assuming cost is $1.20/1000 GAL Therefore 450 GAL/TON cement X $1.20/1000 GAL X 445,500 TONS cement = $240,570/YR YR (9) Based on 450 GAL/ton cement from Reference 1, page 28 and assuming cost is $0.07/1000 GAL Therefore 450 GAL X $0.07 X 445,500 TONS cement = $14,033 TON cement 1000 GAL YR (10) Assuming the maintenance to be 2% of fixed-capital and to include pollution control Therefore $73,507,500 X 0.02 = $1,470,150/YR YR (11) Assuming operating supplies are 10% of maintenance costs Therefore $1,470,150/YR X 0.10 = $147,015/YR (12) Assuming that depreciation is 10% of fixed-capital $73,507,500 X 0.10 = $7,350,750/YR YR (13) Based on Reference 5, Appendix A, methanol process, the transport charges are $0.0098/LB 9.24 Therefore $0.0098/1b X 2000 Ibs = $19.60 TON cement TON cement (14) Based on prices for 1977 obtained from Bill Jacobson for Kaiser Cement in Seattle. 9525 REFERENCES . Environmental Considerations of Selected Energy Conserving Manufacturing Process Options: Volume X. Cement Industry Report, Authur D. Little, PB-264-276, December 1976. . Energy Use Patterns in Metallurgical and Nonmetallic Mineral Processing (Phase 4- Energy Data and Flowsheets, High Priority Commodities)Battelle Columbus Labs, PB-245-759, June 1975. . Commodity Data Summaries, Bureau of Mines, 1977. . R. Norris Shreve, Chemical Process Industries, Third Edition, 1967. - Alaskan North Slope Royalty Natural Gas, Battelle Northwest, August 1977. 9.26 9.4 CHLOR-ALKALI INDUSTRY I. INTRODUCTION (1) Process Overview Chlorine and caustic soda are produced almost entirely by electro- lytic methods from aqueous solutions of sodium chloride or fused chloride. In the electrolysis of brine, chlorine is produced at the anode, and hydrogen, together with sodium hydroxide, at the cathode. Since the anode and cathode products must be kept separate, many ingenious cell designs have been invented and commercialized. However, all these designs have been either variations on a type of diaphragm or on a mercury intermediate electrode. Diaphragm cells contain an asbestos diaphragm to separate the anode from the cathode. This allows ions to pass through by electrical migra- tion but reduces the diffusion of products. Diaphragms permit the con- struction of compact cells of lowered resistance, because the electrodes can be placed close together. The diaphragms become clogged with use, as indicated by higher voltage and higher hydrostatic pressure on the brine feed. They must be replaced regularly. The diaphragm permits a flow of brine from anode to cathode and thus greatly lessens or pre- vents side reactions (e.g., sodium hypochorite formation). Newer cells with metal cathodes (titanium coated with rare earth oxides, platinum or noble metals, or oxides) rarely develop clogged diaphagms and operate for 12 to 24 months without requiring diaphragm replacement. It is expected that Du Pont's Nafion (a perfluorosulfonic acid polymer), and similar materials used as membranes to replace asbestos, will increase service life. Presently under development are permionic membranes which pass NaOH while retaining NaCl increasing the purity of diaphragm cell (2) caustic and eliminating a purification step to remove chlorine. Mercury cells produce purer NaOH, but a small loss of mercury to the environment presents extreme problems. Originally, it was believed 9.27 that this loss was unimportant, but marine life concentrates the mercury biologically, resulting in fish containing lethal amounts of methyl] mer- cury. Ingestion of contaminated fish led to development of the so-called Miniamata disease, resulting in deaths and affliction. In 1973, Japan outlawed mercury cell use after 1978, and the construction of mercury cells in the United States came to an abrupt halt. Careful process con- tro, (3) combined with treatment of water and air effluent, may make it possible for mercury cell plants to meet environmental standards and survive, but most companies are hesitant to erect new units. Greatly improved diaphragm cell technology, particularly the replacement of graphite anodes with dimensionally stable titanium anodes with a catalytic coating, has swung interest to large (200 kA) diaphragm cells. The use of plastic has simplified cell construction, minimized and simplified maintenance, and allowed outdoor cell rooms in some cases, thus reducing costs. Technological Trends At the beginning of this century, in the early days of the electro- lytic chlorine industry, a great techno-commercial argument took place about the relative merits of diaphragm and mercury cells; no definite answer was ever produced to the question. In some places, in particular the USA where energy was less expensive, the diaphragm cell fluorished and became the main chlorine producing cell; whereas, in Europe the mercury cell became dominant. This rivalry between the two types of cells was brought to a sudden end by the ecological concern about the effect of mercury in the environment. Much research has gone into mer- cury cell modification, mostly dealing with process effluent cleanup. Due to Japan's legal limit on the use of mercury cells after March 1978, most mercury process cleanup engineering was developed there. (4) (5,6) imply that the outright ban on mercury cells Now recent news releases in Japan may be scrapped or at least delayed because of success attained with the new cleanup technology. This technology is now finding its (7) way into the European and American markets as well. 9.28 While mercury cell operators are presently concentrating on clean- ing up their operations, new development in the diaphragm cell tech- nology are also receiving attention. The progress made in the last 10 years can be partly attributed to Dimensionally Stable Anodes (DSA®). Through the use of such novel metallic anodes in place of the older graphite anodes, lower cell voltages and higher current efficiencies are possible with the higher product purity and lower maintenance (8) diaphragm is being undertaken by many manufacturers. The membranes (10) Corporation and Hooker Chemical, are based on Du Pont's Nafion which is costs. Extensive work on new membranes to replace the asbestos developed by several American companies, including Diamond Shamrock a copolymer of tetrafluoroethylene and another monomer to which a sulfonic acid group is bonded. The membranes are permselective which minimizes the amount of salt which can pass through the diaphragm into the caustic solution. Since 19749) this technology has been utilized on a commercial scale. The latest efforts by the developers has been in exporting the technology. (1! +12+13) The newest development in diaphragm technology comes from Asahi Chemical Industry Company of Japan) rent efficiency at higher concentration of caustic from the electrolyzer. whose perfluorocarboxylic acid membrane yields a higher cur- This technology will be further developed in cooperation with PPG Indus- (15) tries Inc. Structure of the Industry There are over thirty different corporations operating plants in the chlor-alkali industry in the U.S. today. Four of these companies-- Dow, Hooker (Occidental), PPG and Diamond Shamrock--control about half of the U.S. production of chlorine and caustic soda. These four, minus Diamond Shamrock, along with FMC and Pennwalt, control plants in Canada and Mexico as well. The tables (16) give the specifics of these pro- duction patterns. Of the total North American production capacity, less than 10 percent is in the Pacific Northwest and British Columbia. 9.29 0e°6 TABLE 1. Chlorine Plants in the United States (Not including plants building) I Year (a) Capacity Containers State & City Producer Built Cells T/C Filled Notes Alabama LeMoyne Stauffer Chemical Company 1965 De Nora 22 x 5 (merc.) 150 --SB 1 McIntosh Olin Corporation 1952 Olin E8 (merc.) 1630, Hooker H4 (diaph.) ('77) 500(¢) --SB ] Mobile Diamond Shamrock Corp. 1964 De Nora 18 x 4 (merc.) 15 --S- 1 Muscle Shoals Diamond Shamrock Corp. 1952 De Nora 24 x 2 M (merc.) 400 --SB 3 California Pittsburgh Dow Chemical USA 1917 Dow (diaph. ) 685 --S- 1 Delaware Delaware City Diamond Shamrock 1965 De Nora 18 x 4 (merc. ) 350 --S- 3 Georgia Augusta Olin Corporation : 1965 Olin EVIF (merc. ) 400 --S- 1 Brunswick Allied Chemical Corp. 1957 Solvay V-100 a} 300 --S- ] Brunswick Brunswick Chemical Co. 1967 Hooker HC4B (diaph. 80 ---- 1,7 Illinois Sauget Monsanto Company 1922 De Nora 18 x 6 (merc.) 120 --S- 3 Indiana Mt. Vernon General Electric Co. 1976 Hooker H2A (diaph.) ---- 1 Kansas Wichita Vulcan Materials Co. 1952 Hooker HC3BT, H4 ('75) (diaph.) 500 cTs- 1 Kentucky Calvert City B.F. Goodrich Chemical Corp. 1966 De Nora 24H5 (merc. ) 300 cece 1 Calvert City Pennwalt Corp. 1953 Olin E11F (merc.) ('67) 330 --SB 3 Louisiana Baton Rouge Ethyl Corporation 1938 Downs (fused salt) Hooker S3D (diaph. ) 375 --S- 1,4 Baton Rouge Allied Chemical Corp. 1937 Hooker S4B (diaph.) ('68) 550 --S- 1 Geismar BASF Wyandotte Corp. 1959 Diamond MDC41 (diaph.), Uhde 30 sq. m. vooc(<) --S- 1 (merc.) ('64), Hooker H2, HC4BT (diaph.) ('69) Geismar Vulcan Materials Co. 1976 Diamond MDC 55 (diaph.) 590 ---- 1 Gramercy Kaiser Aluminum & Chemical Corp. 1958 Hooker HC3B, HC3C (diaph.) 560 --SB 1 Lake Charles PPG Industries, Inc. 1947 Columbia N 1, Hooker S3A (diaph.) 690(c) --SB 1 De Nora 48H5 (merc.) ('69), Glanor 1144 Plaquemine Dow Chemical USA 1958 Dow (diaph. ) 3400 --S- 1 Plaquemine Georgia-Pacific 1975 Hooker H4 (diaph.) 800* --S- 1 St. Gabriel Stauffer Chemical Co. 1970 Uhde 30 sq. m. (merc. ) 450 --SB 1 Taft Hooker Chemical Corp. 1966 Hooker HC4B, C60, Hc80, H4 ('75) (diaph.) 1520 --S- 1 Maine Orrington IMC Chemical Group, Inc. 1967 De Nora 24H5 (merc. ) 215 --S- 1 Michigan Midland Dow Chemical USA 1897 Dow (Diaph.) 775 --S- 1 Montague Hooker Chemicals & Plastics Corp. 1954 Hooker HC3B (diaph. ) 225 --S- 1 Wyandotte BASF Wyandot.te Corp. 1938 Hooker HC3A (diaph. ) 540 --S- 1 Wyandotte Pennwalt Corp. 1898 Diamond DS43 (diaph.) ('60) 275 ers- 1 Mississippi Vicksburg Vicksburg Chemical Co. 1962 None -- -TS- 6 Nevada Henderson Stauffer Chemical Co. of Nevada, Inc. 1942 Diamond MDC29 (diaph.) ('76 350 --S- 1 New Jersey Linden Linden Chlorine Products Inc. 1956 BASF - Krebs (merc.) ('69) Krebs (merc.) ('63) 400 --S- 1 New York Niagara Falls E.I. Du Pont: de Nemours & Co. Inc. 1898 Downs (fused salt.) 180 ---- 4 Niagara Falls Hooker Chemicals & Plastics Corp. 1898 Hooker H4 (diaph.) ('74) 515(c) --S- 1 Niagara Falls Hooker-Sobin Chemical Co. 1971 Uhde 20 sq. m. (merc.) -- --S- 2 Niagara Falls Olin Corporation 1897 Olin E1IF (merc.) ('60) 210 --S- 1 Syracuse Allied Chemical Corp. 1927 Solvay S60 (merc.) ('53) 960 --S- 1 Hooker HC4B (diaph.) ('68, '77) North Carolina Acme Allied Chemical Corp. 1963 Solvay V-200 (merc. ) 165 --S- 1 Canton Champion International Corp. 1916 Hooker S1 (diaph. ) 50 cree 1,7 Ohio Ashtabula IMC Chemica’ Group, Inc. 1963 Olin E11F (merc. ) 110 --S- 2 Ashtabula RM1 Company 1949 Downs (fused salt) 190 --S- 4 Barberton PPG Industries, Inc. 1936 Columbia (diaph. ) 300 --S- 1 Tennessee Charleston Olin Corporation 1962 Olin E1IF, E812 (merc. ) 630 --SB 1 Memphis E.1. duPont du Nemours & Co., Inc. 1958 Downs (fused salt) 150 --S- 4 Memphis Velsicol Chemical Corp. 1943 Hooker HC-4B (diaph.) ('69) 70 --S- 1 {a} Refers to year chlorine production started at location. b) Dow Freeport includes both Texas and Oyster Creek divisions. (c) Expansion in progress - see Table 3. (d) See Table 4. L€°6 Table 1. (Cont'd) Year State & City Producer Built (a) Cells Saskatchewan Saskatoon Prince Albert Pulp Co. Ltd. 1963 Krebs (merc.) Kureha HD-4 (merc.) ('69) CUBA Los Villas Electro Quimica del Caribe SA 1935 Vorce (diaph.) (government operated) MEXICO Guanajuato Salamanca Guanos y Fertilizantes de Mex., 1959 Krebs (Paris) (M) (expansion 1971) SA (form. Montrose) (Guanomex) Jalisco Guadalajara Pennwalt del Pacifico, SA 1976 Diamond D0S45 (D) Mexico Chalco Fabrica de Celulosa el Pilar SA 1953 Pomilio (D) San Cristobal Guanos y Fertilizantes de Mex., 1954 Krebskosmo (M) (Ecatepec) SA (Guanomex) (form. Ind. Nac. (expansion 1959) Quim. Farmaceutical) Santa Clara Pennwalt, SA de CV 1958 De Nora 14TGL (M) De Nora 14 x 3 F (M) ('66) Mathieson E11 (M) ('67) Michoacan Zacapu Industrias Quimicas de Mix., SA 1975 Diamond MDC20 (D) Nuevo Leon Monterrey Celulosa y Derivados, SA Plantas 1958 Mathieson E8 (M) Quimicas (form. Sosa de Mixico) (expansion 1972) Veracruz Pajaritos Industria Quimica del Istmo, SA 1967 De Nora 18 x 4 (M) De Nora 18 H 4 (M) ('72) PUERTO RICO Guayanilla PPG Industries (Caribe) 1971 De Nora 27M2 (merc.) Texas Baytown Mobay Chemical Corp. 1972 Uhde (HC1) Corpus Christi E.I. du Pont de Nemours & Co., Inc. 1974 Kelchlor, Diamond MDC55 (diaph.) Corpus Christi PPG Industries, Inc. 1938 Columbia N 1, N 3 (diaph.) Deer Park Diamond Shamrock Corp. 1938 Diamond MDC22 (diaph.) De Nora 18 SGL (merc. ) Deer Park Shell Chemical Co. 1966 Hooker HC-4BT (diaph.) Denver City Vulcan Materials Co. 1947 Hooker S 1 (diaph.) Freeport(> Dow Chemical USA 1940 Dow (diaph.), Dow (magnesium Houston Ethyl] Corporation 1952 Downs (fused salt) Houston Champion International Corp. 1936 Hooker S 1 (diaph.) LaPorte Diamond Shamrock Corp. 1974 Diamond MDC 29 (diaph.) Point Comfort Aluminum Co. of America 1966 De Nora 24 x 5, 24H5 (merc.) Port Neches Jefferson Chemical Co., Inc. 1959 Hooker $3B (diaph.) Snyder American Magnesium Co. 1969 VAMI nachos tia) Utah Rowley NL Industries, Inc. 1977 Modified IG Farben (magnesium) Virginia Hopewel1 Hercules, Inc. 1939 Hooker HC3 (diaph. ) Washington Bellingham Georgia-Pacific Corp. 1965 De Nora 18 x 4 (merc. ) Longview Weyerhaeuser Company 1957 Diamond MDC29 len ('75) Tacoma Hooker Chemicals & Plastics Corp. 1929 Hooker S1, S3 (diaph. Tacoma Pennwalt Corp. 1929 Glanor 1144 (diaph.) West Virginia Moundsville Allied Chemical Corp. 1953 Solvay S60 (merc.) New Martinsville PPG Industries, Inc. 1943 Columbia N 1, N 3, N 6 (diaph.) Uhde 20 sq. m. (merc.) (* i So. Charleston FMC Corporation 1916 Hooker HC3B (diaph.) ('73) Hooker H1 (diaph.) ('73) Wisconsin Green Bay Fort Howard Paper Co. 1968 Hooker HC3C (diaph.) Port Edwards BASF Wyandotte Corp. 1967 De Nora 24H5 (merc. ) a) Refers to year chlorine production started at location. b) Dow Freeport includes both Texas and Oyster Creek divisions. c) Expansion progress - see Table 3. d) See Table 4. Capacity T/D (c) (c) 500 100 1 1050 370 50 7330(c) 110 40 1200(¢) 460 150 70 125 85 250 400(c) 470 260 690 800 14 Containers Filled CTS- cTTS- Oree nun =e ' rE_Nntenwee pemrrrnree vue nuunn 1 oro Notes won ° wre epee _ © ~N TABLE 2. Chlorine Plants in Canada, Cuba and Mexico (Not including plants building) bene} Capacity Containers Province & City Producer Built(@) TD Filled Notes CANADA Alberta Fort Saskatchewan Dow Chemical of Canada, Ltd. 1968 Dow (diaph. ) (c) =-S- 1 British Columbia Wanaino Canadian Occidental 1964 Hooker S4, HC4BT (diaph.) --S- 1 Petroleum Ltd. Worth vancouver Canadian Occidental Petroleum Ltd. 1957 Hooker S3B, HC-60, HIA (diaph. ) --S 1 Squamish FMC of Canada Ltd. 1965 De Nora 24 x 5 (merc.) --SB 1 Manitoba Brandon Hooker Chemicals Canada, Ltd. 1968 Dryco (diaph. ) --S- it ilew Brushwick Dalhousie Canadian Industries, Ltd. 1963 I.C.1. (merc. ) --S- 1 Nova Scotia Abercronibie Point Canso Chemicals Ltd. 197- I.C.1. (merc. ) --S- 1 Ontario Cornwall Canadian Industries, Ltd. 1935 1.C.1. (merc. ) (c) TSs- 3 Dryden Reed Ltd. 1962 Hooker Mx (membrane) ('75) --S- 157 Sarnia Dow Chemical of Canada, Ltd. 1948 Dow (diaph.) --S- 1 Quebec Beauharnois Stanchem 1948 Uhde (merc.) ('71) (c) -S- 1 Becancour Canadian Industries, Ltd. 1975 Hooker H2A (diaph.) 285 SoS J Lebel-sur- Domtur Pulp Ltd. 1967 Olin E11F (merc. ) cree 1 Quevillon Shawinigan Canadian Industries, Ltd. 1938 1.C.1. (merc.) -~-S- 1 Saskatchewan Saskatoon Prince Albert Pulp Co. Ltd. 1963 Krebs (merc.), (c) cTs- 1 Kureha HD-4 (merc.) ('69) CUBA Los Villas Electro Quimica del Caribe SA 1935 Vorce (diaph.) CcT-- 1 Sagua La Grande (government operated) MEXICO Guanajuato Salamanca Guanos y Fertilizantes de Mex., 1959 Krebs (Paris) (M) cece 1 SA (form. Montrose) (Guanomex) (expansion 1971) Jalisco Guadalajara Pennwalt del Pacifico, SA 1976 Diamond DS45 (D) cTs- 1 Mexico Chalco Febrica de Celulosa el Pilar SA 1953 Pomilio (D) ios 1 San Cristobal Guanos y Fertilizantes de Mex., 1954 Krebskosmo (M) cTs- 1 (Ecatepec) SA (Guanomex) (form. Ind. Nac. (expansion 1959) Quim. Farmaceutica) Santa Clara Pennwalt, SA de CV 1958 De Nora 14TGL (M) cTS- 1 De Nora 14 x 3 F (M) ('66) Mathieson E11 (m) ('67) Michoacan Zacapu Industrias Quimicas de Mex., SA 1975 Diamond MDC20 (D) = sie 1 Nuevo Leon Monterrey Celulosa y Derivados, SA Plantas 1958 Mathieson E8 (M) cTs- 1 Quimicas (form. Sosa de Mexico) (expansion 1972) Veracruz Pajaritos Industria Quimica del Istmo, SA 1967 De Nora 18 x 4 (M) (c) 2-S- 1 (Coatzacoalcos) De Nora 18H4 (M) ('72) (a) Refers to year chlorine production started at location. (b) Expansion in process - see Table 3. 9.32 TABLE 3. New Plants Expansions and Modernizations Projected Location Producer Project Status Completion Notes UNITED STATES Alabama Mc Intosh Olin Corp. Phase 2, 500 T/D Hooker H4 Engrg. 2Q '78 1 Louisiana Geismar BASF Wyandotte Corp. Modest Expansion Underway 2.Q) 77 1 Diaphragm Cells Lake Charles PPG Industries, Inc. Phase 2, 750 T/D Engrg. 1980 1 (Bipolar) Plaqueniine Georgia Pacific Corp. Expansion 900 to 1200 T/D Engrg. Early '79 1 Hooker H4, $30 million New York Niagara Falls Hooker Chems. & Plastics 450 T/D Hooker H4 (diaph.) Engrg. 1Q '78 1 Corp. Oregon Portland Pennwalt Corporation Expansion 310 to 410 T/D Bldg. Mid '79 1 Expansion 410 to 570 T/D Engrg. 1981 (diaph. ) Texas Baytown Goodrich/Bechtel 800 T/D Diamond MDC 55 Engrg. Early ‘80 1 Freeport Dow Chemical USA Expansion, Dow (diaph.) 1000 T/D Underway 1978 1 La Porte Diamond Shamrock Corp. “Incremental Expansion" Bldg. Early '78 ; washington Tacoma Hooker Chems. & Plastics Expansion 400 to 675 T/D Engrg. Mid '79 1 Corp. CANADA Alberta Fort Saskatchewan Dow Chemical of Canada Expansion 900 T/D Bldg. Late '79 1 Dow (diaph.) Ne Brunswick Nackawic St. Anne - Nackawic smal] plant Engrg. Mid '79 il Pulp & Paper Co. Asahi membrane cell Ontario Cornwall Canadian Industries Ltd. Conversion to metal anodes Underway 1Q '78 1 Quebe= Becancour Canadian Industries Ltd. Expansion 385 to 770 T/D Bldg. 4Q '79 1 $100 million Saskatchewan Saskatoon Prince Albert Pulp Co. replacement cell room Engrg. Fall '78 1 Asahi membrane cell MEXICO Veracruz Pajaritos Cloro de Tehuantepec SA 5CO T/D Glanor 1144 Underway Early '79 1 (Bipolar TABLE 4. Operations Shut-Down Location Producer Extent, Scheduled Notes Texas Corpus Christi PPG Industries Inc. Complete shutdown 1Q'78 1 All capacities shown are published capacities. 9.33 II. ENERGY REQUIREMENTS The major production route for the chlor-alkali industry today is by way of electrolysis of brine or molten salt. Due to this circum- stance, there is no chance for energy source substitution. Or to look at the problem another way, one could say there is perfect substituta- bility among any of the competitive means of generating electrical power. A variable energy cost for evaporation to concentrate the caustic solu- tion is also required for diaphragm cells. As the technology of the permselective membranes developes this cost will continue to decrease. Basing an energy cost calculation on a published cost accounting for chlor-alkali production(!4) and adjusting energy costs to 24 mills per kWh, $4.40 per metric ton of steam and a capital cost multipler for Southern Alaska of 1.5; the percent energy cost of the total production cost is about 60 percent for the standard asbestos-diaphragm or mercury cells but may drop substantially to about 55 percent for the Asahi perm- selective membrane cell. Actual kWh requirements for the electrolysis portion of the process range from 3524 kWh/mton e154) to 3750 kWh/mton c15!"7) for the mercury cell, down to 3040,(17) 3137178) ana 2929'14) kWh/mton Cl, for the asbestos diaphragm cell. The additional energy requirement of caustic concentration from the cell product of 15 percent up to the commercial product of 50 percent when using diaphragm cells is from 24168) to 2668''4) kwh/mton of NaOH (measured as 100% NaOH). The new permselective membrane technology may drop this cost to as low as 297 kWh/mton NaOH while increasing the electrolysis cost to only 3054 kWh/mton c1,. (14) With the current market price of $135 per ton of chlorine or caustic soda 50% solution, the energy intensiveness cal- culates to 84,000 Btu/$ of product in the mercury cell and 128,000 Btu/$ of product in the asbestos diaphragm cell. The newer membrane technology could require as little as 77,000 Btu/$ of product. 9.34 III. ECONOMIC CONSIDERATIONS (19) Market Conditions A major market for chlorine is ethylene dichloride, which eventually becomes polyvinyl chloride (PVC). In this derivative chain, comfortable downstream capacity is reinforcing the effects of large polyvinyl chloride inventories. This capacity situation is a mild but not unpleasant sur- prise in view of the severe environmental problems in this area in the past several years. Earlier acute problems of toxic vinyl chloride emission in production, subsequent polymerization, and PVC fabrication plants now seem well in hand. Some vinyl chloride capacity and possibly some PVC capacity have been lost, but the total likely was smaller than once thought. Debottlenecking efforts probably have overcome all of this capacity loss. The result then is ample PVC capacity even with good growth in consumption. Unfortunately for producers, PVC's capacity situation merely helps translate chlorine's weak profitability down- stream. Industry sources still cite PVC production as the really buoyant market force for chlorine this past year. PVC, in effect, has offset declines in other chlorinated organics, particularly fluorocarbons used as propellants. The propellant market may have accounted for 3 percent or so of chlorine demand, some 300,000 tons a year at most. This market soon will be gone for practical purposes. However, chlorine consumption in making other fluorocarbons such as refrigerants is still rising, although regulatory curbs may be on the way. Prospects for other pro- ducts containing chlorine vary over the range of 7 percent annual growth down possibly to zero in pulp and paper. Prospects are even poorer in cases such as environmentally curbed trichloroethylene. Although still a major user of chlorine, the pulp and paper industry is shifting to other bleaching materials. The result is little growth for this area. Major derivatives of chlorine are ethylenedichloride 20%, other chlorinated hydrocarbons 15%, propylene oxide 10% and various inorganics 9.35 10%. Major uses of chlorine are for diverse chemicals 35%, plastics (mostly PVC) 20%, solvents 15%, pulp and paper 15% and water treating 5%. Demand growth for caustic during 1978 will be in the usual big use areas such as the manufacture of a diverse lot of other chemicals. Used largely in neutralization processes, caustic counts on this area for half of all domestic sales. Because chemical manufacturing continues to grow fairly well, this use of caustic will grow, too, perhaps 7 per- cent per year or well above the overall caustic growth rate of 4 to 5 percent annually. One general use of caustic, neutralizing effluent streams, has had particularly strong growth in recent years. However, the big growth in pollution control is over and caustic's growth rate for this use likely will fall back to about the overall growth rate in chemicals manufacture. Pulp and paper holds second spot among easily identifiable use areas for caustic. This use continues to have an above-average growth rate because of steady growth in demand for pulp and paper products and a trend toward more use of caustic per unit of production at the expense of chlorine. Aluminum's use of caustic--converting bauxite ore to alumina for subsequent reduction to the metal--has been threatened by two factors. First, domestic U.S. alumina production has not been keeping up because of increased alumina imports. Second, concerted efforts to recycle aluminum metal are beginning to slow the growth in alumina demand. Major uses of caustic soda are for diverse chemicals 50%, pulp and paper 15%, aluminum production 5%, textiles 5%, and petroleum refining 5%. There are no derivatives of sodium hydroxide produced on a commercial scale. Additional sources peg chlorine growth at 5 percent for 1978 and caustic soda growth at 5 percent through 1980 (20427) or perhaps slightly 9.36 lower at 4.2 percent. (71 These rates follow on prerecession growth rates of 6 to 7 percent in 1963 to 1973. (22) Capacity use at plants which coproduce chlorine and caustic soda will hover around 80 percent through 1978 for the second year in a row. This operating rate contrasts with historical and desired optimum rates of 96 percent or more in these highly effictent plants. (!9) This below capacity production has resulted in a marginally tight supply for caustic soda. The cause of the present supply situation is a weak demand for chlorine. At one time, chlor- alkali plants were run mostly for chlorine output. Coproduct caustic, if not sold, was literally thrown away, even by dumping in the ocean. The situation is a lot different now. Production costs related to sell- ing prices are such that neither product can be discarded or sold at bargain-basement prices. The result is that chlor-alkali units can be run economically only if reasonably good prices are obtained for both chlorine and caustic. As basic chemicals, sodium hydroxide and chlorine, face stiff competition. Sodium carbonate is the main substitute for caustic soda(!7) in such diverse chemical production processes as aluminum, glycerine, glycols, phosphates, silicates and sodium fluoride, the carbonate also replaces hydroxide in the NSSC pulp mills while sodium sulfate can (22) Sodium chlorate replace sodium hydroxide in kraft pulp mills. ) 21 and ozone compete with chlorine in bleaching, and peroxides and ozone are also replacing chlorine in water treatment processes; !7? but in the specialty chemical and plastics industry, chlorine has only limited competition from Her. 17) Geographic Considerations Location of the salt fields is one of the factors which has to be taken into account in the siting of plants for the manufacture of chlorine and caustic. In the USA where more than one-third of the world's chlorine is made, about 75 percent of the output is from elec- trolysis of brine made in local salt fields. A significant portion of the other 25 percent is produced in the Pacific Northwest which receives OFS its salt as a solid barged from Baja California. There the salt is produced by solar evaporation of sea water. In the case of Japan, which makes over 10 percent of the world's output of chlorine, all the salt needed has to be imported, almost entirely as salt from solar evapora- tion of sea water. Most European producers are near salt fields except in West Germany, the main European chlorine producer, where the develop- ment of the nineteenth century dye stuffs industry resulted in many chemical manufacturing sites remote from the salt eee rock Salt requirements are about 1.8 tons/ton of Cl, produced. The delivered salt is mined and shipped to these electrolytic plants. cost of the salt from Baja California to the Kenai coast is approxi- mately $19/ton. A second factor to consider in situating a chlor-alkali plant is the electric power cost and availability. The energy intensiveness of the industry may make this the overriding consideration. Thirdly, transportation must be considered in the siting process. The technology of transporting the hazardous products of the process is well developed. Yet serious accidents do occur as shown by two recent fatality-causing releases in the southeast U.S. that have been in the newspaper headlines. The ICC controls transportation costs by setting freight tariffs and designating official territories. Railroads must file rate schedules as common carriers and barge traffic also pro- vides competition. Marine transportation is certified by the U.S. Coast Guard and Pacific Northwest and British Columbia producers are known to barge chlorine and caustic along the Pacific Coast from Alaska to California for the paper industry. However, chlorine and caustic soda are not generally shipped long distances because the products have a low value in proportion to weight which limits their competitiveness with locally produced products. Freight costs as a percent of sales price escalate rapidly the more distant the market. Each plant has a natural geographic marketing area that cannot easily be invaded by competing plants in distant localities. 9.38 The chlorine and caustic soda industry, therefore, is a market oriented (24) port is available, no ocean-going shipments of chlorine are known on a industry. Although caustic can be shipped economically if a water commerical scale. IV. DEVELOPMENT AND OPERATING COSTS Capital Current capital costs for new plants or expansion range from $100K/ton/day on the Gulf Coast'!®»25) to $133 k/ton/day and $216K/ton/ sn Brazil, (13) respectively, to $260K/ton/day in 26 bility is less than needed. Depending on how the accounting is done, day in Sweden Quebec, Canada. However, due to the low capacity utilization profita- the level of return will range between insufficient for replacement of plants to sufficient for plant replacement but not high enough to outbid alternative investments. Producers' quarterly financial statements may very well continue to complain that one reason for poor overall profits is chlor-alkali operations doldrums. ('2) General capital cost calculations for chlor-alkali plants usually put plant pay back life at 15 years with a discounted cash flow at 20 percent. New plants are sized from 500 to 1,000 tons/day Cl,. Capacity is continuing to expand though some projects have been scrapped due to the capacity glut. (21) Labor The labor requirement for a new 1,000 ton/day plant would be nearly 150 people not including marketing and shipping personnel or process engineers. The key to successful operation lies with supervision with only a small amount of training required for the shift workers. There- fore, an influx of skilled workers would not be required to run the plant. Construction of the facility would, of course, require skilled craftsmen during the construction period. 9739 Development Time There are no significant regulatory requirements for placing a new chlor-alkali plant other than normal environmental impact statements. EPA concern is significantly less than with those industries dealing in organic chemicals. Trouble spots are pH maintenance in the plant waste water effluent and the suspended solids which may appear in the neutraliz- ing process. Chlorine emissions are of concern, but their control is well within today's technology limits. Construction time for a 1,000 ton/day plant is about 1-1/2 years. Though life spans for capital recovery purposes are 15 years, plant life expectancy may be as great as 40 years as evidenced by pre-World War II diaphragm cells now being replaced by (16) new technology. Environmental Residuals The major effluent stream will be an aqueous discharge stream con- taining dilute caustic and salt which will require neutralization. Neutralization often produces a suspended solids problem which also must be rectified. Purification of the aqueous salt cell feedstock often produces inorganic salt streams which require disposal, although this is used to precipitate calcium, magnesium and iron are precipitated with sodium hydroxide and sulfate is reduced by precipitation with barium chloride. The Prec are allowed to settle, then are filtered d. utilized, will also require disposal. A major environmental problem may from the cell fee Old cell membranes, if diaphragm cells are result from the use of mercury cells. Specific constraints and tech- nology for mercury control would have to be reviewed as they become available. V. EXOGENOUS INFLUENCES Visibility Though chlorine gas has definite negative conotations, chlor- alkali plants apparently suffer little more public abuse than any other 9.40 industrial chemical production site. The plants provide employment and are relatively clean. But two recent railroad accidents resulted in releases of chlorine gas which caused the deaths of several people in each case. This type of problem does not reflect on the production plant or even on the industry per se, but it does point out the diffi- culties of transportation safety of this hazardous chemical. Current information distributed by the popular press indicates that the Congress may even investigate the transportation of such hazardous chemicals, which could result in stricter regulations, which in turn translates to higher transportation costs. Of course, the chance of such hazardous spills and the transportation costs increase proportionately with the transportation distance. One might also expect that the amount of public outcry against shipping of such hazardous chemicals would also increase directly in proportion with the number of people subject to possible exponsure to the chemicals, which would, in most cases, be proportional to the distance transported. International Trade Foreign trade in chlorine is listed as negligible in all sources. The small amount of trade which does occur is mainly by barges in the Pacific Northwest and by railroad car between the U.S. and its North American neighbors. Exports of caustic soda are expected to drop from 10 percent of production in 1977 to about 5 percent in 1978. The reasons behind the shrinking exports are strong domestic selling prices and increased production from foreign plants. (19) VI. CONCLUSIONS Although mercury cells have several advantages including easier shutdown operation, less maintenance and repair, less steam require- ment and lower capital cost for evaporating equipment, there remain several drawbacks. Electrical power cost is greater for the electrolysis, floor area requirements are greater and the mercury inventory cost is substantial. The initial inventory of mercury for a 1,000 ton/day plant 9.41 could cost up to $7.5 million. Research and development in the area of mercury containment will probably continue, but the main thrust for new plants appears to be in the use of permselective membrane systems. The main advantage of such systems is their lower total power requirement when considering both the electrolysis and the product concentrating step. The chlor-alkali industry is market oriented and, as such, plants have been built all across the country wherever needed. The products are so basic that the need exists (and therefore a plant exists) in almost every major industrial area of the country. The market allows for only a small distribution area. In Alaska, for example, there are two paper/pulp plants which are likely customers; and although there are nearly 40 other paper/pulp plants in Washington, Oregon, Idaho and Northern California accessible by water with nearly 20 percent of the nation's capacity for paper, (28) there are also six chlor-alkali plants in the same region. Alaskan chlorine and caustic soda would have to compete with Pacicif Northwest products which are produced with cheap hydropower. Raw material cost is 30 percent higher in Alaska for Baja Californian salt, and some consideration would have to be given to developing a salt deposit known to exist at the southern end of the (20) only a remote possibility for an Alaskan plant; ocean-going chlorine is Alaskan panhandle. Penetration into the Japanese market remains almost unheard of. A Japanese subsidiary of Dow Chemical only recently was allowed to build a new chlor-alkali plant in Japan after months of haggling with that country's economic controllers. The new 1,100 ton/day plant will be built on Japan's northernmost island and was strongly opposed by Japan's domestic chlor-alkali industrialists. (29) Attempts to market Alaskan caustic soda or chlorine in Japan would most likely be met by stiff resistance. Transportation remains the major point of contention. Unless questionable local sources of salt can be developed, an Alaskan chlor- alkali plant will be at a distinct disadvantage due to higher raw material costs. Transportation of the products is a risky business, and, 9.42 unless further industrial development is made locally to provide new markets, long transportation distances will be required. Long trans- portation distances not only add cost to the product, but also increase chances of public exposure to the chemicals and the possible resultant regulatory consequences. REFERENCES 1. From Chemical Process Industries, Fourth Ed., R. Norris Shreve and Joseph A. Brink, Jr., Copyright 1977, McGraw-Hill, Inc. 2. Dahl, Chlor-Alkali Cell Features New Ion-Exchange Membrane Chem Eng (NY) 84 (17) 60 1975. 3. Cell Systems Keep Mercury from Atmosphere, Chem. Eng. News, Feb- ruary 14, 1972, p. 14. 4. Gardiner and Muoz, Mercury Removal from Waste Effluent via Ion Exchange, Chem. Eng., NY, August 23, 1971, pp. 57-59. 5. Chem. Eng., November 22, 1976, p. 73. 6.—-Ghem. Eng..—April 11,1977. -p. 72.. 7. The Japan Economic Journal, Vol. 16, #785, January 24, 1978, p. 9. 8. Diaphragm Cells from Chlorine Production Society of Chemical Industry, London, 1977, p. 15. 9. New Chlorine Plants Watch Their Watts, Chemical Week, November 27, 1974, p. 45. 10. Chlor-Alkali Producers Shift to Diaphragm Cells, Chem. Eng., February 18, 1974, p. 84. 11. Chem. Eng., March 29, 1976, p. 61. 12. Chem. & Eng. News, August 29, 1977, p. 12. 13. Chem. & Eng. News, August 29, 1977, p. 12. 14. Chem. Eng., June 21, 1976, p. 86. 15. Chem. Eng., January 2, 1978, p. 17. 16. le 18. 19% 20. 21. 2a. 23. 24. 25 26. ele 28. 29. North American Chlor-Alkali Industry Plants and Production Data Book, January 1978, Chlorine Institute Pamphlet 10. Faith Keye's and Clark. Energy Consumption: The Chemical Industry, J. T. Reding and B. P. Shepherd for EPA #PB 241-927, April 1975. C&EN, February 6, 1978, p. 8, Chlorine, Major Alkalies Still in Doldrums. SRI Handbook for Chemical Economics. Chemical Marketing Reporter, June 27, 1977. Chemical Marketing Reporter, August 5-12, 1974. Electrolytic Manufacture of Chemicals from Salt, D.W.F. Hardie and W. W. Smith, The Chlorine Institute, 1975. Pacific Northwest Economic Base Study for Power Markets, Chlor-Alkali Industries, Bonneville Power Administration, 1967. Chemical Marketing Reporter, Chlorine-Caustic Facility is Started Up by Olin at its McIntosh Complex, December 26, 1977, Daas C&EN, September 26, 1977, p. 18. Chem. Eng., May 24, 1976, p. 69. Control of Atmospheric Emissions in the Wood Pulping Industry, E. R. Hendrickson, et al., March 15, 1970. Chem. Eng., May 24, 1976, p. 67. 9.44 9.5 LIME INDUSTRY A. GENERAL CHARACTERISTICS 1. Locations of Major Producing Regions Lime is commercially produced in 30 of the continguous 48 states as well as in Hawaii and Puerto Rico. In 1972, the States of Ohio, Pennsylvania, Missouri, Texas, Michigan, and Illinois produced 61% of the total U.S. lime output. (1) The greatest concentration of commercial lime plants appears to be in the Great Lakes region. 2. Markets There appears to be very few markets for lime in Alaska. According to the U.S. Army Corps of Engineers in 1976, only 826 tons of lime was shipped by water into Alaska for the whole year. (2) A 1967 Census of Transportation by the U.S. Department of Commerce showed that over 80% of lime shipped in 1967 was transported less than 300 aileso This indicates that the lime industry markets tend to be of a localized nature. 3. Industrial Structure In 1972 the U.S. Bureau of Mines reported the total number of active lime plants, both commercial and captive, as being 186 plants. (1) Of these about 100 were commercial plants. In 1972, 10 companies operating 30 plants accounted for 45% of the total lime production. (!) 4. Process Description Fundamentally there are no differences in the types of processes used in the production of lime. Basically the only differences are in the calcination steps involved in different plants. There are four possible types of calcining kilns--rotary kilns, vertical kilns, rotary hearth kilns, and fluidized solids kilns. Of these four types of kilns, the rotary kilns and the vertical kilns are most widely used. Therefore, in this study, the lime industry was evaluated according to processes involving either rotary kilns or vertical kilns. 9.45 The manufacture of lime involves five basic steps: * acquisition of raw materials, processing of raw materials, ° calcining, processing of quicklime, and hydration of quicklime. Limestone is the raw material for producing lime and is acquired by quarrying/mining. The limestone is then transported to the lime plant. The raw materials are processed by crushing and screening the limestone to 6 ft-8ft sized chunks. These chunks can be fed to a vertical kiln at the point or they can be crushed, screened, and classified in order to be fed to a rotary kiln. The calcination step involves heating the limestone in the kiln in order to drive off carbon dioxide. The quicklime is processed by crushing pulverization. At this point the quicklime could be sold but if it is not used relatively soon after production it will absorb moisture and carbon dioxide from the air. Therefore, for better storage most of the quicklime is hydrated by adding water to the quicklime. This hydrated lime (or slaked lime) is more readily stored for future use. 5. Trends in Process Development The basic trend in the lime industry is toward larger plant sizes with the smaller, less economical plants becoming inactive. 6. Economic Plant Scale As already mentioned the economical plant scale trend is toward the larger plants. In 1972, according to the U.S. Bureau of Mines, 36% of the lime plants had capacities greater than 200,000 short tons/year whereas these same plants produced 65% of the total lime output. For this study, only 3,045,000 short ton/year plants were evaluated because of the limited demand for lime in Alaska and the high rates of transportation for the low value of lime on the economic market. 9.46 7. Capital Costs The capital cost per the hypothetical 30,000 short ton/year vertical kiln plant was calculated to be $4,149,000. This assumes that a vertical kiln producing 100 tons/day costs $1,600,000 and that this cost is only 70% of the fixed capital cost. A 1.65 scale-up factor to adjust costs from the Lower 48 states to the costs in Alaska is also assumed. This total capital cost consists of fixed-capital and working capital but it does not include the cost of the land on which the plant is built. This capital investment represents about $138/ton of lime produced per year. The capital cost for the hypothetical 45,000 short ton/year rotary kiln plant was calculated to be $1,815,000. This includes a 1.65 scale- up factor from costs in the Lower 48 states to costs in Alaska and fixed capital and working capital. This cost does not include the cost of the land on which the plant is built. This capital investment represents about $40/ton of lime produced per year. 8. Labor Requirements The total number of employees estimated to be needed to run the vertical kiln lime plant is 25 employees. This represents about 1 employee/4 tons of lime produced per day. The total number of employees estimated to be needed to run the rotary kiln plant is also about 25 employees. This represents about 1 employee/6 tons of lime produced per day. 9. Data Cost Sheets 10. References (1) Industrial Energy Study of the Concrete, Gypsum, and Plaster Pro- ducts Industries, PB-237-833 by Stanford Research Institute for Federal Energy Administration and U.S. Bureau of Mines, August 1974. (2) Waterborne Commerce of the United States, Calendar Year 1976, Part 4 Waterways and Harbors, Pacific Coast, Alaska, Hawaii, by the Depart- ment of the Army Corps of Engineers. 9.47 ar wn — ow ON D 11. 12. 13. Process - Lime Production, Rotary Kiln Capacity - 45,000 TONS/YR, 150 TONS/DAY, 300 pays/yr!) Capital Investment - $1,815,000 (2) Feedstock Requirements - 130,000 tons/yr(3) Total Product Costs I. Manufacturing Costs - A. Direct Production Costs 1) Feedstock Costs $390,000/4) 2) Chemicals -0- 3) Direct Operating Labor $259,000(5) 4) Direct Supervision @ 10% of Direct Operating Labor $ 26,000 5) Utilities Fuel (as coal) @$1.00/10°BTU 315,000'6) Electrical Power @ $0.04/KWH 86,0007) Process Water @ $1.00/1000 GAL 36,0008) 6) Maintenance @ 2% fixed capital 33,000 7) Operating supplies @ 10% of Maintenance 3,000 A. TOTAL $1,148,000 B. Fixed Charges 1) Depreciation, 10% S.L. $ 165,000 2) Taxes and Insurance @ 2% of Fixed Capital 33,000 B. TOTAL $ 198,000 C. Plant Overhead @ 50% of I.A.3, 1.A.4, and I1.A.6 159,000 II. General Expenses @ 15% of I.A.3, I.A.4, and I.A.6 48 ,000 Total Annual Product Cost 1,553,000 By-Product Credits: -0- Net Product Cost 1,553,000 ROI, 25% before Taxes on Fixed-Capital Plus 10% on Working Capital 429,000 Net Costs and ROI 1,982,000 Net Transfer Price/TON LIME 44.04 Shipping Costs/Ton Lime $40 - $1259) Current Price/Ton Lime $50 Oe op, Portland 9.48 (2) (3) (4) (5) (9) (10) FOOTNOTES Based on communication with Mr. Schaeffer of Fuller Co. in which he stated that the smallest rotary kiln Fuller makes is 150 T/D kiln. Based on the low figure of $1,000,000 fixed capital for a 150 T/D rotary kiln lime plant in the lower 48 states from Fuller Co., 1.65 factor to Alaska, and 10% of fixed capital being working capital. Based on BCL estimate that 2.88 tons of limestone is needed per ton of lime produced. Based on a figure of $3/ton for limestone (same value as used in the cement section) Based on 4 men per shift, 8 hr. shifts, 7 days/week, 300 days/year, $9/hr, 3 shifts per day. Based on an estimate of 7x10°BTU/ton lime for an average rotary kiln from PB-237-833 (Stanford Research Institute) Based on an estimate of 48 KWH/ton lime (based on numbers for crushing & calcining in the BCL report) Based on a value of 0.4 GAL/LB lime (assumed the same as for a cement plant from Plant Design and Economics for Chemical Engineers, M.S. Peters and K.D. Timmerhaus, McGraw-Hill Book Company, Second Edition, 1968, page 133). $40 value is based on the difference of price/ton of cement in Seattle and Ankorage, and the $125 value is a very rough guess from an Ash Grove Cement Company representative for shipping lime from Portland to Alaska. Based on current prices F.0.B. Portland given in phone call to Ash Grove Cement Company. 9.49 nr wn — wo On DD le 2s 13). Process - Lime Production, Vertical Kiln Capacity - 30,000 TONS/YR, 100 TONS/DAY, 300 pays/vr'") Capital Investment - $4,149,000'2) Feedstock Requirements - 86,400 TONS/YR‘?) Limestone Total Product Costs I. Manufacturing Costs - A. Direct Production Costs 1) Feedstock Costs 2) Chemicals 3) Direct Operating Labor 4) Direct Supervision @ 10% of Direct Operating Labor 5) Utilities Fuel (as oi1)') @ $2.00/10°8TU Electrical Power @ $0.04/KWH Process Water @ $1.00/1000 GAL 6) Maintenance @ 2% Fixed Capital 7) Operating Supplies @ 10% of maintenance A. TOTAL B. Fixed Charges 1) Depreciation, 10% S.L. 2) Taxes and Insurance @ 2% of Fixed Capital B. TOTAL C. Plant Overhead @ 50% of I.A.3, I.A.4, and I.A.6 II. General Expenses @ 15% of I.A.3, I.A.4, and I.A.6 Total Annual Product Cost By-Product Credits: Net Product Cost ROI, 25% Before Taxes on Fixed-Capital Plus 10% on Working Capital Net Costs and ROI Net Transfer Price/TON LIME Shipping Costs/TON LIME Current Price/TON LIME F.0.B. Portland 9.50 $ 259,000 (4) Se 160,000 (5) 16,000 324,000 7) 12,000 (8) 24,000 (9) 75,000 8,000 $ 878,000 $ 377,000 75,000 $ 452,000 $ 126,000 $ 38,000 $1,494,000 =0= $1,494,000 $ 981,000 $2,475,000 82.50 g4o-$125 (19) 50.00(11) (1) (10) (11) FOOTNOTES Based on communication with Mr. Gory of Kennedy Van Saun, 100 TON/DAY was the smallest size of vertical kiln that was still economical (smallest Van Soun makes is 60-75 T/D) Based on an equipment cost figure for a 100 TON/DAY vertical kiln at $1,600,000 and assuming that the equipment cost is 70% of the fixed capital, 1.65 factor to Alaska, and 10% of fixed capital being working capital. Based on BCL estimate that 2.88 TONS of limestone is needed per ton of line produced. Based on a figure of $3/ton for limestone (same value used as in cement section). Based on 2 men, 8 hr shift, 5 days/week; 6 men, 8 hr shift, 7 days/week; 300 days/year; $9/hr. Oil is used because of the vertical kiln specification. Based on estimate of 5.4 X 10°BTU/ton lime from PB-237-833 (Stanford Research Institute). Based on an estimate of 1O0KWH/ton lime (based on numbers for crushing and mining in BCL report) Based on a value of 0.4 GAL/LB lime (assumed the same as for a cement plant from Plant Design and Economics for Chemical Engineers, M.S. Peters and K.D. Timmerhaus, McGraw-Hill Book Company, Second Edition, 1968). $40 value is based on difference of price/ton of cement in Seattle and Ankorage, and the $125 value is a very rough guess from Ash Grove Cement Company repre- sentative for shipping lime from Portland to Alaska. Based on current prices F.0.B. Portland given in phone call to Ash Grove Cement Company. 9.5] 9.6 METHANOL FROM COAL Process Description Nearly all the methanol produced in the United States uses natural gas as feedstock, while the rest of the world depends heavily on naphtha and other hydrocarbons. When natural gas and naphtha are used as feed- stocks, they are steam reformed to produce a synthesis gas. When heavier hydrocarbons are used as feedstock, they are gasified by partial oxida- tion with steam and oxygen in a gasifier to form synthesis gas. The synthesis gas from the reformer or gasifier is then pressurized and sub- sequently converted into methanol in a catalytic packed converter. Two major types of converters are used. The older ones operate at 200-300 atm and 300°C with zinc/chromium oxide catalysts. Newer units use copper catalysts and operate at 50-100 atm and 250-270°C. The methanol produced from the converter is ready to be used as methyl-fuel. Commercial grade methanol is obtained by the distillation of crude methanol. As mentioned early, the feedstock for the methanol synthesis in the U.S. is exclusively natural gas. However, as natural gas reserves are depleted, coal will be the logical choice to replace it as the feed material for the methanol synthesis. The development of the advanced coal gasification processes, which effectively convert coal to gas, makes the methanol synthesis gas from coal similar with that from natural gas. With 200 billion tons of proven minable coal and lignite reserves in the U.S. there should be no problem in supplying the raw material required for the future methanol and methyl-fuel synthesis for this country. A schematic process flow sheet for methanol synthesis via coal gasification processes can be constructed as shown in Figure 9.1. Coal from storage is crushed to proper size and charged into coal feed lock hoppers. If the process is operated at atmospheric pressure, coal can be fed directly into the gasifier. Coal, in the gasifier, is converted to a gas stream containing mainly CO and Ho by steam, oxygen (or air), and other gasifying media. The gasifier effluent is then passed through 9.52 €S°6 WATER me METHANOL as SYNTHES1S CONVERTER ot oe Son REMOVAL E =) EEL Ue 3 u COMPRESSORS WASTE HEA SHIFT Yj) COAL FEED RECOVERY CONVERTER ©) 1) LOCK HOPPERS 6 { owt) Ce ACID-GAS SEPARATOR phe i wy REMOVAL UNIT OR AIR . ASH LET DOWN TO TANK DISTILLATION CRUDE METHANOL FIGURE 9.1. Methanol Synthesis via Coal Gasification Processes a dust collector and scrubber to remove particulates and tar from the gas stream. Depending upon the type of process and operating conditions the composition of the gasifier effluent varies substantially. If the proportions of CO, CO, and Ho in the gas is correct and the sulfur content is low enough for the methanol synthesis, the gas is pressurized and directly introduced to the methanol converter. However, in most cases, the gases generated from gasifiers require some adjustments in gas composition and purification to remove undesired impurities before they are used for the methanol synthesis. O/H, and C0,/H, ratios can be adjusted by passing the gas through a shift converter and/or a C0, removal unit. Sulfur compounds (mainly in the form of HS) can be removed from gas stream by monoethanol amine, hot potash, rectisol pro- cesses, and others. The cleaned synthesis gas is then pressurized and fed into various methanol synthesis loops. The crude methanol produced from the converter, after pressure letdown is ready to be used as methyl- fuel. If pure methanol is desired, distillation of the crude methanol is required. Process Economics Producing methanol from coal cannot compete with steam methane reforming at current natural gas prices on the Gulf Coast ($2.00/million Btu) as can be seen in the following process work sheet. Improvements in gasification technology which allow pressurization of the gasifier (which traditionally has been run at atmospheric pressure) would trim both capital and operating costs for production of methanol from coat. (3) A 10-15% reduction in capital and operating costs would reduce methanol costs by 3¢/4¢/gal. Assuming these improvements in gasification technology are made and natural gas rises to $2.25/million Btu, coal at approximately $0.50/mil- lion Btu ($10/ton) is required to compete with natural gas. (In Alaska methanol from coal still could not compete due to significantly higher capital and operating costs.) 9.54 nrPn — 10. He 12. 13. 14, PROCESS WORKSHEET - ALASKAN INLAND LOCATION Process Methanol Production from Beluga Coal ., DUUU ton/day fueT gate Capacity_methanol a Feedstock Requirements Capital Investment $573 mm 1,194,000 lb/hr Beluga Coal ($100 Btu/1b, 25% moisture) Operating Costs: A. Feedstock Costs @ $1..00/10° Btu B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $1/10° Btu (coal) Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.03/Mgal Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 80 @ $30,000/yr. (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Total Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price Shipping Costs West Coast) $/gal $/gal (Ship or barge to West Coast FOB West Coast FOB $/gal $/gal Total Costs Current Price 9.55 $76.3 x 10°/yr en $1.5 x 10 /yr $ 77.8 x 10°/yr $11.0 x 10°/yr (172,000 1b/hr Beluga 6 Coal) $11.2 x 10°/yr ae $ 2.0 x 10-/yr 2 $ 2.6 x 10 /yr $0.9 x 10°/yr $0.4 x 10°/yr $ 28.1 x 10°/yr $ 2.4 x 10°/yr $ 0.5 x 10°/yr ee $20.9 x 10 /yr $ 2.4 x 10°/yr $10.5 x 10°/yr Se $52.3 x 10-/yr § 89.0 x 10°/yr $194.9 x 10°/yr =; $194.9 x 10°/yr $135.8 x 10°/yr $330.7 x 10°/yr $ 0.67 $0.03 $ 0.70 $ 0.47 (a) Includes development of transportation from mine mouth to north shore at Cook Inlet of terminal facilities on the north shore. Also includes development (.$80 mm) Economic Plant Scale The approximate minimum reference size for a coal to methanol plant has been estimated to be 5,000 to 15,000 bbl/day (700-2100 tons/day). The most economic size would appear to be 20,000 to 35,000 bb1/day (3000 to 5000 tons/day). (1) Capital Costs Table 1 gives estimated capital costs for coal to methanol plants. TABLE 1. Coal to Methanol - Capital Costs Capital Investment $M Size Gasification At Time Estimated Reference Tons/D MeOH Coal Type Process of Study 1978 (2) 5000 Easkin Bit. Koppers-Totzek 253 (1974) 345 (2) 5000 West. Subbit. Winkler 241 (1974) 330 (3) 5000 - Winkler 273 (1975) 330 A similar plant built in the Cook Inlet area would cost approximately $495 million in 1978 dollars based on 50% increase in capital costs for this area. Additional capital investment would be required to develop a transportation system to move the coal from the Beluga fields to the north shore of the Cook Inlet (14-24 miles) and a shipping terminal would have to be built on the north shore. This additional capital investment is estimated at $80 miltion’*) $575 million. bringing the total capital investment to Markets Methanol is produced at 11 plants in the U.S. with a total capacity of 1312 million gallons annually. All 11 plants are located in the Gulf Coast area. (See Table 2.) Demand for methanol was 1015 million gal- lons in 1977 and has grown at 6.2 percent per year over the past 10 years. Future growth is predicted to be 6-8 percent per year through 1981. Current price for methanol is $0.44/gal FOB Gulf Coast. 9.56 Table 3 shows the uses of methanol. Forty-three percent of the meth- anol produced goes to synthesis of formaldehyde. A significant portion (.15%) of formaldehyde production is in the Pacific Northwest. (This would seem to be the logical market for methanol produced in Alaska. ) Formaldehyde is expected to grow at 7-8 percent per year through the next 5 years. Acetic acid is the fastest growing end-use for methanol and is likely to take a larger share as this technology becomes more widely used. The possibilities for methanol in the future are myriad--transporta- tion fuel, protein synthesis, steel manufacture, sewage treatment, and peak power generation represent only a partial list. The leap from theory to commercial use will depend on a number of factors, including coal gasification technology, international politics, and allocation of capital for pilot plants. One major expansion is now set for the late 70s and one is a good possibility. Other expansions will most likely come in the form of incremental revamping and process improvement. OA57) TABLE 2. U.S. Methanol Production'°) Producer Capacity Air Products, Pace, FL 50 Borden, Geismar, LA 160 Celanese, Bishop, TX 150 Celanese, Clear Lake, TX 230 DuPont, Beaumont, TX 200 DuPont, Orange, TX 100 Georgia-Pacific, Plaquemine, LA 120 Hercules, Plaquemine, LA 100 Monsanto, Texas City, TX 100 Rohm & Haas, Deer Park, TX 22 Tenneco, Houston, TX _ 80 Total 1312 (a) Capacity in millions of gallons annually. TABLE 3. Uses of Methanol Formaldehyde synthesis Methyl halides Methylamines Methyl methacrylate Dimethyl terephthalate Solvent uses Other Total 9.58 (6) 45 4 4 (a) 1. REFERENCES Methanol from Coal. Oak Ridge Associated Universities for the Energy Research and Development Office of the Federal Energy Admin- istration Under Contract No. 14-01-001-1699, February 1976. The Introduction of Methanol as a New Fuel into the United States Economy. American Energy Research Company, March 1976. Coal Chemicals Are Making a Comeback. Chemical Engineering, September 1, 1975. Clean Energy from Alaskan Coals. Stanford Research Institute for the Energy Research and Development Administration Under Contract No. E(49-18)1516. January 1976. Chemical Profile - Methanol. Chemical Marketing Report, March 7, 1977. Chemical Production from Waste Carbon Monoxide - Its Potential for Energy Conservation. Battelle Pacific Northwest Laboratories for the Department of Energy Office of Conservation Under Contract No. EY-76-C-06-1830, November 1977. Methonal: Its Synthesis, Use as a Fuel, Economics, and Hazards. A thesis submitted to the Faculty of the Graduate School of the University of Minnesota by David LeRoy Hagan, December 1976. 9.59 9.7 PETROLEUM REFINING Petroleum refining is the separation and processing of crude oil fractions into various salable products. The products produced and the processing schemes used are different for every refinery depending on the crude oil type and the product slate desired. Closely related to petroleum refining is the production of petrochemicals from refined products. Figure 1 shows a block flow diagram of a multipurpose refinery and petrochemical complex. Crude oil distillation is the major initial operation in nearly all refineries. The oi] is separated into six major fractions according to their respective boiling points. From lowest to highest boiling points these are light ends (Cy and lighter), straight run gasoline, naphtha, kerosene, gas oi], and reduced crude. The light ends cut is treated to remove sulfur (usually HS) and then is either sold (LPG), used as refinery fuel, or used as in-plant process feed (alkylation, hydrogen production, or olefin production). Straight run gasoline goes directly to the gasoline blending pool or is subjected to isomerization for octane improvement and then goes to the gasoline blending pool. The naphtha cut is hydrotreated to remove sulfur and then is catalytically reformed. Catalytic reforming produces a high octane stream containing high quantities of aromatics. Reformed light naphtha typically is used as feed to an Aromatics Complex for production and/or recovery of BTX (benzene, toluene, and xylene) and other aromatics (cumene, ethylbenzene, etc.). Reformate from heavy naphtha goes to the gasoline pool. Naphtha is also the most common feedstock for olefins production. The kerosene cut is treated to remove sulfur and goes to the distil- late blender. The main products of the distillate blender are jet fuel, diesel fuel, and No. 2 fuel oil. 9.60 19°6 CRUDE OIL CRUDE UNIT REDUCED CRUDE LIGHT ENDS (C4) STRAIGHT RUN GASOLINE Ho KEROSINE GAS OIL VACUUM DISTILLATION RESID DESULPHURI ZATION COKING J NATURAL GAS/C, 4 NAPTHA STEAM HYDROGEN PLANT REFORMER Hy TO PROCESSES FUEL OIL BLENDER —> Cy OLEFINS LPG TREATING NAPTHA PRODUCTION GAS Ol —®| AND SEPARATION ALK YLATE ALK YLATION | SOMERATE GASOLINE |__g ISOMERI ZATION REFORMATE| BLENDER NR I nl CATALYTIC j}-—» HYDROTREATING REFORMING DISTILLATE |p| AROMATICS TREATING COMPLEX fm C4 HYDROCRACKING FLUID CATALYTIC Tenant DISTILLATE HYDROTREATING BLENDER FIGURE 1. FUEL GAS LPG ETHYLENE PROPYLENE BUTYLENE BUTADIENE REGULAR GASOLINE PREMIUM GASOLINE UNLEADED GASOLINE BENZENE TOLUENE CUMMENE ETHYLBENZENE XYLENES JET FUEL DIESEL FUEL NO. 2 FUEL OIL HIGH SULFUR FUEL OIL LOW SULFUR FUEL OIL PETROLEUM COKE ASPHALT Multipurpose Refinery and Petrochemical Complex Block Flow Diagram There are several processing options for the gas oil cut depending on crude oil type and desired product slate. If the refinery is gasoline oriented, the light gas oi] can be hydrocracked to gasoline and other distillates. Heavy gas oi] goes to the fluid catalytic cracker which produces additional gasoline and distillates as well as a heavy fuel oil. If the refinery is oriented toward residual fuel oil production, the gas oil is hydrotreated to remove sulfur and then goes to the fuel oi] blender. Depending on the sulfur content of the gas oil and the desired sulfur content of the fuel oil, gas oil may go directly to the fuel oil blender. As with gas oil there are several options for reduced crude pro- cessing. In a residual fuels oriented refinery the reduced crude is either hydrotreated in a residium desulfurizer to produce a low sulfur fuel oil or goes directly to the fuel oil blender depending on the fuel oil sulfur content desired. To produce additional gasoline and distil- late the reduced crude can be vacuum distilled into additional gas oils and a vacuum residium. Depending on crude type the vacuum residium can be used directly as asphalt or as fuel oil. It also can be fed to a residium desulfurizer to produce low sulfur fuel oil, or it can be fed to a coker to produce additional gas oils and distillates and petroleum coke. The gasoline blender combines all the gasoline streams in the refinery and various additives to produce regular, premium, and unleaded gasoline. The distillate blender combines various distillate streams to produce jet fuel, diesel fuel, and No. 2 fuel oi]. The fuel oi] blender combines various residual fuel oil streams to produce residual fuel oils of various sulfur contents. Production of basic petrochemicals from refinery feedstocks is often considered part of the refining process. The most common applica- tions are production of olefins (ethylene, propylene, butylene and buta- diene) by cracking naphtha, and recovery and separation of benzene toluene, and xylenes from catalytic reformate by extraction and distillation. 9.62 Synthesis of cumene, ethylbenzene and other more complex aromatics is also commonly part of the refining process. Trends in Process Development Table 1 shows the production of U.S. refineries in 1955 and 1975. The past 20 years have resulted in only small changes in the product slate (increasing jet fuel production, and decreasing residual fuel pro- duction); however, it appears that during the next 20 years significant changes will take place due to depletion of the world's petroleum reserves. It is generally agreed upon that in the long term (2001) petroleum refiner- ies will be used only for production of transportation fuels (gasoline, diesel, and jet fuel) and for petrochemicals. These are the areas where it will be most difficult to replace petroleum with alternate energy sources. Coal and nuclear will gradually take over in the field of producing electricity. Natural gas, electricity, and solar energy will dominate home heating and coal will be dominant in industrial heating applications including petroleum refineries. This leaves transportation fuels and petrochemicals for petroleum. With regard to transportation, only methanol used with gasoline or by itself appears likely to have an impact between now and the end of the century. Syncrudes from shale oi] and coal are not expected to make significant contributions in this century. Coal and natural gas based petrochemical production is viable; however, coal is better suited to power generation and the demand for natural gas for home heating is not likely to leave significant quantities available for petrochemical production. In the short term (1980s), however, refiners may be forced to shift toward increased production of residual and distillate fuels. Develop- ment of nonpetroleum energy sources (principally coal and nuclear) has been slowed tremendously. Imported petroleum and increased production of 9.63 TABLE 1. Yield and Throughput u.s. (1) Refinery Industry % Volume Product 1955 1975 Gasoline 46.4 49.6 Jet fuel 20 6.6 Kerosene and distillate fuel oil Zou alee Residual fuel oil 14.7 O43 Lubes, wax, coke, and asphalt 6.0 730 Other 5.8 643) TOTAL 100.0 100.0 Total throughput, 1,000 b/d 7,857 13,224 residual fuels appears to be the only means of making up for recent delays in development of nuclear and coal energy. Economic Plant Scale It appears that feed rates of processing units are approaching their maximum economic size. New crude units will not be substantially larger than 200,000 B/D, cracking units larger than 80,000-100,000 B/D, nor catalytic reformers larger than 30,000-50,000 B/D. Small refineries, capacity under 50,000 B/D, are economically viable under certain special conditions. Energy and Utility Requirements Table 2 shows typical energy and utility requirements for a petroleum refinery. Overall, refineries consume the energy equivalent of approxi- mately 10% of the crude they process. New refineries, by making greater use of heat exchangers, improving furnace efficiencies, and providing closer process integration, may reduce the energy required by about 25%. 9.64 TABLE 2. Refinery Energy and Utility Requirements Steam 10-50 1b/bb1 Recirculating Cooling Water 200-800 gal/bb1 Power 1-5 kWh/bb1 Water Consumption 1 bb1/bb1 Fuel 300 x 107-600 x 10° Btu/bb1 Capital Cost The capital cost of a petroleum refinery varies significantly depending on the crude type to be processed and the desired product slate. Table 3 shows the effect of crude type on capital cost for grass roots refineries of various sizes. The capital costs are for a refinery of average complexity, located on the Gulf Coast, producing mainly trans- portation fuels (gasoline, diesel, and jet) and heating fuels (home heat- ing oil and residual fuel). TABLE 3. Capital Costs of Petroleum Refineries (2) Refinery Type Capital cost, $MM Mbpsd Feedstock 1970 1977 250 Lt. Arab. 383 515 250 Low sulfur 229 307 150 Lt. Arab. 259 349 15 Lt. Arab. 40 54 15 Low sulfur 22 29 A similar refinery located on the Kenai Peninsula, processing 150,000 b/d of Alaskan North Slope crude cans, would have a capital cost of approximately $525 million. Basic capital costs for North Slope and Arabian Lite would be similar. North Slope is lower in sulfur (1.04% to 1.8%) (4) so less desulfurization would be required; however, North Slope is also heavier (28° API to 33° apr) (4) so additional cracking would be 9.65 required. The major difference is the relocation to the Kenai Peninsula from the Gulf Coast which results in approximately a 50% increase in capital costs. A somewhat more complex refinery producing significant quantities of olefins and aromatics in addition to transportation fuels and residual fuels would have capital costs approximately 50% higher ($525 million - Gulf Coast, $765 million - Kenai Peninsula). For a refinery producing only transportation fuels and petrochemicals (olefins and aromatics) capital costs would be 100-150% higher ($875 million - Gulf Coast, $1315 - Kenai Peninsula). Labor Requirements It has been estimated that a world scale refinery in Alaska would provide permanent employment for over 400 people at the refinery and indirectly would result in permanent employment for over 600 more people most of whom would be Alaskans. During construction the labor force (5) would average approximately 2600. Lead Time The lead time required to bring new petroleum refining facilities on stream varies from 3 to 6 years, depending on the size and complexity of the refinery. Marketing The Petroleum Administration for Defense District (PADD) V consist- ing of the States of Alaska, Arizona, California, Hawaii, Nevada, Oregon, and Washington is the closest market for refined products from an Alaskan refinery and as a result it is the most attractive market since trans- portation charges are the lowest of any market area. Forecasts for the demand for refined products in PADDV are presented in Table 4, (6) To meet the demand for these products PADDV refineries currently are processing a crude mix of heavy, high sulfur, California crude; light, low sulfur, Indonesia crude; light, high sulfur, Arabian crude and some Alaskan North Slope crude. The number and capacity of refineries 9.66 19°6 Product Demand - PADDV (1976-1985) (©) TABLE 4. (1000 barrels/day) 1976 1977 1978 1979 1980 b/d % b/d % b/d % b/d % b/d % Gasoline (2) 1030 43.8 1080 41.1 1120 41.5 1150 41.9 1180 42.2 Jet Fuel 290 12.3 290 11.1 300 11.1 B15) Tile) 330 11.8 Mid-Distillate 285 12.1 340 12.9 365 13.5 390 14.2 420 15.0 Residual 445 18.9 575 21.9 550 20.4 520 18.9 485 17.3 Other 300 12.8 (340 12.9 360 13.4 (370 13.5 (380 13.6 Total 2350 100 2625 100 2695 100 2745 100 2795 100 Totat >) 2625 2725 2810 2865 2920 2975 3005 3035 TOTAL 2350 2625 2695 2725 2810 2865 2920 2975 3005 3035 SOURCE: (a) The Near-Term Outlook for Petroleum Demand in District V, W. J. Levy Consultants Corp., New York, December 1977. (b) Based on conversations with oi] companies operating on the West Coast. 89°6 TABLE 5. (January 1, 1977) Petroleum Refineries Number and Capacity of Petroleum Refineries in PADDV (6) Crude 0i1 Distillation Crude 0i1 Throughput Capacity Refining District, (Number) (Barrels per Calendar Day PADD District Oper- Shut- Operable Inoperable and State Total ating down Total Operating Shutdown Shutdown Total Building PADDV Alaska 2 - 60,000 60,000 - - 60,000 25,000 Arizona 1 - 5,000 5,000 - - 5,000 - California 40 - 2,326,320 2,081,942 244,378 6,000 2,332,320 1,500 Hawaii 1 - 40,000 40,000 - - 40,000 - Nevada - ] - - - 500 500 2,500 Oregon - ] 14,000 - 14,000 - 14,000 - Washington 7 ] 367,900 363,400 4,500 - 367,900 1,500 Total 51 3 2,813,220 2,550,342 262,878 6,500 2,819,720 30,500 SOURCE: U.S. Department of the Inrerior, Bureau of Mines, Petroleum Refineries in the United States and Puerto Rico, January 1, 1977. in PADDV is given in Table 5. Comparing the total refinery capacity in PADD (Table 5) with the total product demand in PADDV (Table 4) indicates there’ is significant overcapacity in the region (2.8 x 10° B/D capacity - 2.35 x 10° B/D demand). Very little capacity was being added as of January 1977. No major expansion in refining capacity is planned in the region, and it is doubtful that an expansion will take place until the present uncertainty over a national energy policy is resolved. This lack of planned expansion comes despite the large surplus of crude oil available on the West Coast as a result of introduction of Alaskan North Slope crude oil into the market. Alaskan North Slope cannot directly replace imported crude oi1 on the West Coast. Alaskan North Slope is significantly heavier than Indonesian and Arabian imports and existing PADDV refineries cannot totally replace imported crude with ANS and meet the product demand slate for the region. The current surplus on the West Coast is 400,000 B/D which is being shipped to the Gulf Coast and Virgin Islands via the Panama Canal. It has been estimated that the surplus crude available on the West Coast may reach 725,000 B/D by 1985. ‘7) Due to its lower quality and the required product slate on the West Coast, ANS is currently and will likely remain the surplus crude. Assessment of Market Conditions Since the 1973 oi] embargo the petroleum industry has operated in a rather uncertain manner. Few long term capital and contractual commit- ments have been made. More recently, the industry is trying to antici- pate the impact of the proposed National Energy Policy. Based on this cautious investment philosophy and the current over capacity on the West Coast it is unlikely that any expansion on the refinery capacity on the West Coast will be planned in the next few years. Should any expansion occur it would most likely be an addition or modification to an existing facility. 9.69 A grass roots refinery specifically designed for Alaskan North Slope crude and planned to come on stream after 1985 (by which time demand may finally exceed refining capacity in PADDV) is a possibility. If this were to come about California would be the favored location over Alaska due to the higher capital costs in Alaska; however, environmental concerns in California might make it impossible to build such a facility. A company or group of companies with a demand for refinery products (residual fuel for power plants, feedstock for petrochemicals, etc.) that would like to secure their own source of crude oil might be willing to build a refining complex in Alaska to obtain Alaska's royalty oil. This would appear to be the only way a petroleum refinery is likely to be located in the State of Alaska. 9.70 REFERENCES "Petroleum 2000," The 0i1 and Gas Journal, August 1977. "Unit Utility Requirements of Refinery Processes," The 0i1 and Gas Journal, October 31, 1977. "Outlook for Refining Capacity," Hydrocarbon Processing, June 1977. "Guide to World Crude Export Streams," The Oi] and Gas Journal, March 29, 1976. "Proposal for Utilization of Alaskan State Royalty 0i1," Alaska Petro- fining Corporation, October 1977. "North Slope Royalty 0i1 Market, Pricing and Revenue Analysis," Battelle Pacific Northwest Laboratories, Richland, WA. Prepared for Division of Research Services, Legislative Affairs Agency, Alaska State Legislature Under Contract No. 2311203378, March 1978. "Where Will North Slope 0i] Go?", Chemical Engineering, March 14, 1977. 9.71 orn — ~ 10. Me NZ LEE 14. Ss 16. We 18. PROCESS WORKSHEET - ALASKAN CCASTAL_ LOCATION Process _ Petroleum Refining Capacity 150,000 b/d Feedstock Requirements 3. Capital Investment__$525 Alaskan North Slope Crude - 49.5 x 10° bbl/yr Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.024/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.03/Mgal Total D. Labor, Naintenance, Overhead, etc.: Operating Labor, 180 8 $30,000/yr (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Total Annual Manufacturing Costs Co-product/By-product Creaits: Total © Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound Shipping Costs (Ship or barge to West Coast) $/bbl Total Costs $/bb] Current Price $/bbl on West Coast Net Surplus Applied to Domestic Feedstocks $/bb] Crude 0i1 Shipping Costs (Valdez to Kenai) $/bb1 Average Entitlements for North Slope Crude $/bb1 Allowable Cost of Crude 0i1 (FOB Valdez) 9.72 § 3.3 x 10°/yr $ 4.45 x 10°/yr $ 2.38 x 10°/yr $ 1.25 x 10°syr $ 2.08 x 10°-/yr $ 0.65 x 10°/yr $ 0.74 x 10°/yr $ 5.40 x 10°/yr $1.08 x 10°/yr $18.00 x 10°/yr $5.40 x.10°yyr $9.00 x 10°/yr $45.00 x 10°/yr $ 3.3 x 10°/yr $11.6 x 10°/yr $83.9 x 10°/yr $98.7 x 10°/yr $98.7 x 10°/yr $120.0 x 10°/yr $218.7 x 10°/yr $_4.42/bb1 $ 0.70/bb1 $_5.12/bb1 $_15.60/bb1 $ 10.48/bb1__ $ (0.30/bb1) $_ 2.50/bb1 $ 12.68/bb1 9.8 PETROCHEMICALS AND AGRICHEMICALS FROM NORTH SLOPE NATURAL GAS The natural gas from Alaska's North Slope represents a potential feedstock for the production of petrochemicals and agrichemicals. Devel- opment of these industries could provide benefits to the State of Alaska in the form of development and alternate markets for the State's royalty natural gas. This analysis was undertaken to determine the economic viability of a chemical production complex utilizing North Slope natural gas. A brief profile of the various chemical commodities evaluated in this analysis follows. Ethylene and Propylene The tremendous growth in ethylene consumption as a chemical inter- mediate is one of the real success stories of the petrochemical industry. Prior to World War II its growth rate paralleled and reflected continued increased demands for ethylene glycol and synthetic ethyl] alcohol. With the advent of a commercial styrene industry in 1944, greater demands for ethyl chloride beginning in the late 1940s, and the rapid use of poly- ethylene as a major plastic beginning in 1950, the rise in ethylene de- mands can best be described as spectacular. These new demands, cou- pled with additional requirements for ethylene oxide and synthetic ethyl acohol, have brought ethylene to the number-two spot, second only to ammonia, in the petrochemical industry. Four new large end uses for ethylene opened up in the late 1960s and 1970s, namely, ethylene-propylene elastomers, a-olefins, linear alcohols, and vinyl acetate. Prolyethylene is the largest outlet for ethylene, accounting for about 40% of production. The three important plastics, polystyrene, polyethylene, and polyvinyl chloride, represent very sig- nificant markets for ethylene. Ethylene derivatives, ethylene dichloride, ethanol, etc., consume another 40% of ethylene production. oes Ethylene, both in number of kilograms produced for chemical use and in dollar value, is the world's most important petrochemical build- ing block. Ethylene is unique in that it must be used close to the point of production, since it is not easily transportable. Furthermore, pro- duction costs are favored by very large manufacturing facilities. More than anything else, these two facts have been responsible for the petro- chemical empire along the Gulf Coast of Texas and Louisiana. Most ethylene/propylene production is located on the Gulf Coast, although plants are also located on the East Coast, in the Midwest and on the West Coast. Propylene, after ethylene and benzene, is the third most important olefin used as a petrochemical building block. It is fast emerging from its position as a low-value ethylene by-product to a rival of ethylene for the position of major chemical and plastic feedstock. Propylene is actually produced in much larger quantities than ethylene; however, all production capacity is not available to the chemical industry. The bulk of propylene production is consumed in the manufacture of gasoline- alkylate and polymer gas. The demand for polypropylene makes it the largest outlet for propy- lene, accounting for 23% of production. Propylene oxide and acrylonitrile vie for the second-place market for propylene. Oxide consumption is growing fast as a result of the growth of urethane and polyester resins. Other major outlets include isopropyl alcohol, cumene, and oxo chemicals. At the present time there is worldwide overcapacity in the ethylene industry. This situation is expected to continue through 1981, when U.S. capacity is expected to reach 43.4 billion pounds due to expansions and new plants. Demand is expected to grow at a modest 5-6% per year to about 30 billion pounds in 1981. Propylene demand is expected to grow a faster 8-9% per year rate. 9.74 Economies of scale have led to large ethylene/propylene plants with production capacities on the order of 250 million to one billion pounds per year. The capital cost for such a plant located on the Gulf Coast is in excess of 200 million dollars. Process Description In general, ethylene and propylene plants are of two types: refinery-connected, where ethylene and propylene are isolated from off- “gases or other refinery products; for example, ethane, propane, are used for at least part of their feedstock; and plants that obtain these pro- ducts by intentional cracking of hydrocarbons. Almost any naphthenic or paraffinic hydrocarbon heavier than methane can be steam-cracked to yield ethylene and propylene. Feedstocks cur- rently used throughout the world are ethane, propane, butane, naphthas, gas oils, and even crude oils. Lower-molecular-weight feedstocks normally produce higher yields of ethylene; higher-molecular-weight feedstocks result in a higher propylene/ethylene ratio. In the U.S. about 75% of the ethylene produced by steam-cracking hydrocarbons was derived from ethane and propane. The remainder was derived from naphtha or gas oil. A shift to heavier feedstocks can be expected due to rising prices and shorter supplies of ethane and propane. Currently, about 75% of propylene is derived from petroleum refineries and 25% from intentional cracking of hydrocarbons. In the steam-cracking process the hydrocarbon feedstock, diluted with steam, is passed through a pyrolysis furnace, where cracking occurs. Temperatures in the furnace are between 815 and 870°C. Steam is used as a diluent in the conversion step to inhibit coking in the furnace tubes. Contact time of the feedstock in the furnace is 1 sec or less. The yield of ethylene and propylene, as well as other cracking products, is set by this pyrolysis step. After the appropriate feedstock and conver- sion have been selected, the reaction kinetics (temperature patterns, contact time, and pressure) determine the final product distribution. 9.75 Ethane is the preferred feedstock if only ethylene is desired; propane if only propylene is desired. The hot effluent gases are cooled rapidly to quench the pyrolysis reaction, usually in a quench tower. A four-stage, two-case centrifugal compressor then pressurizes the cooled pyrolysis gases to over 500 psig. Acid gases are absorbed in a system employing monoethanolamine, caustic, and water. After flashing off the hydrogen, the dried gas is cooled and sent to the demethanizer, where methane is recovered overhead for fuel and the C, bottoms flow, under pressure, to the deethanizer. In this column the C. and heavier materials are removed as a bottoms stream and fed to the depropanizer. Acetylene is removed from the ethylene by catalytic hydrogenation of the deethanizer overhead. The stream from the acetylene hydrogenator is then fractionated to separate ethane gas for recycle to the pryolysis furnace and the product ethylene. The depropanizer feed is fractionated, producing Cy bottoms for transfer to the debutanizer and overhead, which, after hydrogenation to remove propadiene and methyl acetylene, goes to a C, stripper. Here propane is recovered for recycle to the furnace, and chemical-grade propylene is produced. In the debutanizer Cy fractions and pryolysis gasoline are separated for subsequent sale. Ethylene Glycol The chief uses of ethylene glycol are as a permanent "antifreeze" for motor vehicles and the manufacture of ethylene glycol-terephthalate polyester fibers, films and resins. Diethylene glycol, which is co- produced with ethylene glycol, is used in the manufacture of polyurethane and polyester resins. These end uses are expected to grow moderately. The capital cost of a plant capable of producing 300 million pounds per year of ethylene glycol is estimated at about $50 M. 9.76 Process Description The catalytic oxidation of ethylene with air yields ethylene oxide and carbon dioxide. Ethylene oxide may then be hydrated to yield ethy- lene glycol. Ethylene and air are mixed in a volume ratio of about 1:10 and passed over a catalyst composed of silver oxide. Generally, an anti- catalyst such as ethylene dichloride (about 1 ppm) is added to the ethy- lene feed to suppress the formation of carbon dioxide. At essentially atmospheric pressure and temperatures of 270 to 290°C, 60 to 70% of the ethylene is converted to ethylene oxide. The reaction products are fed to a scrubber, where ethylene oxide is absorbed. This residual gas is compressed and recycled. Ethylene oxide is stripped from solution, and then distilled to remove light ends. The raw ethylene oxide may then be converted to ethylene glycol by acid or pressure hydration in a tower reactor. The acid hydration process makes use of a 0.5 to 1.0% sulfuric acid solution. Contact time is 30 min at 50 to 70°C. In the pressure-hydration process, a residence time of 1 hr at 195°C and 185 psi is required. The weight ratio of water to ethylene oxide is 6:1. In both cases diethylene and triethylene glycol are formed as by-products. They may be separated from the ethylene glycol by vacuum distillation. Propylene Glycol Polyester resins account for over 45% of propylene glycol consump- tion. Other markets include cellophane manufacture, brake fluids, pet foods, tobacco humectant and food and pharmaceutical uses. Growth in demand will be tied to the market for unsaturated polyester resins. Current capacity of 855 million pounds is located on the Gulf Coast, with the exception of one plant in West Virginia, and is more than adequate to meet present demand of about 575 million pounds. The current Gulf Coast capital cost of a plant capable of producing 130 million pounds per year is estimated to be about $30 M. OE Process Description Propylene oxide may then be converted to propylene glycol by acid or pressure hydration in a tower reactor. The hydration of ethylene oxide in 0.5 to 1.0% sulfuric acid medium takes place at 50 to 70°C with a con- tact time of 30 min. The pressure hydration of propylene oxide takes place at 195°C and 185 psi with a residence time of 1 hr. After dehydra- tion and vacuum distillation, the propylene glycol is recovered as over- head from the distillation column. Dipropylene glycol is obtained as a by-product of propylene glycol manufacture, or intentionally by the addition of propylene oxide to propylene glycol. Styrene and Polystyrene Polystyrene plastics currently use about half of all U.S. styrene production. Styrene production was about 6,620 million pounds in 1977 with capacity rated at 9,180 million pounds. Other uses for styrene include styrene butadiene rubber, acrylonitrile-butadiene-styrene (ABS) resins and unsaturated polyester resins. A 5-6% growth rate for styrene is expected over the next 10 years. Present overcapacity may lead to some older plants being retired. Polystyrene producers have been operating at about 70% of capacity and several less efficient plants have been retired. Future growth in demand for polystyrene is expected to be about 6-7%. Over 95% of all current U.S. styrene production capacity is located jn Texas and Louisiana. Capital costs for a new Gulf Coast styrene plant with a capacity of 400 million pounds per year are estimated to be about $60 M. A styrene to polystyrene plant, rated at 200 million pounds per year, is estimated to cost about $30 M. Process Description Benzene is alkylated with ethylene in the presence of an aluminum chloride or boron trifluoride catalyst. The resulting ethylbenzene is 9.78 catalytically dehydrogenated in the presence of steam or benzene to yield styrene. Dry benzene (99%) and ethylene (95%) are continuously fed into an alkylating tower operating at essentially atmospheric pressure. A small amount of ethyl chloride is added to the ethylene feed as a source of hydrogen chloride (as well as ethylene) which acts as a catalyst promoter. Granular aluminum chloride (97.5%) is fed to the top of the alkylator at a constant rate. The reactant ratio is about 0.6 mole ethylene/mole benzene. No ethylene is recycled, and the losses to the vents are negli- gible. From 65 to 100 kg of ethylbenzene may be obtained per kilogram of aluminum chloride catalyst. The exothermic alkylation reaction is maintained at approximately 95°C by cooling water. The aluminum chloride combines with the hydro- carbon (benzene and ethylbenzene) to form a hydrocarbon-in-soluble complex (reddish-brown oil). The reaction products are fed to coolers, where the temperature is reduced to about 40°C. Here the aluminum chloride complex is separated from the crude mixture in settling tanks and is pumped back to the alkylator or to a high-temperature dealkylator. The latter, operating at 200°C, breaks down a charge of complex poly- ethylbenzenes to benzene and ethylbenzene (which are returned to the system) and a tarry aluminum chloride residue. Approximately 80% of the aluminum chloride may be recovered. The crude ethylbenzene from the settling tanks is sent to a caustic scrubbing system for neutralization. After being washed with a 50% caustic solution, the "sweetened" material is charged to a fractionating system for purification of ethylbenzene. The purified ethylbenzene is heated to 520°C. Superheated steam (710°C) and the ethylbenzene vapors are continuously mixed and fed into a reactor in a ratio of 2.6 kg steam/kg ethylbenzene. The reactor con- tains a selective fixed dehydrogenation catalyst such as zinc, chromium, iron, or magnesium oxide, on activated charcoals, aluminas, or bauxites. 9.79 At a catalyst temperature of about 630°C conversions of 35 to 40% per pass may be realized. The reaction product leaves the top of the reactor at about 565°C and is cooled to condense out tars. A final condenser liquefies the steam, styrene, toluene, and benzene. The condensed materials pass to a settling tank, where the hydrocarbons are decanted and the water is discharged to a disposal system. The crude styrene of average composition (37% styrene, 61% ethyl- benzene, 1% toluene, 0.7% benzene, and 0.3% tar) is passed through a pot containing sulfur. This stream (containing enough dissolved sulfur to act as a polymerization inhibitor) is preheated and then fed to vacuum columns. At 157 torr pressure, benzene and toluence distill ata head temperature of 57°C. The column bottoms (90°C) containing styrene, ethylbenzene, and tar are passed successively to primary and secondary vacuum columns where ethylbenzene is separated from the styrene and recycled to the reactor. Styrene is distilled in the second column to remove tar and sulfur. A polymerization inhibitor is added to the top of the column. The tarry residue discharged from the bottom is burned. The distilled styrene passes to receivers, where more inhibitor is added. The finished material is refrigerated below 20°C and loaded to insulated tank cars. The polymerization of styrene monomer to polystyrene can be accom- plished by the addition of polymerization catalysts and heat to a sus- pension of the monomer in water. The hard beads which form are separated from the water and dried. Low Density Polyethylene Low density polyethylene (LDPE) finds its main use in sheet and films. Other uses include injection molding, wire and cable coatings and other extrusion coatings. The market for low density polyethylene is expected to grow at the rate of 8.5% per year. Current production, about 6 billion pounds, is about 85% of rated capacity. Production 9.80 is centered on the Gulf Coast with other plants located in Iowa, I1llinois and California. A new plant located on the Gulf Coast, with a capacity of 400 million pounds per year, is estimated to cost about $100 M. Process Description Ethylene is mixed with recycled material and compressed to about 300 psi. A chain transfer agent (catalyst) is added and the mixture is further compressed to about 15,000 to 25,000 psi. The mixture then enters a reactor or autoclave where initiator is added and polymerization takes place. Molten polymer is separated from the remaining gaseous material which is recycled. The molten polymer is fed into a pelletizing extruder and the pellets are cooled and dried. High Density Polyethylene About 40% of U.S. high density polyethylene (HDPE) production is used in blow molding. Another 20% is consumed in injection molding with the remainder utilized in various end uses such as pipe and conduit and film and sheet products. Consumption of HDPE is expected to grow at about 10-12% per year through 1985, but present production capacity (in excess of 4 billion pounds annually) is operating at about 71-74% of maximum ratings. Over 90% of HDPE capacity is located in Texas and Louisiana and a new 150 million pounds per year plant located on the Gulf Coast is estimated to cost nearly $40 M. Process Description There are several HDPE production processes. In the Union Carbide process gaseous ethylene, comonomer and dry catalyst are fed to a reaction system consisting of a fluid bed reactor, recycle compressor and recycle cooler. The reaction occurs at pressures less than 300 psi and temperatures of 85-105°C. Circulating gas fluidizes a bed of grow- ing polymer using supported chromium catalysts. Circulation of the 9.81 ethylene gas provides monomer for the polymerization reaction and acts as a medium for heat removal. The polymer is granular and flows inter- mittently into product discharge tanks. Polypropylene Injection and blow molding products account for about 36% of polypropylene use. Fiber and filament uses, especially as a replace- ment for jute carpet backing, account for another 30%. Remaining uses include extruded products and film. Current polypropylene production capacity is about 3 billion pounds per year, but is currently operating at only 65-70% of capacity. Use is projected to grow at the rate of 10-12% per year through 1985. Most polypropylene plants are located in Texas and Louisiana. The remaining plants are located in New Jersey, Delaware and West Virginia. A new plant capable of producing a 100 million pounds per year is esti- mated to cost in excess of $50 M for a U.S. Gulf Coast location. Process Description Propylene, a hydrocarbon diluent, and a titanium tetrachloride- aluminum alkyl catalyst are continuously fed to a polymerization reactor operating at 50-100°C and 100-400 psi. The crystalline polymer formed in the reactor is insoluble and precipitates. The polymer granules are separated from the other components, dried and extruded as pellets. Molecular weight control is achieved by the addition of hydrogen gas, a chain-transfer agent. Vinyl Chloride and Polyvinyl Chloride (PVC) Nearly all vinyl chloride monomer produced is used in making poly- vinyl chloride homopolymer and copolymer resins. Polyvinyl chloride resins are used extensively in making pipe (40%) and electrical insula- tion (22%). Other uses include packaging, apparel and recreation plastic products. Cosmetic and toiletry makers have been abandoning PVC bottles because of monomer migration problems, but this use is not a large market for PVC. 9.82 Vinyl chloride monomer production capacity is about 7 billion pounds per year in the U.S. Present capacity exceeds demand and growth will be tied to the construction industry. Nearly all vinyl chloride monomer production is located on the U.S. Gulf Coast. A new 200 million pound per year vinyl chloride monomer plant is estimated to cost in excess of $20 M on the Gulf Coast. A PVC plant of the same capacity is estimated to cost about $40 M. Process Description Most vinyl chloride processes utilize the pyrolysis of ethylene dichloride to produce the monomer. Ethylene dichloride is produced by the vapor or liquid-phase reac- tion of ethylene and chlorine in the presence of a catalyst. Chlorine gas is bubbled through a tank of ethylene dibromide, and the mixed vapors are passed into a chlorinating tower maintained at 40 to 50°C. The chlorine meets a stream of ethylene gas, and the resulting reaction products are passed from the top of the tower through a partial condenser (above 85°C) into a separator. The ethylene dibromide liquefies and is returned to the process. Gaseous ethylene dichloride is fed into a fractionating column to yield a refined product. The yield is about 96 to 98%. Vaporized ethylene dichloride is then dried and passed over a contact catalyst (e.g., pumice or charcoal). The catalyst is usually packed in atainless-steel tubes directly heated in a cracking furnace. At 50 psig, with the effluent gases at 480 to 510°C, a 50% conversion and a 95 to 96% yield is attained. The hot effluent gases from the furnace are quenched by direct con- tact with a stream of ethylene dichloride. Uncondensed gases are sent to an indirect (surface) condenser to recover the remainder of the condensable vapors; the noncondensables are scrubbed with water to recover hydrogen chloride. 9.83 The combined liquid streams from the quencher and condenser are fed to a fractionation tower operated under sufficient pressure to yield vinyl chloride by condensing the overhead vapors in a water condenser. The vinyl chloride is sent to storage. In most plants the vinyl chloride facilities are built adjacent to the ethylene dichloride plant so that the binyl chloride raw materials are essentially ethylene and chlorine. Polyvinyl chloride is polymerized in an autoclave or reactor in the presence of a catalyst similar to the other plastic resins. A PVC compound can be tailor-made to achieve end properties by the addition plasticizers, fillers and other additives. Acrylonitrile About 50% of acrylonitrile production is used in the production of acrylic and modacrylic fibers. Acrylonitrile-butadiene-styrene (ABS) and styrene-acrylonitrile (SAN) resins, which are used to produce tough all-around plastics, account for another 20%. Other uses include adiponitrile production and nitrile rubber production. Capacity for the production of acrylonitrile is over 2 billion pounds and is expected to grow to about 2.5 billion by 1980. Current production facilities are operating at about 84% of capacity and this trend is expected to continue. Plants are located in Texas, Louisiana, Ohio and Tennessee. A new 100 million pound per year plant located on the Gulf Coast is estimated to cost over $40 M. Process UVescription Acrylonitrile is produced by reacting a mixture of propylene, am- monia, and air in the presence of a catalyst. Refinery propylene (40 to 90% pure) or chemical-grade propylene (90+ %), fertilizer-grade ammonia, and air in volume proportions of 1 part propylene, 1 part ammonia, and 2 parts oxygen are mixed and fed to a fluidized bed catalytic reactor. The catalyst is a supported 9.84 molybdenum-based catalyst, such as 50 to 60% bismuth phosphomolybdate on silica. At reaction conditions of 400 to 450°C, 0.5 to 2 atm and 10 to 20 sec contact time, the propylene is converted to acrylonitrile with a yield in excess of 70% of that theoretically obtainable. The reactor effluent is fed to an absorption column, where it is scrubbed with water to separate fixed gases and unreacted propylene, which are sent overhead. The water solution of acrylonitrile from the bottom of the scrubber goes to a separator, where wet acrylonitrile is taken overhead. This product is then dried and purified by distillation. Acet- onitrile bottoms from the product separator are purified by conventional distillation methods. Principal by-products are acetonitrile and hydrogen cyanide. One kilogram of propylene yields 0.84 kg acrylonitrile, 0.03 kg acetonitrile, and 0.13 kg hydrogen cyanide. Methanol (Methyl alcohol) Over 45% of the methanol produced in the U.S. is used in the produc- tion of formaldehyde. Other uses include general process solvent, methyl acrylate production, methyl halide production and the direct synthesis of acetic acid. The latter is a relatively new process and can be ex- pected to grow in the future. A pending development which would have a major impact on the production of methanol is its use as a motor fuel and a fuel for peaking power generation. Current production capacity is in excess of 1.4 billion pounds per year and the industry is operating at about 78% of capacity. Production facilities are centered in Texas and Louisiana. A new 1000 ton per day plant, based on natural gas feedstock and located on the Gulf Coast, is estimated to cost in excess of $35 M. Process Description Methanol is synthesized by the reaction of hydrogen and carbon monoxide under high pressures. The reactants, hydrogen and carbon monoxide, are obtained in a variety of ways from different raw materials. 9.85 A common source in the United States is reformed natural gas. In this case natural gas that has been desulfurized by passage over activated carbon is preheated and mixed with carbon dioxide and steam at 30 psig. The mixture is passed into heated alloy-steel tubes in a furnace. The tubes are normally packed with a promoted nickel catalyst. The reaction, which takes place at 800°C, is essentially: 3CH, + CO, + 2H,0 - 4C0 a 8H, 4 2 The resulting synthesis gas is cooled by passage through waste-heat boilers, various heat exchangers, and water coolers. A gas suitable for methanol synthesis can also be produced by partial oxidation of methane or other light hydrocarbons. Other sources of raw material gas that have been used are naphtha, heavy oils and coal. Regardless of the source of the carbon monoxide-hydrogen mixture, the ratio is adjusted so that approximately the theoretical ratio is ob- tained (2 volumes of hydrogen to 1 volume of carbon monoxide). The mixed gases are compressed in multistage compressors to pressures of 3000 to 5000 psi and heated in heat exchangers by the reaction gases. The heated gases pass through a copper-lined steel converter containing a mixed catalyst of the oxides of zinc, chromium, manganese, or aluminum. The temperature of the reaction is maintained at approximately 300°C by proper heat removal. The converter must be heated to initiate the reaction but, once started, it is self-supporting. The temperature is kept con- stant by proper space velocity and heat interchange. The methanol-containing gases leaving the reactor are cooled by the reactants in heat exchangers and condensed under full operating pressures. The pressure is released, and the cool (0 to 20°C) liquid methanol is run off. It may be further purified by distillation. The residential gases are returned to the system for reprocessing. Accumulation of inert gases is guarded against by purging part of the recycle gases. 9.86 The most recent advance is toward high-volume plants utilizing large steam-driven compressors operating at lower pressures. In this low- pressure process a copper-based catalyst is used with pressures of 50 to 100 atm. The high activity of the catalyst allows the reaction to take place at temperatures between 250 and 270°C. The process is more efficient because of lower by-product formation, lower energy costs, and lower investment and maintenance requirements. Formaldehyde Current U.S. formaldehyde production capacity is about 9 billion pounds per year, but demand is depressed to about 6 billion pounds per year. About 25% of formaldehyde production is used to produce urea- formaldehyde resins used in making plywood and particle board. Another 25% is consumed in making phenolic resins. The remainder is scattered through a variety of end uses. Growth of formaldehyde consumption is dependent primarily on housing starts. Formaldehyde production sites are scattered throughout the middle and southeastern states and along the West Coast states of Washington and Oregon. A new 400 million pound per year formaldehyde plant, located on the Gulf Coast, is estimated to cost about $6 M. Process Description Formaldehyde is made either by catalytic vapor-phase oxidation of methanol or by a combination oxidation-dehydrogenation process. Formalde- hyde and the unreacted methanol in the product gases are absorbed in water and separated by distillation in either process. Generally, air and methanol are mixed mechanically or by maintaining the methanol at a constant level and temperature in the vaporizer, through which air is drawn. The alcohol-air mixture contains 30 to 50% methanol. Residual alcohol spray is vaporized in a preheater. 9.87 The reactor contains a silver or copper gauze catalyst. The reaction over these catalysts is a combination of dehydrogenation and oxidation, the former being responsible for high yields, whereas the latter supplies heat and aids in keeping the catalyst active. The best metal oxide catalyst is a mixture of molybdenum, iron, or vanadium oxides. The reac- tion over this type of catalyst is mainly one of oxidation and requires a large excess of air, at a catalyst temperature of 450 to 600°C and a con- tact time of about 0.01 sec. Separation of methanol and formaldehyde is accomplished by alternate scrubbing and cooling; the gases then pass to a final scrubber fed with cold water and are vented to the atmosphere. These exit gases contain 19 to 22% hydrogen and 74 to 75% nitrogen. The gases also contain between 4 and 5% carbon dioxide, together with traces of CO, oxygen, and methane. The combined condensate and scrubber liquor from the main column (containing formaldehyde, water, and approximately 15% unreacted methanol) are fed into a fractionating column, where 37% formaldehyde plus the de-~ sired amount of methanol stabilizer is removed from the bottom and excess methanol is removed from the top and returned to the vaporizer. Overall yields are 85 to 90% by weight based on the methanol charged. Essentially all formaldehyde is produced from methanol. Of the two processes starting with methanol, the one using the oxide catalyst gives higher yields but is also more expensive to operate. The process is par- ticularly suitable for large plants. Ammonia Over 75% of the anhydrous ammonia produced in the United States is used as fertilizer, either directly or as urea, ammonium nitrate or other ammonium compounds. Plastics, fibers and resins account for another 10%. U.S. ammonia production capacity is in excess of 22 million tons per year, but production is about 17 million tons, or about 77% of capacity. Demand is heavily tied to agriculture and prospects for a large increase in the near future are dim. Thus, the industry is caught in a cost- price squeeze with demand falling and natural gas prices rising. 9.88 Ammonia production facilities are widespread throughout the United States in order to be close to agricultural markets. A new, natural gas based, 1000 ton per day ammonia plant is estimated to cost about $60 M. Process Description Nitrogen and hydrogen in a 1:3 ratio react catalytically at high temperatures and pressures to produce ammonia. The nitrogen is derived from the air by means of liquefaction, or by burning out the oxygen in air with hydrogen. Hydrogen is obtained from many sources, including water gas, coke-oven gas, natural gas, fuel oil, catalytic reformer gases, and the electrolysis of water or brine. Since World War II, natural gas has become the most important hydrogen source in the U.S. The natural gas is preheated, passed over a bauxite catalyst to remove the sulfur, and then treated with steam in a reforming furnace. By use of a nickel catalyst in the reformer, a 70% conversion of methane to carbon monoxide and hydrogen is attained. The partially reformed gas is then led to a combustion furnace, where sufficient air is added to give nitrogen and hydrogen concentrations that will eventually result in the 1:3 molar ratio required for best yields in the ammonia synthesis reaction. The combustion chamber also contains a nickel catalyst, so the reforming reaction is also completed in the unit. Temperature of the reaction gases reached 925°C. In the initial gas-reforming processes pressure of about 30 to 50 psi and temperatures up to 925°C were used. Modern plants use higher pressures, up to 500 psi. The gases are cooled to 425°C by a water quench and then fed to a shift converter where, in the presence of an iron oxide catalyst, carbon monoxide is reduced to less than 1%, by means of the water shift gas reaction: CO + H,0—> CO, 1 Ho 9.89 The gas is cooled, compressed to 200 psi, and sent to the gas- purification system. Carbon dioxide is removed by absorption; many absorbents are used, including monoethlanolamine solution, potassium car- bonate solution, Sulfinol (sulfolane, Cy He S0,), propylene carbonate, and others. Final cleanup of carbon monoxide and carbon dioxide (to less than 10 ppm) is accomplished by methanation. Here the gases are passed over a nickel catalyst where any remaining oxides are hydrogenated to methane. Other popular processes for preparation and purification of ammonia synthesis gas are the hydrocarbon partial oxidation process and the liquid nitrogen-catalytic reformer off-gas process. In the partial oxidation process air is liquefied and then separated into oxygen of 95% purity and nitrogen of 99.99% purity. The reforming and combustion chamber steps of the process described previously are replaced by a partial oxidation unit using 95% oxygen and a large excess of natural gas. A sufficiently high temperature results from the partial combustion to allow reaction between the excess methane and the water vapor formed by the combustion process. The effluent gases, chiefly carbon monoxide and hydrogen, are quenched and processed as pre- viously described, that is, through a shift converter and a monoethan- olamine unit. The last traces of carbon monoxide and any residual hydro- carbon are removed by washing with liquid nitrogen in a low-temperature wash tower. When catalytic reformer off gas is used as the source of hydrogen, purification may be effected by a light caustic scrub and a liquid nitro- gen wash. Nitrogen for both the wash tower and the feed stream is supplied by an air liquefaction unit. In any case the purified 3:1 hydrogen-nitrogen mixture is ready for compression to reaction pressure and feed to the ammonia synthesis unit. A typical pressure is about 300 atm although the range is wide: from 9.90 130 to 650 atm. The compressed gas is filtered to remove oil. At the inlet to the reactor, the fresh feed is joined by a recycle stream of unconverted nitrogen and hydrogen. By means of internal heat exchangers, the temperature of the feed gases is raised to 400 to 600°C, with an aver- age of about 475°C. The reactor contains an iron oxide catalyst promoted by addition of small amounts of aluminum, potassium, calcium, or magnesium oxides. The gases leaving the reactor are cooled (-10 to -20°C), and some of the ammonia liquefies. Part of the gas is purged to prevent accumula- tion of diluents such as argon, and the purge gas is used for fuel. The remaining gas is recompressed and recycled. The conversion per pass is approximately 20 to 22% and the overall yield with recirculation approaches 85 to 90%. Urea Current U.S. urea production capacity is in excess of 6.5 million tons per year. However, production is only about 4.5 million tons per year. The market for urea is very similar to that for ammonia with 65- 75% of production going to fertilizer use. Other uses are urea-formalde- hyde and melamine resins (15%) and animal feeds (10%). Prospects for growth in the near future are similar to those of ammonia--very poor. Urea production is scattered throughout the U.S. A modern 1500 ton/day plant is estimated to cost about $30 M on the Gulf Coast. Process Description Urea is produced by the indirect dehydration of the intermediate, ammonium carbamate, formed by the high-pressure reaction of excess ammonia and carbon dioxide. A description of one complete process follows. Ammonia and carbon dioxide, in a weight ratio of about 2.3:1 (3:1 mole ratio), are compressed to liquids and charged separately into a steam-heated, silver-lined autoclave (reactor). The reactants require about 2 hours to pass through the autoclave which is maintained at a 97:91 temperature of approximately 190°C and a pressure of 1500 to 3000 psi. During this time the ammonia and carbon dioxide react to form ammonium carbamate which is largely converted to urea. The reaction mixture, consisting of about 35% urea, 8% ammonium carbamate, 10.5% water, and 46.5% unreacted ammonia, is discharged from the autoclave and cooled to approximately 150°C. The melt is passed to an ammonia still, operating at 60°C, where 60 to 65% of the unconverted ammonia and any unreacted carbon dioxide are distilled and collected in an ammonia-absorption system. The absorbed materials may be reused in the reactor or converted to liquid fertilizer. The residue in the ammonia still, consisting largely cf urea and water, is discharged to a crystallizer, where it is cooled to about 15°C. About 70% of the remaining free ammonia is removed by vacuum and sent to the recovery system. The resulting slurry is passed to a continuous cen- trifuge, separating the crystalline urea. The mother liquor, containing about 21% ammonium carbamate, 38% urea, 14% ammonia, and 27% water, is sent to the ammonia-recovery system, where it is utilized in the manu- facture of the liquid fertilizer. The yield of urea in the crude melt based on the carbon dioxide charged is 80 to 85%. If the ammonia recovered by absorption is taken into account, this yield is essentially the same based on the ammonia charged. However, about 60% of this crude urea is recovered as crystal- line product, the remainder going to make up liquid fertilizer (urea- ammonia liquor). Ammonium Nitrate Ammonium nitrate, like ammonia and urea, is heavily tied to acri- cultural uses. About 80% of ammonium nitrate production is consumed as fertilizer. Nearly all the remainder is used in making explosives. U.S. ammonium nitrate production capacity is over 7 million tons/yr. Its current status is similar to those of ammonia and urea. Most ammonium nitrate is produced in conjunction with ammonia and nitric acid facili- ties. 9°92. A new 800 ton/day nitric acid-ammonium nitrate production facility is estimated to cost about $13 M on the Gulf Coast. Process Description Ammonia and nitric acid are reacted to yield ammonium nitrate either in solution or in a molten form. It is then further processed to crystal or granular form. Concentration of the nitric acid is typically 57 to 60% but may range from 40 to 65%. The chief differences between various processes are the concentra- tion of the reactants and the method used to remove the solid phase from solution. In a typical prilling process, ammonia vapor and nitric acid are reacted in a stainless-steel neutralizing vessel under agitation. As the materials come into contact, the heat of reaction causes the solution to boil, thus concentrating it to an 85% solution. The nearly neutral solution is then pumped to a vacuum evaporator and concentrated to about 95%. The hot (125 to 140°C) solution of nitrate is then pumped to the top of a spray tower, or prilling tower, about 60 miles high, whence it is discharged through a spray head. As it falls countercurrent to a stream of conditioned air, the material solidifies into small spherical pellets (called prills) about the size of buckshot. The particles are screened, dried further, and then dusted with clay or fine diatomaceous earth to minimize caking tendencies. Over- and undersized particles are separated in a final screening, redissolved, and returned to the reactor. In the Stengel process, ammonia vapor (143°C) and 60% nitric acid (165°C) are fed to a packed stainless-steel reactor. The concentration of the reactants is such that the heat of reaction vaporizes the water “present. The mixture of nitrate and water (205°C) is led to a cyclone- type separator from which steam leaves the top and molten ammonium nitrate the bottom. Air is blown through the molten nitrate to reduce the moisture content to 0.2%. The molten mass is solidified by cooling on a continuous, water-cooled, stainless-steel belt. The resulting solid 9.93 sheet of ammonium nitrate is carried to the end of the belt, removed, and ground to granular form. The granules are conditioned with clay in a coating drum and bagged for shipment. A third process for making solid ammonium nitrate is continuous vacuum crystallization. The ammonium nitrate solution (about 60%) formed in the reactor is concentrated by evaporation (65°C) to between 75 and 80% dry substance. It is then charged into a special polished stainless- steel vacuum crystallizer, somewhat similar to the Oslo-Krystal classify- ing type used for ammonium sulfate, but modified to give a rotating rather than a classified suspension and to provide adequate growth of seed crystals to intermediate sizes. By operation at a temperature of about 36°C an absolute pressure of 25 MM Hg, and a concentration of 75 to 79% ammonium nitrate, crystals of size, shape, and strength favor- able for fertilizer use are produced continuously at a relatively high rate. The product is removed from the bottom of the crystallizer ina slurry containing about 40% by weight of crystals and run to a centri- fuge. The mother liquor is returned to the system, while the crystals, containing about 1% water, are fed to a counterflow rotary dryer, where at 82°C the moisture content is reduced to about 0.1%. The crystals are usually conditioned by dusting (3 to 4% kiselguhr, for example) and then packaged in bags. Economic Evaluation An inland location adjacent to the proposed Alaska Northwest nat- ural gas pipeline was chosen as the site for this study. Other assump- tions made in this evaluation are listed below: e Costs for both construction and production are on an early 1978 basis. This avoids the necessity for escalation factors and market projections. e It was assumed that North Slope natural gas was available from a pipeline adjoining the complex; for example, the Alcan pipeline route. 9.94 e It was assumed that labor, a townsite, shipping facilities, and other infrastructure were in place at the site. e It was assumed that equipment for the plants would be shipped to Alaska for final assembly and emplacement. e A regional index factor of 2.0 times U.S. Gulf Coast plant costs was used for Inland Alaska coastal construction. The regional index factor of two times Gulf Coast costs represents a substantial barrier to competitive production. A similar situation exists in the Mid-East. The construction cost index for Saudi Arabia is estimated to be 1.66 times the index for the U.S. Gulf Coast. Large, "world scale" plant sizes were used in the study in order to take advantage of economies of scale. Assuming pipeline flow of 2.5 BCF/day with 78% extraction of ethane and 99% extraction of propane, the royalty portion of the liquid petroleum gases (LPG) is about suffici- ent to feed an olefins plant of half the size used in this study. How- ever, the ammonia and methanol plants, which use natural gas feedstock, would utilize less than 30% of the royalty natural gas available. It must be mentioned that the limited scope of this study required the adaptation of published cost information for the various chemical pro- cesses without a thorough point-by-point engineering evaluation. This point is particularly important in regard to the initial capital expendi- tures which play a dominant role in determining product unit costs and on which local conditions in Alaska could have a dramatic effect. The chemical commodities evaluated are by no means the only ones which can be produced from natural gas and LPG, but are large volume commodities for which cost information is readily available. Many of the materials are feedstocks for other chemical products which can be further processed before fabrication into end products. Appendix A contains a worksheet for each commodity evaluated. The top of each page lists the commodity produced, the size of the plant, and the capital investment consisting of plant investment plus an allowance 9.95 for working capital for each process. The capital investment estimates used in this study assume a grass roots facility wherein both the inside battery limits (ISBL), the main process elements of the plant, and outside battery limits (OSBL) facilities such as steam generation, water treatment, cooling towers, etc., are provided. For the purposes of this evaluation the OSBL facilities were estimated by adding on 35-40% of the ISBL invest- ment for each plant. Major items such as air separation plants were included in the ISBL estimates. The LPG extraction plant costs used in this study assume that the LPG plant is a conventional expander type plant with recompression. Item No. 4 on the process worksheets indicates the feedstock require- ments to be obtained from other plants in the complex or from the LPG or natural gas streams. Item 5.A indicates the annual cost for feedstocks other than natural gas and LPG which must be imported to the complex. Item 5.B indicates the cost estimates for catalyst replacement and small amounts of incidental chemicals used in each plant. Items 5.C and 5.D indicate the estimated utility requirements and labor, maintenance overhead, taxes, insurance and depreciation estimates, respectively. Item 6 is a summation of all the costs shown to this point. Item 7 indicates a credit at current mar- ket prices for any by-products produced in the process and exported. Item 8 indicates the net manufacturing cost after taking any by-product credit. Item 9 indicates a return on investment before taxes calculated at 25% of the fixed plant investment plus 10% on the estimate of working capital invested in feedstock and product inventories, work in process, accounts receivable and operating cash. Item 10 indicates total net cost plus allowance for return on investment. Item 11 indicates the net manufactur- ing cost per pound of product exclusive of feedstock costs for Item 4. Item 12 indicates estimated shipping costs per pound. Item 13 gives the total delivered cost. Item 14 indicates the current (March 13, 1978) market prices taken from Table 1. Item 15 is the net surplus per pound of 9.96 TABLE 1. Commodity Chlorine Ethylene Glycol Propylene Glycol Vinyl Chl Polyvinyl] Ammonium Acrylonit oride Monomer Chloride Nitrate, Bulk rile Formaldehyde, 37% Urea Methanol Polystyre Styrene M ne oOnomer H.D. Polyethylene L.D. Poly ethylene Polypropylene Ammonia Ethylene Propylene Naphtha Source: Current Chemical Prices Price $135/ton, FOB $0.245/1b, Delivered Eastern U.S. $0.25/1b, Delivered $0.143/1b, FOB $0.39/1b, Freight Allowed $110/ton, Delivered $0.275/1b, FOB $0.0525/1b, Delivered $130/ton, Delivered Western U.S. $0.50/gal, Los Angeles, FOB Gulf Coast $0.44/gal $0.28/1b, Delivered $0.21/1b, FOB $0.318/1b, Freight Allowed $0.315/1b, Freight Allowed $0.30/1b, Delivered $130/ton, Delivered $0.13/1b, FOB-Contracts $0.095/1b, FOB $15.50/bb1. Chemical Marketing Reporter, March 13, 1978 9.97 product which can be applied to the feedstocks in Item 4. Item 15 times the capacity in Item 2 equals the sum available to purchase the feedstocks in Item 4. Item 15 times the capacity in Item 2 equals the sum available to purchase the feedstocks in Item 4. Decreasing supplies of natural gas in the Lower 48 states and increasing gas costs are expected to cause a shift to heavier feedstocks by chemical producers in the future. For this reason, we elected com- pared Alaskan chemical production costs from natural gas to production costs on the U.S. Golf Coast using naphtha feedstock. Process worksheets for these plants are shown in Appendix B. Many of the plants produce chemicals which are used as feedstocks in another plant. By using the above method we can start at the surplus over manufacturing cost for a final product and go backward through an entire chain of plants to determine what price can be paid for LPG or natural gas and still have the entire process chain economically feasible. In several instances the surplus from a final product is not sufficient to cover the manufacturing cost of its feedstock. In this instance, manufacturing the product in Alaska is not economically viable. For example, the surplus from the manufacture of polystyrene in Alaska is $0.068/1b. The polystyrene plant produces 200 million pounds per year. Therefore, $13,600,000 ($0.068 x 200 million) is available to defray the cost of the 206 million pounds of styrene monomer feedstock required for the polystyrene plant. This amounts to $0.066 per pound ($13,600,000 + 206 million pounds) maximum that can be paid for styrene monomer. How- ever, the bare manufacturing cost (exclusive of local feedstock) for styrene monomer is $0.254 per pound, so the manufacture of polystyrene is not economically feasible even at a zero LPG price. This data is summarized in Table 2 for each process, utilizing Alaskan natural gas feedstock. Where a plant utilized two local (domestic) feedstocks, the surplus applied to each was ratioed on the basis of their current market prices. 9.98 TABLE 2. Chemical Product Economic Summary , (Basis: Alaska Inland Location) Manufacturing Product Current > Cost @ Zero Shipping Delivered Market Breakeven Allowable Hydrocarbon Hydrocarbon Cost Cost Price Point Feedstock Costs _ (a) Product Cost ($/1b) (S/ib) ($/1b) (S/1b) (S/1b) /1b6 Btu Ethylene 0.184 NA. - 0.130 > - - Propylene 0.129 NA. = 0.095 - = = Propylene 0.208 0.031 0.239 0.250 Propylene NEE. - @ 0.061 Ethylene 0.171 0.031 0.202 0.245 Ethylene N.C. - Glycol @ 0.061 Styrene 0.254 0.031 0.285 0.210 Ethylene N.C. - Monomer] @ (0.240) Polystyrene 0.158 0.054 0.212 0.280 Styrene N.C. - Monomer @ 0.066 LD. 0.252 0.054 0.306 0.315 Ethylene NGG - Polyethylene @ 0.009 H.D. 0.235 0.054 0.289 0.318 Ethylene N.C. - Polyethylene @ 0.028 Polypropylene 0.464 0.054 0.518 2.300 Propylene NG. - @ (0.190) Vinyl Chloride 0.182 0.033 9.213 0.143 Ethylene N.C. - @ (0.147) Polyvinyl 0.207 0.054 0.261 0.390 Vinyl Chloride N.C: - Chloride @ 0.128 Acrylonitrile 0.355 0.031 0.386 0.275 Propylene N.C. - @ (0.077) Ammonia @ (0.042) Methanol 0.058 0.018 0.076 0.050 Natural Gas N.C. - @ (0.002)/SCF Formaldehyde 0.018 0.017 0.035 0.053 Methanol N.C. a @ 0.042 Ammonia 0.068 0.015 0.083 0.065 Natural Gas N.C. = @ (0.001)/SCF Urea 0.035 0.022 0.057 0.065 Ammonia INsGe - @ 0.014 Ammonium 0.037 0.041 0.078 0.055 Ammonia N.C. - Nitrate @ (0.050) japhtha @ 20.300 Btu/1b. C. indicates not competitive. ) indicates negative value. (a) Ni (3 N.A. indicates not applicable; shipping cost prohibitive. c) N (a) ( 9°99 Similar data are shown in Table 3 for the Gulf Coast evaluation utilizing naphtha feedstock. Table 2 indicates that none of the chemical commodities evaluated can be produced competitively at an inland Alaskan location; not even if LPG and natural gas are available at zero cost. Looking at Table 3 (Gulf Coast chemical production from naphtha), the breakeven point for the manufacture of ethylene glycol is ethylene feedstock at a price of $0.206 per pound. After taking into account feedstock-to-product ratios and the bare manufacturing cost for ethylene, we find that the manufacture of ethylene glycol is economically viable at a naphtha price of $0.084 per pound or less. This corresponds to a price of approximately $4.11 per million Btu (assuming naphtha at 20,300 Btu/1b). Examination of Tables 2 and 3 indicates that an inland Alaska petrochemical/agrichemical complex based on natural gas is not competi- tive with a Gulf Coast complex based on naphtha. The reasons for this is the much higher construction cost index for in?and Alaska. 9.100 TABLE 3. Chemical Product Economic Summary (Basis: U.S. Gulf Coast Location - Naphtha Feedstock) Manufacturing Product Current Cost @ Zero Shipping Delivered Market Breakeven Allowable Hydrocarbon Hydrocarbon Cost Cost Price Point Feedstock Costs. Product Cost (S/1b) (s/1b) (s/1b) (S/1b) (5/1) $_ S7ibe Brus) Ethylene 0.022 FOB - 0.120 Naphthe Naphtha 0.69 @ 0.014 @ 3.53/bb1 Propylene 0.015 FOB - 0.095 Naphtha Naphtha 0.69 @ 0.014 @ 3.53/bb1 Propylene 0.115 0.006 0.121 0.250 Propylene Naphtha 3.62 Clycol @ 0.177 @ 0.074/1b Ethylene 0.095 0.006 0.101 0.245 Ethylene Naphtha 4.11 Glycol @ 0.206 @ 0.084/1b Styrene 0.145 0.007 0.152 0.210 Ethylene Naphtha 3.67 Monomer @ 0.186 @ 0.074/1b Polystyrene 0.092 0.033 0.125 0.280 Ethylene NeGs @ 0.018 L.D. 0.144 0.033 0.177 0.315 Ethylene Naphtha 2.48 Polyethylene @ 0.133 @ 0.050/1b RSD. 0.126 0.033 0.159 9.318 Ethylene Naphtha 2.89 Polyethylene @ 0.151 @ 0.059/1b Polypropylene 0.255 0.033 0.288 0.300 Propylene N.C. @ 0.010 Vinyl Chloride 0.117 0.007 0.124 0.143 Ethylene Naphtha 0.40 @ 0.040 @ 0.008/1b Polyvinyl 0.117 0.033 0.150 0.390 Ethylene Naphtha Said Chloride @ 0.253 @ 0.105/1b Acrylonitrile 0.158 0.007 0.165 0.275 Naphtha Naphtha 1.83 @ 0.037 @ 0.037/1b Methanol 0.075 FOB - 0.067 N.C. Formaldehyde 0.011 0.006 0.017 0.053 Methanol Naphtha 0.90 @ 0.084 @ 0.018/1b Ammonia 0.047 0.007 0.054 0.065 Naphtha Naphtha 0.67 @ 0.014/1b @ 0.014/1b Urea 0.022 0.006 0.028 0.065 Ammonia Naphtha 1.04 @ 0.064 @ 0.021/1b Ammonium 0.025 0.006 0.031 0.055 Ammonia Naphtha 0.37 Nitrate @ 0.053 @ 0.007/1b Naphtha @ 20.300 Btu/1b. N.A. indicates not applicable, shipping cost prohibitive. N.C. indicates not competitive. (_) indicates negative value. 9.101 10. Te V2e lise REFERENCES - PETROCHEMICALS AND AGRICHEMICALS FROM NORTH SLOPE NATURAL GAS D. Cooperberg (C. E. Lummus Co.), "Establishment of a Petrochemical Complex Based on Natural Gas." Presented at the International Conference on Natural Gas Processing and Utilization, Dublin, Ireland. April 7-9, 1976. "Basic Considerations for Manufacture of Petrochemicals in Alaska," El Paso Products Company, October 14, 1976. R. A. Bacon, J. E. Gentel, "Petrochemical Venture in Alaska," Dow Chemical Company, December 3, 1975. T. B. Baba, J. R. Kennedy (Stone & Webster Engineering Corp.), "Ethylene and Its Coproducts: The New Economics," Chemical Engi- neering 83:116-128. Edward R. Hayes (Northwest Pipeline Corp.), "Alcan Pipeline Presenta- tion: The Opportunity for Petrochemicals and Hydrogen Refining in Alaska." Speech in Fairbanks, Alaska, November 5, 1976. J. H. Prescott, "Butadiene's Question Mark," Chemical Engineering 83:46-50, August 12, 1976. "New Styrene Plants Cut Energy Costs," Chemical Week, November 17, 1976, pp. 34-35. "Sources and Production Economics of Chemical Products," McGraw Hill Publications Co., 1974. K. M. Guthrie, "Capital and Operating Costs for 54 Chemical Processes," Chemical Engineering, June 15, 1970, pp. 140-156. A. Heath, "Improved Catalyst Boosts Acrylonitrile Route," Chemical Engineering, March 20, 1972, pp. 80-81. S. D. deBree, "Dissolved Catalyst Stars in HD-Polyethylene Route," Chemical Engineering, December 11, 1972, pp. 72-73. J. W. Winton, "Plant Sites 1977: It's North's Move," Chemical Week, November 10, 1975, pp. 35-55. P. De Lesquen, "Low-Density Polyethylene Made in Tubular Reactor," Chemical Engineering, May 29, 1972, pp. 42-43. 9.102 14. 152 16. ze 18. 19. 20. ile aes 23. 24. Zoe 26. Hydrocarbon Processing, November 1975. Various pagings. H. D. Riegel, H. Schindler, M. C. Sze, "Chlorinated Hydrocarbons Pro- duced Via Transcat," in The Petroleum/Petrochemical Industry and The Ecological Challenge, AIChE Symposium Series, No. 135, Vol. 69, 1973. F. A. Lowenheim, M. K. Moran, "Faith, Keyes, and Clark's Industrial Chemicals," 4th ed., John Wiley & Sons, New York, 1975. J. T. Cannon, Fish Engineering, Inc., Houston, Texas. Personal Communication, February 1977. C. P. Winters, C. F. Braun Co., Alhambra, CA. Personal Communica- tion, March 1977. H. Byrum, Traffic Analyst, El Paso Products Co., Odessa, TX. Personal Communication, February 1977. David M. Wallace, "Construction Costs in Saudi Arabia," 1976 Trans- actions of the American Association of Cost Engineers, July 18-21, 1976, Boston. Chemical Profiles, from The 0il Paint and Drug Reporter, Various Dates and Pagings. "Key Chemicals," from Chemical and Engineering News, Various dates and pagings. "Overcapacity to 1981 Seen for Ethylene," Chemical Week, February 8, 1978, p. 25. "But Where Will All That Ethylene Go?", Chemical Week, September 14, 19775, Ps 2. "Chementator," Chemical Engineering, October 24, 1977. "A New Life for a Senior Plastic," Chemical Week, August 17, 1977, p. 29. 9.103 9.9 PULP INDUSTRY A. GENERAL CHARACTERISTICS 1. Location of Major Producing Regions In 1974 65 percent of the total U.S. output of all types of wood pulp was produced in Georgia, Alabama, Washington, Louisiana, Florida, Oregon, Maine, Mississippi, South Carolina, and Virginia. (!) Eight out of 10 of these states are located in either the southeastern, the south- (1) the regions of the U.S. having the greatest number of kraft pulp mills per number central, or the northwestern states. Based on 1977 figures states in the region are the southeastern, the southcentral and the north- western regions. Based on the number of kraft pulp mills in Canada in 1977!) kraft pulp producers in Canada with British Columbia being the dominant > British Columbia, Ontario, and Quebec appear to be the greatest one. 2. Markets There are no known markets in Alaska for kraft pulp. 3. Industrial Structure According to information from Reference 2, it appears that the production of bleached kraft market pulp is concentrated within about four North American companies. 4. Process Description The process for producing bleached kraft pulp involves three mainline steps--wood preparation, pulping, and bleaching--and several auxiliary steps such as chemical recovery, lime reburning, and power production. A flow diagram of the bleached kraft process is illustrated in Figure 1. The wood preparation step involves removing the bark from the logs to be pulped and cutting the logs into wood chips. The pulping step involves the digestion or cooking of the wood chips at elevated temperature and pressure in a solution of sodium hydroxide and sodium sulfide called white liquor. During the digestion process the major portion of the 9.104 SOL*6 LOGS | Bel p>) CHIPPING | OF BARK oF woop | | wood LOSSES AND BARK BLEACHING AGENTS SUCH AS: CHLORINE, SODIUM HYDROXIDE, CHLORINE DIOXIDE, HYDROGEN PEROXIDE AIR DRY BLEACHING PULP | DISSOLVED REJECTED - SOLID FIBER LOSSES G) és) LOSSES CHEMICAL RECOVERY EVAPORATION AND LIQUOR OF BLACK PREPARATION KEY: @) ELECTRICAL MAKEUP ENERGY (S) STEAM WHITE: BURNING OF G) ENERGY — LIQUOR BLACK LIQUOR 7 woop Ge) RECYCLE FUEL LOSSES ENERGY FORMATION OF GREEN LIQUOR LIME RECYCLE CAUSTIZING OF GREEN LIQUOR SaS— sta eaeenaae oI ate eaten STEAM ls LIME SLUDGE TO PROCESS ome l ine of ene MAKEUP - 1] FIGURE 1. LIME REBURNING = BACK PRESSURE TURBINE POWER GENERATION Flow Diagram of Bleached Kraft Process lignin in the wood and some of the carbohydrate materials are dissolved in the digestion solution. After completion of the digestion process the contents of the digester vessel are discharged to atmospheric pressure, and the crude pulp is separated in countercurrent washers from the solu- tion called black liquor. The black liquor consists of lignin, carbohy- drate materials, and inorganic cooking chemicals. The crude pulp is next transferred to the bleaching step. The unbleached, washed pulp is bleached in multistage equipment. The bleaching step removes the residual lignin and colored impurities in the pulp while maintaining as much as possible of the pulp yield and pulp strength. The bleaching sequence involves various chemicals such as chlorine, sodium hydroxide, chlorine dioxide, and hydrogen peroxide. The black liquor from the pulping step is processed in the auxiliary chemical recovery step. First, the black liquor is evaporated to 60-65 percent solids and then burned in a smelter-type furnace for recovery of heat and cooking chemicals. Sodium sulfate may be added to the black liquor prior to the furnace to make up for sodium losses in the pulp. The molten mixture of inorganic sodium carbonate and sodium sulfide from the bottom of the furnace is dissolved in water to make the so-called green liquor. The green liquor is treated with lime (calcium oxide) to convert the carbonate to hydroxide. The clarified solution from the lime treatment is called white liquor and is recycled to the digester vessel. The lime sludge (calcium carbonate) from the lime treatment step is processed in the auxiliary lime reburning step. The sludge is burned in a kiln to convert it to lime for reuse. Steam for use in the power production step is produced by black liquor evaporation, black liquor burning, and bark burning. The steam is discharged through a back pressure turbine to produce electrical power and process steam. 5. Trends in Process Development In the pulp industry there are three basic pulping processes-- chemical pulping, mechanical pulping, and a combination of the previous two called chemi-mechanical or semichemical. There are two main types 9.106 of chemical pulping-sulfite and kraft. Sulfite pulping uses steam pressure and an acid chemical (calcium, magnesium, sodium, or ammonium bisulfite plus sulfurous acid) to reduce wood chips to pulp. Kraft pulping uses steam pressure and alkaline chemicals (sodium hydroxide and sodium- sulfide) to reduce wood chips to pulp. Mechanical pulping is accomplished by either pressing logs against a revolving grindstone or mechanically fiberizing wood chips. The dominant semichemical process is called the neutral sulfite semichemical (NSSC) process. This process consists of reducing wood chips, which have been partially softened under steam pres- sure with chemicals, to pulp by mechanical action. Of all these pulping processes the kraft process was responsible for 69 percent of the total wood pulp production in the U.S. during 1975. (1) The kraft process has changed very little since the commercial devel- opment of bleached kraft pulp in the early 1930s. Mechanical pulping involving stone grinding has changed little in the past hundred years. With the advent of the mechanical refiner, wood chips, sawdust, and shavings can be utilized to make refiner mechanical pulp (RMP). There are three potential new technologies that are being considered in the pulping industry. One is the alkaline-oxygen pulping process. This process involves an alkaline treatment to soften the wood chips, mechanical dis- integration, treatment with oxygen under alkaline conditions to remove most of the remaining lignin and finally a multistage bleach sequence-- chlorine dioxide, caustic extraction, and chlorine dioxide. This alka- line-oxygen process would eliminate the air pollution from malodorous sulfur compounds and greatly alleviate the bleach plant effluent problem. Another process that is already under development is the Rapson effluent- free kraft process. This process consists of a number of changes to the conventional kraft pulping process to eliminate effluents. Some of these changes are as follows: 1) replacement of about 70% of the chlorine normally used in the first-stage chlorination step by chlorine dioxide, 9.107 2) countercurrent washing in the bleach plant, 3) reuse of all bleach-plant effluent in the pulping step, and 4) use of the a-3(4) process for chlorine dioxide generation. A third process already in use is the thermomechanical pulping (TMP) process. This process involves preheating wood chips and then fiberizing the chips in a pressurized disc refiner which consists of two circular metal plates generally rotating in opposite directions. The TMP process compares with the refined mechanical pulping process (RMP) in that the RMP process reduces wood chips to fibers at atmospheric conditions. The TMP process improves fiber properties and allows the use of chips and residual wood which is an improvement over stone grinding for both reasons and an improvement over the RMP process for the first reason. The trends in pulp industry are toward conservation of energy, updating old equipment rather than building new plants due to the high capital cost, and recovery of as much energy as possible from wood residues. 6. Economic Plant Scale Since the kraft process produces the majority of the wood pulp, a bleached kraft pulp mill was chosen as a representative of pulp industry. According to Reference 2 the minimum size for a bleached kraft pulp mill is 600 tons of pulp/day. This was the size plant chosen for this study. 7. Capital Cost The capital costs are a major factor in the development of the pulp industry. new pulp mills is prohibitive and many of these firms are spending their 3) The capital costs for many firms considering building money to upgrade old equipment rather than build new plants. The capital costs for the hypothetical bleached kraft pulp mill for this study are $245,000,000. This involves a 1.65 scale-up factor from costs in the Lower 48 states to costs in Alaska, no costs for land on which the plant (a) A proprietary process for chlorine dioxide generation. 9.108 is built, and fixed capital and working capital. This capital investment represents about $1170 capital/air dry ton of pulp produced per year. 8. Labor Requirements The pulp industry is a mechanized industry and the labor require- ments reflect this fact. The total number of employees estimated to be needed to run the hypothetical bleached kraft pulp mill is 150-200 employees. This represents from 1 employee/4 air dry tons of pulp per day to 1 em- ployee/2.5 air dry tons of pulp per day. 9. Cost Data Sheet 10. References (1) Lockwood's Directory of the Paper and Allied Trades, Harry Dyer, Editor-in-Chief, Vance Publishing Corp., New York, NY, 1977. (2) Environmental Considerations of Selected Energy Conserving Manufacturing Process Options: Volume V. Pulp and Paper Industry Report, Report for Industrial Research Lab., Cincinnati, Ohio by Arthur D. Little, Inc., Cambridge, MA, PB-264-271 (EPA- 600/7-76-034e), December 1976. (3) Textile and Paper Chemistry and Technology, J. C. Arthur, Jr., Editor, A symposium sponsored by the Cellulose, Paper, and Textile Division at the 171st Meeting of the American Chemical Society, New York, NY, April 5-9, 1976, ACS Symposium Series 49, 1977. 9.109 nr won — 6. Te Process - Bleached (5-stage) Kraft Pulp Capacity - 210,000 ADT/YR, 600 ADT/Day, 350 pays/yr!) Capital Investment - $245,000, 0002) Feedstock Requirements - 500,000 TONS/YR (Bone Dry Wood & Bark) (3) Total Product Cost: I. Manufacturing Costs - A. Direct Production Costs 1) Feedstock Costs 2) Chemicals 3) Direct Operating Labor 4) Direct Supervision 5) Utilities Fuel (as oi1) @ $2/10°BTU Electrical Power Process Water @ $2/1000 GAL Cooling Water Makeup @ $1.20/1000 GAL Cooling Water Circulation @ $0.07/1000 GAL 6) Maintenance (Includes labor, supervision and supplies) 7) Operating Supplies 8) Pollution Control (operating & Maintenance) A. TOTAL B. Fixed Charges 1) Depreciation, 10% S.L 2) Taxes & Insurance @ 2% of Fixed-capital B. TOTAL C. Plant Overhead @ 50%(17) of I.A.3, I.A.4, and I.A.6 and II. General Expenses Administrative Costs @ 32% (18) of I.A.3, I1.A.4, and I.A.6 above Total Annual Product Cost By-Product Credits: Electricity $ 735,000'19) Tall O31 1,354,000 (2°) Turpentine 196, 000/21) TOTAL $2,285,000 9.110 $64,286,000 (4) 6,300,000 (5) 1,098,000 (6) 300,000 (7) 3,167,000 (8) -0- 4,620,000 5,040,000!) 294,000! 12) 2,310,000'13) 210,000'14) 3,150,000'15) (10) $90,775,000 $22,275,000 16) 4,455,000 $26,730,000 1,854,000 $ 1,187,000 $120,546 ,000 10. ile Ue Se 14. Net Product Cost ROI, 25% before taxes on fixed-capital plus 10% on Working Capital Net costs and ROI Net Transfer Price/ADT Pulp Shipping Costs/ADT Pulp (Tanker to Japan) Total Costs/ADT Pulp Current Price/ADT Pulp 9.111 $118,261,000 57,915,000 176,176,000 $838.93 19.60 $858.53 $365 .00(23 (22 (1) (2) (7) FOOTNOTES Based on the assumption that this pulp mill would be about the same capacity as the two existing pulp mills in Alaska. (See Reference 1, p.37). Based on the lowest estimate of 4 private firms ($225,000/ADT/DAY) and assum- ing that this estimate is just fixed-capital for the lower 48 states. It is also assumed that this value includes pollution control. A scale-up factor of 1.65 is used to adjust the cost to Alaska. Therefore; $225,000/ADT/DAY X 600 ADT/DAY X 1.65 =$222,750,000 is fixed-capital invest- ment and $222,750,000 X 0.10 = $22,275,000 is working capital $222,750,000 + $22,275,000 = $245,025,000 for total capital investment Based on a material balance given in Reference 2 for the kraft process and normalized to a 1ADT of pulp output. About 2.38 tons of wood & bark is needed to form 1ADT of pulp. Therefore; 210,000 ADT/DAY X 2.38 TONS Wood & Bark/ADT Pulp = 499,800 TONS Wood & Bark/DAY Based on the value of $150/1000 boardfeet given by Ron Galdebene-Alaskan Forest Service for the price of timber to the pulp mills. Also assuming the density of the bone dry timber is 28 1bs/ft3. Therefore; 500,000 Tons (wood & bark) /YR X 2000 LBS X FT? X 12 boardfeet X TON 28LBS FT” $150/1000 boardfeet = $64,285,714/YR Number used from Reference 3, page 93 for chemicals as $30/ADT pulp $30/ADT pulp X 210,000 ADT/YR = $6,300,000/YR Based on 0.7 man-hr/ADT from Reference 3, page 93 and assuming only 83% of that number is for direct labor. Also assuming $9.00/man-hr as based on information in Reference 4, page 2. Therefore 0.7 man-hr X $9.00 X 210,000 ADT X 0.83 = $1,098,090/YR ADT man-hr YR Based on 0.7 man-hr/ADT from Reference 3, page 93 and assuming only 17% of that number is for direct supervision. Also assuming $12.00/man-hr for supervisors wages. 9.112 (8) (10) (11) (12) (13) (14) (15) (16) (17) Therefore; 0.7 man-hr X $12.00 X 210,000 ADT X 0.17 = $299,880/YR ADT man-hr YR Calculated from information in Reference 3, page 59 and ending up with 7.54 X 106BTU to be purchased as fuel. ADT 7.54 X 10°BTU X $2.00 X 210,000 ADT = $3,166,800/YR ADT 10°sTU YR Assumed that the plant can generate all its electrical power needs from recovery processes. From Reference 3, page 93 there is 11,000 GALS/ADT. Therefore; 11,000 GALS X $2.00 _ X 210,000 ADT = $4,620,000/YR ADT 1000GAL YR From Reference 3, page 93 there is 20,000 GALS ADT Therefore; 20,000 GALS X $1.20 X 210,000 ADT = $5,040,000/YR ADT TO00GAL YR From Reference 3, page 93 there is 20,000 GALS ADT Therefore; 20,000 GALS X_$0.07_ X 210,000 ADT = $294,000/YR ADT 1000GAL YR Based on 0.6 man-hrs/ADT from Reference 3, page 93 and assuming $10.00/man-hr. Also from Reference 3, page 93 is $5/ADT for materials and supplies. Therefore; fe man-hr X so.) + $5 spelies | X 210,000 ADT = $2,310,000/YR "ADT man-hr ADT YR Based on $1.00/ADT‘ for supplies from Reference 3, page 93 Therefore; $1.00 X 210,000 ADT = $210,000/YR ADT YR Based on $15.00/ADT from Reference 3, page 94. Therefore; $15.00 X 210,000 ADT = $3,150,000/YR ADT YR Assumed to be 10% of the fixed capital $222,750,000 X 0.10 = $22,275,000/YR YR From value for Plant Overhead in Reference 3, page 93. rails (18) (19) (20) (21) (22) (23) From value for Labor Overhead in Reference 3, page 93. Based on excess production of electricity of 140KWH as given in Reference 3, page 93 and assuming power sells for $0.025/KWH i Therefore; 140KWH X 0.025/KWH X 210,000 ADT = $735,000 Bas@a'on a material balance giSen in Reference 2 for the kraft process and normalized to a1ADT of pulp output. Tall oil is produced at a rate of 86 lbs /ADT. The price for tall oil from Chemical Marketing Reproter October 31,1977 is $150/TON Therefore; 86LBS TALL OIL X 210,000 ADT X $150 X TON = $1,354,500/YR ADT YR TON 2000LBS Based on a material balance given in Reference 2 for the kraft process and normalized to alADT of pulp output. Turpentine is produced at a rate of 15LBS /ADT. The price for turpentine from Chemical Marketing Reporter October 31,1977 is $.45/GAL Therefore 15LBS Turpentine X 210,000 ADT X GAL X $.45 = $196,329. ADT YR 7.22LBS GAL Based on Reference 5, Appendix A, methanol process the transport charges are $0.0098 LB There $0.0098 X 2000 LBS = $19.60 LB ADT PULP ADT PULP Based on chart in Reference 6, page 140. 9.114 REFERENCES Lockwoods Directory of Paper and Allied Trades, 1976. Evaluation of the Theoretical Potential for Energy Conservation in Seven Basic Industries, Battelle Columbus Labs. PB-244-772, July, 1975. Environmental Considerations of Selected Energy Conserving Manufacturing Process Options: Volume V. Pulp and Paper Industry Report, Arthur D. Little, PB-264-271, December, 1976. Alaska's Forest Products Industry, State Forester, State of Alaska, Jan 1976. Alaskan North Slope Royalty Natural Gas, Battelle Northwest, August 1977. North America - Profile 1977, Pulp and Paper. 9.115 APPENDIX A PETROCHEMICAL PROCESS WORKSHEETS - ALASKAN INLAND LOCATION arn 10. i. 12. 13. 14. 15. PROCESS WORKSHEET - ALASKAN INLAND LOCATION Process LPI iquid petroleum ga raction-Expander Capacity ott a ae. ethane 3. Capital Investment _ $12) x 10° Feedstock Requirements »590 mm SCFD North Slope Gas Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu $ 8,237,000 Electrical Power @ $0.025/kWh $103,000 Cooling Water Makeup @ $1.20/Mgal $ 106,000 Boiler Feed Water @ $2/Mgal $ 16,000 Waste Water Treatment @ $1.90/Mgal $ 40,000 Cooling Water Circulation @ $0.07/Mgal $ 234,000 Total $ 8,736,000 DO. Labor, Maintenance, Overhead, etc.: Operating Labor, 12 @ $28,000/yr. $ 336,000 (includes benefits) Supervision, @ 20% of Operating Labor $ 67,000 Maintenance, @ 4% of Capital Plant $ 406,000 General Administrative and Overhead @ 100% of Labor $ 336,000 Taxes and Insurance, @ 2% of Capital Plant $ 203,000 Depreciation, 10% S.L. $10,150,000 Totai 522..490..uuc Total Annual Manufacturing Costs $20,234,000 Co-product/By-product Credits: Total Net Manufacturing Cost $20,234,000 ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital $27,325,000 Net Costs and ROI $47,559,000 Net Transfer Price/Pound Shipping Costs/Pound Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound A-1 nrFrn— 10. 1. 12. 13. 14, i. (a) Assumes product pricing ratio ethylene _ PROCESS WORKSHEET - ALASKAN INLAND LOCATION Process Qlefin Plant 1000 mm 1b/yr ethylene 3 Capacity. 243-6 ra ; Capital Investment $437 mm Feedstock Requirements _1245 mm lb/yr ethane; 902.2 mm 1b/yr propane Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 65 @ $28,000/yr. (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Total Annual Manufacturing Costs Co-product/By-product Credits: Cy Mixture @ $0.10/1b Aromatic Mixture @ $0.13/1b Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound Shipping Costs/Pound Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound 1.0 propylene 0.7 $47,559,000 _ $425,000 7,000,000 $317,000 $960,000 $200,000 $342,000 1,610,000 $ 1,820,000 364,000 $15,652,000 $ 1,820,000 $ 7,826,000 $39,130,000 _$ 6,000,000 _ $6,032,000 Ethylene--85.4% of Mfg. cost 2), Propylene--14.6% of Mfg. Cost $47 ,984 ,000 $10,429,000 $ 66,612,000 $125 025,000 ($12,032,000) $112,993,000 102,395,000 $215, 388,000 $0.184/1b $074294b>——_ opr nw — 10. Fit 12. 13. 14. 5s PROCESS WORKSHEET - ALASKAN INLAND LOCATION Process___Low Density Polyethylene Capacity 400 mm 1b/yr 3. Capital Investment $230 mm Feedstock Requirements _416 mm 1b/yr ethylene Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals $244,000 Total : C. Utility Requirements Fuel @ $2/10° Btu $ 2,120,000 Electrical Power @ $0.025/kWh $ 7,000,000 Cooling Water Makeup @ $1.20/Mgal $ 456,000 Boiler Feed Water @ $2/Mgal $ 184,000 Waste Water Treatment @ $1.90/Mgal $91,000 Cooling Water Circulation @ $0.07/Mgal _$ 756,000 Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 85 @ $28,000/yr. $ 2,380,000 (includes benefits) Supervision, @ 20% of Operating Labor $476,000 Maintenance, @ 4% of Capital Plant $ 7,960,000 General Administrative and Overhead @ 100% of Labor $ 2,380,000 Taxes and Insurance, @ 2% of Capital Plant $ 3,980,000 Depreciation, 10% S.L. $19,900,000 Total Total Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound Shipping Costs/Pound (Rail to coast, hydrotrain to Seattle, rail to Chicago) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound A-3 $ 244,000 $ 10,607,000 $ 47,927,000 $ 52,850,000 $10,777,000 __ $0.252 $0.054 $0. 306 $0.315 $0.009 orn — 10. il. Wo 3. 14, 15. PROCESS WORKSHEET - ALASKAN INLAND LOCATION Process_High Density Polyethylene Capacity__150 mm _1b/yr 3. Capital Investment — $88 mm Feedstock Requirements _157.5 mm 1b/yr ethylene Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals $662,000 Total C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh $ 443,000 Cooling Water Makeup @ $1.20/Mgal -- Boiler Feed Water @ $2/Mgal ne Waste Water Treatment @ $1.90/Mgal va Cooling Water Circulation @ $0.07/Mgal ca Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 30 @ $28,000/yr. $ 840,000 (includes benefits) Supervision, @ 20% of Operating Labor $ 168,000 Maintenance, @ 4% of Capital Plant $ 3,040,000 General Administrative and Overhead @ 100% of Labor $ 840,000 Taxes and Insurance, @ 2% of Capital Plant $1,520,000 Depreciation, 10% S.L. $ 7,600,000 Total Total Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound Shipping Costs/Pound (Rail to coast, hydrotrain to Seattle, rail to Chicago) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound A-4 $662,000 £443,000 $14,008,000 $15,113,000 0 $15,113,000 $20,200,000 $35,313,000 $0.235 $0.054 $0.289 $0.318 $0.029 arn — 10. im le. has 14, 15. PROCESS WORKSHEET - ALASKAN INLAND LOCATION Process Polypropylene Capacity__110 mm 1b/yr 3. Capital Investment $118 .nm Feedstock Requirements 126 mm 1b/yr propylene Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals $ 106,000 Total C. Utility Requirements Fuel @ $2/10° Btu $ 1,012,000 Electrical Power @ $0.025/kWh $ 523,000 Cooling Water Makeup @ $1.20/Mgal $ 153,000 Boiler Feed Water @ $2/Mgal $ 88,000 Waste Water Treatment @ $1.90/Mgal $ 21,000 Cooling Water Circulation ®@ $0.07/Mgal $ 254,000 Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 64 @ $28,000/yr. $ 1,792,000 (includes benefits) Supervision, @ 20% of Operating Labor $ 358,000 Maintenance, @ 4% of Capital Plant $ 4,280,000 General Administrative and Overhead @ 100% of Labor $ 1,792,000 Taxes and Insurance, @ 2% of Capital Plant $ 2,140,000 Depreciation, 10% S.L. $10,700,000 Total Total Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound Shipping Costs/Pound (Rail to Coast, hydrotrain to Seattle, rail to Chicago) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound A-5 Msi; $ 2,051,000 $71,062,090 $23,219,000 0 $23,219,000 $27,850,000 $51,069,000 $0.464 $0.054 $0.518 $0. 300 ($0.218) norFrn — 10. 1. 12. Tas 14. 55 PROCESS WORKSHEET - ALASKAN INLAND LOCATION Process__ Vinyl Chloride Monomer Capacity_192 mm _1b/yr 3. Capital Investment _ $48 nm Feedstock Requirements _91.6 mm 1b/yr ethylene, 119.2 mm 1b/yr chlorine Operating Costs: A. Feedstock Costs chlorine @ $200/ton dlud. $11,920,000 B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal Total D0. Labor, Maintenance, Overhead, etc.: Operating Labor, 32 @ $28,000/yr. (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Total Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound $ 1,200,000 535,000 $298,000 $ 75,000 $ 60,000 $ 434,000 $ 896,000 $ 179,000 $ 1,760,000 $ 896,000 $ 880,000 $ 4,400,000 Shipping Costs/Pound (Rail to coastal terminal, tanker to Gulf Coast, barge to Chicago/Omaha terminal) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound A-6 $11,920,000 $ 2,602,000 $ 2,017,900 $23,533,000 SEAS TUTTE $23,533,000 $11,400,000 $34,933,000 $0.182 $0.031 $0.213 $0.143 ($0.070) PROCESS WORKSHEET - ALASKAN INLAND LOCATION 1. Process Polyvinyl Chloride ! 2. Capacity_190 mm _1b/yr 3. Capital Investment $94 mm 4. Feedstock Requirements __192 mm 1b/yr Vinyl Chloride Monomer 5. Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals $828,000 Total $ 828,000 __ C. Utility Requirements Fuel @ $2/10° Btu $ 293,000 Electrical Power @ $0.025/kWh $ 333,000 Cooling Water Makeup @ $1.20/Mgal $ 66,000 Boiler Feed Water @ $2/Mgal $18,000 Waste Water Treatment @ $1.90/Mgal $ 22,000 Cooling Water Circulation @ $0.07/Mgal $ 96,000 Total $ 828,000 D. Labor, Maintenance, Overhead, etc.: Operating Labor, 78 @ $28,000/yr. $2,184,000 (includes benefits) Supervision, @ 20% of Operating Labor $ 437,000 Maintenance, @ 4% of Capital Plant $3,040,000 General Administrative and Overhead | @ 100% of Labor $2,184,000 Taxes and Insurance, @ 2% of Capital Plant $1,520,000 Depreciation, 10% S.L. $7,600,000 i Total $16,965,000 6. Total Annual Manufacturing Costs $18,621,000 Co-product/By-product Credits: Total 0 Net Manufacturing Cost $18,621,000 9. ROI. 25% Before Taxes on Fixed Invest- Ment plus 10% on Working Capital $20,800,000 10. Net Costs and ROI $39,421,000 11. Net Transfer Price/Pound $0.207 12. Shipping Costs/Pound (Rail to Coast, hydrotrain to Seattle, rail to Chicago) $0.054 13. Total Costs/Pound $0.261 14. Current Price/Pound $0. 390 15. Net Surplus Applied to Domestic Feedstocks/Pound $0.129 A-7 10. 1. 12. 13. 14. 15. orn — PROCESS WORKSHEET - ALASKAN INLAND LOCATION Process___ Styrene Monomer Capacity_400 mm 1b/yr Bie Capital Investment $149 mn Feedstock Requirements __ 125 mm 1b/yr ethylene, 326 mm 1b/yr benzene Operating Costs: A. Feedstock Costs-- Benzene @ $0.14/1b dlud. $45,640,000 B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 24 @ $28,000/yr. (includes benefits) or Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Total Annual Manufacturing Costs Co-product/By-product Credits: $800,000 $ 3,800,000 $300,000 $144,000 -$__152,000__ $ 76,000 $218,000 672,000 $134,000 4,640,000 $672,000 $ 2,320,000 $11,600,000 Al Chloride (25 wt%), 3.6 mm 1b/yr @ $0.03/1b § 108,000 Toluene (97 wt%), 20.8 mm 1b/yr @ $0.63/gal Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound $ 1,812,000 , Shipping Costs/Pound (Rail to coastal terminal, tanker to Gulf Coast, barge to Chicago/Omaha terminal) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound A-8 $ 4,690,000 $20,038,000 sovs $71,168,000 ($ 1,920,000) $69,248,000 $32,300,000 $101 ,548,000 $0.254 $0.031 _$0.285 $0.210 ($0.075) 10. i. 12. 13. 14, 18, PROCESS WORKSHEET - ALASKAN INLAND LOCATION Process Polystyrene : Capacity_200 mm _1b/yr 3. Capital Investment _ $70 mm Feedstock Requirements Operating Ccsts: A. Feedstock Costs B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ §2/10° Btu Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 100 @ $28,000/yr. (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Total Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound 206 mm _1b/yr styrene monomer $ 191,000 $ 500,000 $ 19,000 $4,000 $8,000 $1,000 $2,800,000 560,000 $2,280,000 $2,800,000 $1,140,000 00,00 Shipping Costs/Pound (Rail to Coast, hydrotrain to Sea Seattle, rail to Chicago) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound $ 64,000 > 723,000 0 16,067,000 15,550,000 $31,617,000 $0.158 $0.054 $0.212 $0.280 $0.068 orn 10. Ts 12. 13. 14. 15. PROCESS WORKSHEET - ALASKAN INLAND LOCATION Process Ethylene Glycol Capacity_ 300 mm _1b/yr Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu 3. Capital Investment _ $12? mm Feedstock Requirements _210 mm lb/yr ethylene, 277 mm lb/yr oxygen Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 72 @ $28,000/yr. (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Total Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound $ 239,000 $ 1,242,000 $ 75,000 $144,000 $ 30,000 $ 57,000 _$ _ 567,000 $ 2,016,000 $ 403,000 $ 4,160,000 $ 2,016,000 $ 2,080,000 $10,400,000 _ Shipping Costs/Pound (Rail to Coast, tanker to Gulf Coast, barge to Chicago/Omaha) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound A-10 —$ 239,000 $ 2,115,000 $21.075 000 $23,429,000 —__o $23,429 000 $27,800,000 $51,229,000 $0.171 $0.031 $0.202 $0.245 $0.043 orn — 10. VW. 12. 13. 14. 15. Process Propylene Glycol Capacity_130 mm _1b/yr Feedstock Requirements _95 mm 1b/yr propylene Operating Costs: PROCESS WORKSHEET - ALASKAN INLAND LOCATION Feedstock Costs Catalysts and Chemicals Total Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal Total Labor, Maintenance, Overhead, etc.: Operating Labor, 48 @ $28,000/yr. (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total A-11 3. Capital Investment _ $62 mm (Inc, On plant) $ 94,000 $538,000 $ 32,000 $ 62,000 $ 13,000. $ 25,000 $ 91,000 3 761,000 $ 1,344,000 $269,000 $ 2,200,000 $ 1,344,000 $ 1,100,000 $ 5,500,000 $11,757,000 Total Annual Manufacturing Costs $12,612,000 Co-product/By-product Credits: Total 0 Net Manufacturing Cost $12,612,000 ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital $14,450,000 Net Costs and ROI $27 .062,000 Net Transfer Price/Pound $0.208 Shipping Costs/Pound (Rail to coast, tanker to Gulf Coast, barge to Chicago/Omaha) $0.031 Total Costs/Pound $0.239 Current Price/Pound $0,250 Net Surplus Applied to Domestic Feedstocks/Pound PE OY 1] 10. Wh 12. 13. 14. 1b. arn — PROCESS WORKSHEET - ALASKAN INLAND LOCATION Process__ Acrylonitrile Capacity_100 mm _1b/yr 3. Capital Investment _ $97 mm Feedstock Requirements _117,5 mm 1b/yr propylene. 47.5 mm 1b/yr ammonia Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 36 @ $28,000/yr. (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Total Annual Manufacturing Costs Co-product/By-product Credits: Hydrogen Cyanide, 13 mm 1b/yr @ $Q.20/1b Acetonitrile, 3 mm 1b/yr @ $0.30/1b Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound 319,000 $ 450,000 $ 454,000 $ 288,000 $27,000 $ 60,000 $420,000 _ 1,008 ,000 $ 202,000 $3,240,000 1,008,000 $1,620,000 $8,100,000 $2,600,000 900,000 i Shipping Costs/Pound (Rail to coast, tanker to Gulf Coast, barge to Chicago or rail to Southeast) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound A-12 $ 319,000 $15,178.000 $17,196,000 3,500,000 $13,696,000 21,850,000 35,546,000 $0.355 $0.031 oer = 10. ie 12. 13. 14, 152 PROCESS WORKSHEET - ALASKAN INLAND LOCATION Process Ammonia Capacity__ 876 mm ]b/yr Operating Costs: A. Feedstcck Costs B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh Se Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Capital Investment _ $159 mm Feedstock Requirements _ 14,279 mm SCF/yr natural gas (feedstock and fuel) $419,000 __ Inc. in feedstock $164,000 $158,000 $ 420,000 $133,000 Cooling Water Circulation @ $0.07/Mgal $2,208,000 Total D. Labor, Maintenance, Overhead, e Operating Labor, 60 % $28,000/yr. (includes benefits) UGiars $1,680,000 _ Supervision, @ 20% of Operating Labor $336,000 Maintenance, @ 4% of Capital Plant $4,960,000 General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Totai Total Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound $1,680,000 $2,480,000 $12,400,000 Shipping Costs/Pound (Rail to coast, barge to West Coast) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound A-13 $419,000 $ 3,083,000 $23,525,600 27,038,000 ee $27,038 000 32,500,000 $59,538,000 —$0,068 $0.015 $0.083 $0.065 ($0.018) 10. UUs 12. 13. 14, 15. PROCESS WORKSHEET - ALASKAN Process Urea Capacity_1095 mm 1b/yr 3 Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/ Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 4g @ $28,000/yr. (includes benefits) Supervision, @ 20% of Operating La Maintenance, @ 4% of Capital Plant General Administrative and Overhea @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Total Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound Shipping Costs/Pound (Rail to Coast, shi barge to Chicago/0 Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound A-14 INLAND LOCATION Capital Investment _ $77 mm Feedstock Requirements _635 mm _1b/yr ammonia, 832 mm 1b/yr carbon dioxide $4,812,000 $1,738,000 $ 578,000 $22,000 $ 188,000 Mgal $ 958,000 $1,344,000 bor $269,000 d p to Gulf Coast, maha ) a 21,172,000 $16,850,000 22,00 $0.035 $0.022 $0.057 $0.065 $0 .008 orn — 10. 1. 12. 13. 14. 15. PROCESS WORKSHEET - ALASKAN INLAND LOCATION Process Ammonium Nitrate (Including Nitric Acid Pla Capacity_ 527.8 mm 1b/yr 3. Capital Investment _$36 mm Feedstock Requirements _241 mm _1b/yr ammonia Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals $ 398,000 Total C. Utility Requirements Fuel @ $2/10° Btu $1,344,000 Electrical Power @ $0.025/kWh $3,887,000 Cooling Water Makeup @ $1.20/Mgal $ 239,000 Boiler Feed Water @ $2/Mgal $349,000 Waste Water Treatment @ $1.90/Mgal $17,000 Cooling Water Circulation @ $0.07/Mgal $400,000 Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 12 @ $28,000/yr. $336,000 (includes benefits) Supervision, @ 20% of Operating Labor $ 67,000 Maintenance, @ 4% of Capital Plant $1,120,000 General Administrative and Overhead i @ 100% of Labor $336,000 Taxes and Insurance, @ 2% of Capital Plant $560,000 Depreciation, 10% S.L. $2,800,000 Total Total Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound Shipping Costs/Pound (Rail to Coast, hydrotrain to Seattle, rail to Omaha) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound A-15 $ 6,236,000 $5,219,000 $11,853,000 _ _ aS URE $11,853,000 $ 7,800,000___ $19,653,000 $0.037 $0.041 $0.078 $0.055 ($0.023) orn — 10. 1. 12. 13. 14. 15. PROCESS WORKSHEET - ALASKAN INLAND LOCATION Process Methanol Capacity_730_mm_1b/yr Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh Total 3. Capital Investment _ $92 mm Feedstock Requirements _9866 mm SCF/yr Natural Gas Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 40 (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant @ $28,000/yr. Depreciation, 10% S.L. Total Total Annual Manufacturing Costs Co-product/By-product Credits: Net Manufacturing Cost Total ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound $ 310,000 3,752,000 —$__44,000 _ —$_771,000 —$ 217,000 _ 374 000 $1,124,000 $1,120,000 —$_224,000 $3,120,000 $1,120,000 $1,560,000 $7,800,000 Shipping Costs/Pound (Rail to coast, tanker to West Coast) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound A-16 $ 6,282,000 pe eee $21,536,000 $21,000,000 _ $42,536,000 $0.058 $0.018 $0.076 —#0.050 nPFPn=— c 10. 1. 12. 13. 14, 15. PROCESS WORKSHEET - ALASKAN INLAND LOCATION Process__ Formaldehyde, 37 wt% Solution Capacity__400 mm 1b/yr Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh as Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Capital Investment $16 mm Feedstock Requirements 172.4 mm 1b/yr Methanol $204,000 $ 460,000 $70,000 $110,000 $86,000 _ 68,000 Cooling Water Circulation @ $0.07/Mgal $182,000 Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 16 8% $28,000/yr. (includes benefits) $ 448,000 Supervision, @ 20% of Operating Labor $90,000 Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Total Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound Shipping Costs/Pound (Rail to Coast, Tanker to Seattle/Portland) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound A-17 $ 440,000 $ 448,000 $ 220,000 $1,100,000 $204,000 $976,000 $2,746,000 $3,926,000 —__o $3,926,000 $3,250,000 __ $7,176,000 $0.018 $0.017 $0.035 $0.053 $0.018 APPENDIX B PROCESS WORKSHEETS - U.S. GULF COAST PROCESS WORKSHEET - U.S. GULF COAST 1. Process Olefin Plant - Based on Kawait Naphtha - high crackina severity 2. Capacity ee a wie euhytene 3. Capital Investment $298 nm 4. Feedstock Requirements _12,346,000 bbl/yr Kawait Naptha 5. Operating Costs: A. Feedstock Costs Naphtha B. Catalysts and Chemicals 600,000 Total 600,000 C. Utility Requirements (11,267 109 6 > x Btu provided Fuel @ $2/10° Btu 3,466,000 Op’ cracking residue gases) Electrical Power @ $0.025/kWh 350,000 Cooling Water Makeup @ $1.20/Mgal 1,704,000 Boiler Feed Water @ $2/Mgal 100,000 Waste Water Treatment @ $1.90/Mgal 600,000 Cooling Water Circulation @ $0.07/Mgal 2,450,000 Total 8.670.000 D. Labor, Maintenance, Overhead, etc.: / Operating Labor, 80 @ $24,000/yr. 1,920,000 (includes benefits) Supervision, @ 20% of Operating Labor 384,000 Maintenance, @ 4% of Capital Plant 10,640,000 General Administrative and Overhead @ 100% of Labor 1,920,000 Taxes and Insurance, 8 2% of Capital Plant 5,320,000 Depreciation, 10% S.L. 26,600,009 Total 46,784 ,000 6. Total Annual Manufacturing Costs 56,054,000 Co-product/By-product Credits: Batadiene, 141,700,000 1b/yr @ $0.18/1b 25,506,000 C4 mixture, 106,700,000 1b/yr @ $0.10/1b 10,670,009 —_ Pyrolysis gasoline, 740,900,000 1b/yr @ $18/bb1] 54,325,000 Hydrogen, 5,100,000 1b/yr @ SZ.00/108 Btu 600,000 . Aromatic fuel oi1, 195,400,000 Ihr @ $1.90/108, 6,349,000 (97,450,000) Net Manufacturing Cost (41,396,000) 9. ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital 69,700,000 10. Net Cc ROI 28,304 ,000 : ee este-ein . pEthylene C_/72-0f manuf cose ———- 22 11. Net Transfer Price/Pound ‘propylene @ 23% of manuf. cost‘?)4 $ 0.015 12. Shipping Costs/Pound FOB Plant Ethylene 0.022 13. Total Costs/Pound Propylene 0.015 Ethylene 0.120 14. Current Price/Pound Propylene ——#-695————_ 15. Net Surplus Applied to Domestic Ethylene 0.010 Feedstocks/Pound Propylene 0.080 (a) Assumes product pricing ratio: Ethylene = Propylene 0.7 arn — 10. i. 12. 13. 14. is PROCESS WORKSHEET - U.S. GULF COAST Process Low Density Polyethylene Capacity__ 400 mm 1b/yr 3. Capital Investment _ $115 mm Feedstock Requirements 416 mm_1b/yr ethylene Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, g5 @ $24,000/yr. (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Total Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound Shipping Costs/Pound (Rai] to Chicago) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound 230,000 2,120,000 7,000,000 456,000 184,000 91,000 756,000 —2,040,000 408 ,000 —3.980,900 2,040,000 1,990,000 9,950,000 230,000 10,607 ,000 a IN) 3/0 ro |S o a |e DIS So So wv > 3 —_o 31,245,000 26,425,000 57,670,000 $0144 $ 0.033 orn — 10. We 12 13. 14, 15. PROCESS WORKSHEET - U.S. GULF COAST Process High Density Polyethylene Capacity 150 mm 1b/yr 3. Feedstock Requirements 157.5 mm 1b/yr ethylene Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals C. Utility Requirements Fuel @ $2/10° atu Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal D. Labor, Maintenance, Overhead, etc.: Operating Labor, 30 @ $24,000/yr. (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Tota? Annual Manufac + Co-product/By-product Credits: Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound Shipping Costs/Pound (Rail to Chicago) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Capital Investment $44 mm pe h23-000= Total 623,000 443,000 Total 443,000 720,000 144,000 1,520,000 720,000 760,000 3,800,000 Total 7,664,000 uring Costs &,729.000 Total 0 8,730,000 —10.100.000_ _ 18,830,000 0.126 0.033 $ 0.159 $ 0.318 0.159 Feedstocks/Pound orn — 10. VW. 12. Bay 14. 15. PROCESS WORKSHEET - U.S. GULF COAST Process Polypropylene Capacity__110 mm 1b/yr 3. Capital Investment Feedstock Requirements _ 126 mm _1b/yr propylene Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 64 @ $24,000/yr. (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Total Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound Shipping Costs/Pound (Rail to Chicago) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound B-4 100,000 1,012,090 523,000 153,000 pela ttee a lM ane 21,000 254,000 1,536,000 ___ 307,900 _ 2,140,000 1,536,000 1,070,090 _5,350,000 $59 mm 14,090,000 14,090,000 100,000 2,051,000 11,939,000 0 13,925,000 __ 28,015,000 _ $ $ $ 0.255 0.033 0.288 0.300 0.012 arn — 10. i. T2. 13. 14, 15. PROCESS WORKSHEET - U.S. GULF COAST Process Vinyl Chloride Monomer Capacity 192 mm Ib/yr 3. Capital Investment _ $24 mm Feedstock Requirements 91.6 mm _1b/yr ethylene, 119.2 mm 1b/yr chlorine Operating Costs: A. Feedstock Costs Chlorine @ $150/ton 8,940,000 B. Catalysts and Chemicals Total 8,940,000 C. Utility Requirements Fuel @ $2/10° Btu 1,200,000 Electrical Power @ $0.025/kWh 535,000 Cooling Water Makeup @ $1.20/Mgal 298,000 Boiler Feed Water @ $2/Mgal 75,000 Waste Water Treatment @ $1.90/Mgal 60,000 Cooling Water Circulation @ $0.07/Mgal 434,000 Total 2.602.000 D. Labor, Maintenance, Overhead, etc.: Operating Labor, 32 @ $24,000/yr. 768,000 (includes benefits) Supervision, @ 20% of Operating Labor 154,000 Maintenance, @ 4% of Capital Plant 880 ,000 General Administrative and Overhead ! @ 100% of Labor 768,000 Taxes and Insurance, @ 2% of Capital Plant 440,000 Depreciation, 10% S.L. 2,200,000 . Total i 5,210,000 Totai 4nnual Manufacturing Costs 16,752,090 Co-product/By-product Credits: Total ‘ 0 Net Manufacturing Cost __ 16,752,000 ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital 5,700,000 Net Costs and ROI 22,452 900 Net Transfer Price/Pound $ 0.117 ut Shipping Costs/Pound (Barge to Chicago/Omaha Terminal) $ 0.007 Total Costs/Pound $ 0.124 Current Price/Pound 0.143 Net Surplus Applied to Domestic Feedstocks/Pound 0.019 orn — ~ 10. i. 12. 13. 14. 15s PROCESS WORKSHEET - U.S. GULF COAST Process Poly Vinyl Chloride Capacity___190 mm _1b/yr 3. Capital Investment $47_mm Feedstock Requirements _ 192 mm _1b/yr vinyl chloride monomer Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 78 @ $24,000/yr. (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Total Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound Shipping Costs/Pound (Rail to Chicago) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound B-6 779 ,000 293,000 333,000 66,000 18,000 22,000 96 ,000 1,872,000 374 000 —1.520,000 __ 1,872,000 760,000 * 3,800,000 779,000 828,000 10,198,000 11,805 ,000 0 11,805,000 10,400,000 ~ 22,205,000 $ 0.117 $ 0.033 $ 0.150 0.390 0.240 orn = 10. 1. 12. 13. 14. 1S. PROCESS WORKSHEET - U.S. GULF COAST Process Styrene Monomer Capacity_ 400 mm_1b/yr oe $74 mm Feedstock Requirements 125 mm lb/yr ethylene, 326 mm 1b/yr benzene Capital Investment Operating Costs: A. Feedstock Costs Benzene @ $0.086/1b 28,036,000 B. Catalysts and Chemicals 700,000 Total 28,736,000 C. Utility Requirements Fuel @ $2/10° Btu 3,800,000 Electrical Power @ $0.025/kWh 300,000 Cooling Water Makeup @ $1.20/Mgal 144,000 Boiler Feed Water @ $2/Mgal 152,000 Waste Water Treatment @ $1.90/Mgal 76,000 Cooling Water Circulation @ $0.07/Mgal 218,000 Total 4,690,000 D. Labor, Maintenance, Overhead, etc.: Operating Labor, 24 @ $24,000/yr. 576.000 (includes benefits) Supervision, @ 20% of Operating Labor 115,000 Maintenance, @ 4% of Capital Plant 2,320,000 cee eee and Overhead 576,000 Taxes and Insurance, @ 2% of Capital Plant 1,160,000 Depreciation, 10% S.L. 5,800,000 Total 10,547,000 Total Annual Manufa turing Costs 43,973,000 Co-product/By-product Credits: Al Chloride (25 wt%), 3.6 mm 1b/yr @ $0.04/1b 144 ,000 Toluene (97 wt%), 20.8 mm 1b/yr @ $0.63/gal 1,812,000 Total (1,956,000) Net Manufacturing Cost 42,017,000 ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital 16,100,000 Net Costs and ROI 58,117,000 Net Transfer Price/Pound $ 0.145 Shipping Costs/Pound (Barge to Chicago/Omaha Terminal) $ 0.007 Total Costs/Pound $ 0.152 Current Price/Pound 0.210 Net Surplus Applied to Domestic Feedstocks/Pound 0.058 B-7 orn — 10. i. vee 13. 14. a PROCESS WORKSHEET - U.S. GULF COAST Process Polystyrene Capacity 200 mm 1b/yr 3. Capital Investment $35 mm Feedstock Requirements _ 206 mm 1b/yr styrene monomer Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals Total C. Utility Requirements > Fuel @ $2/10® Btu Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 100 @ $24,000/yr. (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Tota! Aunual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound Shipping Costs/Pound (Rail to Chicago) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound B-8 60,000 191,000 500,000 19,000 icc Mancini 8,000 1,000 2,400,000 480,000 1,140,000 2,400,000 570,000 2,850,000 60,000 723,000 9,840,000 0 10,623,000 7,775,000 18,398,000 $ 0.092 $_ 0.033 0.280 0.155 arn — 10. i. 12. 135 14, 1. PROCESS WORKSHEET - U.S. GULF COAST Process Ethylene Glycol Capacity___300 mm _1b/yr 3. Capital Investment $61_mm Feedstock Requirements _210 mm _1b/yr ethylene, 277 mm 1b/yr oxygen Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 72 @ $24,000/yr. (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Totai Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound 225,000 1,242,000 75,000 144,000 30,000 57,000 567,000 1,728,000 346,000 2,090,000 1,728,000 1,040,000 5,200,000 Shipping Costs/Pound (Barbe to Chicago/Omaha Terminal) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound B-9 225,000 2,115,000 12,122,000 14 5462 ,UU0 IIE 14,462,000 13,900,000 28,362,000 $ 0.095 0.006 $0.10] Oe eee 0.144 orn 6. 7. 10. nN. 12. 13. 14. 15. PROCESS WORKSHEET - U.S. GULF COAST Process Propylene Glycol Capacity__130 mm 1b/yr Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh 35 Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 48 @ $24,000/yr. (includes benefits) hase act aan elcinerrenneneminennens Capital Investment #31 mm Feedstock Requirements 95 mm 1b/yr propylene 88,000 538,000 32,000 62,000 13,000 25,000 91,000 1,152,000 Supervision, @ 20% of Operating Labor 230,000 Maintenance, @ 4% of Capital Plant 1,100,000 General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Total Annuai Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound 1,152,000 550,000 2,750,000 Shipping Costs/Pound (Barge to Chicago/Omaha Terminal) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound B-10 761,000 6,934,000 7,782,000 0 —1,183,000_ _ 7,225,000 —15.008.000 _ S01 $_ 0.006 $_ 0.121 0.250 0.129 10. i. 12. i 14, 15. PROCESS WORKSHEET - U.S. GULF COAST Process Acrylonitrile Capacity 100 mm_1b/yr 3. Capital Investment $48.5 mm Feedstock Requirements _117.5 mm lb/yr propylene, 47.5 mm 1b/yr ammonia Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals 300,000 Total 300,000 C. Utility Requirements Fuel @ $2/10° Btu 450,000 Electrical Power @ $0.025/kWh 454,000 Cooling Water Makeup @ $1.20/Mgal 288 ,000 Boiler Feed Water @ $2/Mgal 27,000 Waste Water Treatment @ $1.90/Mgal 60,000 Cooling Water Circulation @ $0.07/Mgal 420,000 Total 1,699,000 D. Labor, Maintenance, Overhead, etc.: Operating Labor, 36 @ $24,000/yr. 864 ,000 (includes benefits) Supervision, @ 20% of Operating Labor 173,000 Maintenance, @ 4% of Capital Plant 1.620.000 Seed of Lae and Overhead 864,000 Taxes and Insurance, @ 2% of Capital Plant 810,000 Depreciation, 10% S.L. 4,050,000 Total 8,381,000" Total Annual Manufacturing Costs 10,380,000 Co-product/By-product Credits: Hydrogen Cyanide, 13 mm 1b/yr @ $0.33/1b 4,290,000 Acetonitrile, 3 mm 1b/yr @ $0.40/1b 1,200,000 Total | . (5,490,000) Net Manufacturing Cost 4,890,000 ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital 10,925,000 Net Costs and ROI 15,815,000 Net Transfer Price/Pound $ 0.158 Shipping Costs/Pound (Barge to Chicago or Southeast Terminal) 0.007 Total Costs/Pound $ 0.165 Current Price/Pound 0.275 Net Surplus Applied to Domestic Feedstocks/Pound 0.110 B-11 PROCESS WORKSHEET - U.S. GULF COAST 1. Process Ammonia (Naphtha Feedstock) 2. Capacity__ 876 mm _1b/yr 3. Capital Investment $92 mm 4. Feedstock Requirements 2,786,519 bbl/yr Naphtha Feed & Fuel 705,546,610 1b 5. Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals 606 ,000 Total 606 ,000 C. Utility Requirements Fuel @ $2/10° Btu Included in feedstock Electrical Power @ $0.025/kWh 291,000 Cooling Water Makeup @ $1.20/Mgal 631,000 Boiler Feed Water @ $2/Mgal 1,577,000 Waste Water Treatment @ $1.90/Mgal 266,000 Cooling Water Circulation @ $0.07/Mgal 3,312,000 Total 6.077.000 D. Labor, Maintenance, Overhead, etc.: Operating Labor, 45 $24,000/yr. 1,080,000 (includes benefits) Supervision, @ 20% of Operating Labor 216,000 Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant 1,480,000 Depreciation, 10% S.L. 7,400,000 Total . 14,216,000 6. Total Annual Manufacturing Costs 20,899 ,000 7. Co-product/By-product Credits: —2,960,000__ —1,080,000__ Total 0 8. Net Manufacturing Cost 20,899,000 9. ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital 20,300,000 10. Net Costs and ROI 41,199,000 11. Net Transfer Price/Pound $ 0.047 12. Shipping Costs/Pound (Barge to Chicago/Omaha Terminal) $ 0.007 13. Total Costs/Pound 0.054 14. Current Price/Pound 0.065 15. Net Surplus Applied to Domestic Feedstocks/Pound 0.011 B-12 arn — NO 10. Hi. 12. 13. 14. 15. PROCESS WORKSHEET - U.S. GULF COAST Process__Urea Capacity 1095 mm Ib/yr 3. Capital Investment Feedstock Requirements _635 mm 1b/yr Ammonia, 832 mm 1b/yr Carbon Dioxide Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 4g @ $24,000/yr. (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Total Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound 150,000 4,812,000 1,738,000 578,000 22,000 188 ,000 958,000 230,000 1,152,000 610,000 Shipping Costs/Pound (Barge to Chicago/Omaha Terminal) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound B-13 $38.5 mm 150,000 8,296,000 1,152,000 1,220,000 3,050,000 7,414,000 15,860,000 0 15,860,000 8,425,000 24,285,000 $ 0.022 0.006 $ 0.028 0.065 0.037 10. i. 12. 13. 14, 15. PROCESS WORKSHEET - U.S. GULF COAST Process Ammoniam Nitrate (including nitric acid plant) Capacity___ 527.8 mm _1b/yr 3. Capital Investment _ $18 mm Feedstock Requirements 241 mm_1b/yr Ammonia Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals 375,000 Total C. Utility Requirements Fuel @ $2/10° stu 1,344,000 Electrical Power @ $0.025/kWh 3,887 ,000 Cooling Water Makeup @ $1.20/Mgal 239,000 Boiler Feed Water @ $2/Mgal 349 ,000 Waste Water Treatment @ $1.90/Mgal 17,000 Cooling Water Circulation @ $0.07/Mgal 400 ,000 Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 12 @ $24,000/yr. 288 .000 (includes benefits) Supervision, @ 20% of Operating Labor 58,000 Maintenance, @ 4% of Capital Plant 560,000 General Administrative and Overhead @ 100% of Labor 288,000 Taxes and Insurance, @ 2% of Capital Plant 280,000 Depreciation, 10% S.L. 1,400,000 Total Total Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound Shipping Costs/Pound (Barge to Chicago/Omaha Terminal) Total Costs/Pound Current Price/Pound Net Surplus Applied to Domestic Feedstocks/Pound B-14 375,000 2,874 000 9.485 ,000 0 9,485 ,000 —3,900,000 __ 13,385,000 __ $ 0.025 0.006 $ 0.031 0.055 024 arn — oO, 10. 1h, 12. 13. 14. 15. PROCESS WORKSHEET - U.S. GULF COAST Process Methanol Capacity Feedstock Requirements 730 mm 1b/yr oy Capital Investment 1,425,603 bbl/yr Naphtha $112 mm 360,962,680 1b Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals Total C. Utility Requirements Fuel @ $2/10° Btu Electrical Power @ $0.025/kWh Cooling Water Makeup @ $1.20/Mgal Boiler Feed Water @ $2/Mgal Waste Water Treatment @ $1.90/Mgal Cooling Water Circulation @ $0.07/Mgal Total D. Labor, Maintenance, Overhead, etc.: Operating Labor, 45 @ $24,000/yr. (includes benefits) Supervision, @ 20% of Operating Labor Maintenance, @ 4% of Capital Plant General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant Depreciation, 10% S.L. Total Totai Annual Manufacturing Costs Co-product/By-product Credits: Total Net Manufacturing Cost ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital Net Costs and ROI Net Transfer Price/Pound 560,000 9,188,000 75,000 ee) 0002S ae 000neES ——374,000 _ —14124,000" 1,080,000 216,000 3,760,000 1,080,000 1,880,000 9,400,000 Shipping Costs/Pound (Tanker to West Coast Terminal) Total Costs/Pound Current Price/Pound FOB Gulf Coast Net Surplus Applied to Domestic Feedstocks/Pound B-15 560,000 17,416,000 29,725,000 0 29,725,000 25,300,000 55,025,000 ps0. 075s sain FOB Gulf Coast $ 0.075 0.067 (0.008) arn — cn 10. He 1s 13. 14, 15. PROCESS WORKSHEET - U.S. GULF COAST Process Formaldehyde 37 wt% Solution Capacity 400 mm _1b/yr 3. Capital Investment _ $8 mm Feedstock Requirements 172.4 mm_1b/yr Methanol Operating Costs: A. Feedstock Costs B. Catalysts and Chemicals 192,000 Total 192,000 C. Utility Requirements Fuel @ $2/10° Btu 460,000 Electrical Power @ $0.025/kWh 70,000 Cooling Water Makeup @ $1.20/Mgal 110,000 Boiler Feed Water @ $2/Mgal 86,000 Waste Water Treatment @ $1.90/Mgal 68,000 Cooling Water Circulation @ $0.07/Mgal 182,000 Total 976,000 D. Labor, Maintenance, Overhead, etc.: Operating Labor, 16 @ $24,000/yr. 384,000 (includes benefits Supervision, @ 20% of Operating Labor 77.000 Maintenance, @ 4% of Capital Plant 220.000 General Administrative and Overhead @ 100% of Labor Taxes and Insurance, @ 2% of Capital Plant 110,600 Depreciation, 10% S.L. 550,000 Total 1,725,000 Totai Annual Manufacturing Costs 2,855,000 Co-product/By-product Credits: 384,000 Total o Net Manufacturing Cost 2,893,000 ROI. 25% Before Taxes on Fixed Invest- ment plus 10% on Working Capital 1,625,000 Net Costs and ROI 4,518,000 Net Transfer Price/Pound $ 0.011 Shipping Costs/Pound (Tanker to West Coast Terminal) $ 0.006 Total Costs/Pound $ 0.017 Current Price/Pound 0.053 Net Surplus Applied to Domestic Feedstocks/Pound 0.036 B-16