Industrial Energy Use

June 1983

NTIS order #PB83-240606
Library of Congress Catalog Card Number 83-600547

For sale by the Superintendent of Documents,

U.S. Government Printing Office, Washington, D.C. 20402
Foreword

This report responds to a request by the Senate Committee on Finance and the

House Committee on Energy and Commerce for an analysis of the prospects for energy

efficiency in the U.S. industrial sector, the technologies available to improve industrial

energy efficiency, and the effect of various legislative policies on stimulating increased

efficiency. This report complements several recent OTA reports on energy efficiency:

Residential Energy Conservation, Energy Efficiency of Buildings in Cities, and Industrial

and Commercial Cogeneration.

OTA examined energy use in the industrial sector in general and in the largest

energy-using industries—pulp and paper, petroleum refining, chemicals, and steel—in

detail. The report identifies the major technical opportunities available to each industry

to improve energy efficiency, the barriers to implementation of such technologies, and

the factors that guide corporate decisions about energy efficiency-improving investments.

The policy options chosen for assessment were the effects of: 1 ) the accelerated cost

recovery system of the 1981 Economic Recovery Tax Act, 2) investment tax credits

for energy-conserving capital expenditures, 3) a tax on petroleum and natural gas, and

4) increased capital availability through lower interest rates.

In the course of this assessment, OTA drew on the experience of many organizations and individuals. In particular, we appreciate the generous assistance of our

distinguished advisory panel and workshop participants, as well as the efforts of the

project’s consultants and contractors. We would also like to acknowledge the help

of the numerous reviewers who gave their time to ensure the accuracy and comprehensiveness of this report. To all of the above goes the gratitude of OTA, and the personal

thanks of the project staff.

JOHN H. GIBBONS

Director

. . . ill
Industrial Energy Use Advisory Panel

E. Milton Bevington

Servidyne, Inc.

Harold Bogart

Independent Consultant

Carleton Burtt

Equitable Life Assurance of the U.S.

William Chandler

Environmental Policy Institute

William Cunningham

AFL-CIO

Herbert Fusfeld, Chairman

New York University

Gordon Geiger* Rudolph Penner

Inland Steel Co. American Enterprise Institute

J. M. Leathers R. B. Pool

Dow Chemical Co. Kaiser Aluminum & Chemicals Corp.

Harvey Morris Rosalie Wolf

Harvey Morris Associates International Paper Co.

John Myers

Southern Illinois University

Henry Page, Jr.

Sun Refining & Marketing Co.

● Now at North Star Steel

Workshop on the Pulp and Paper Industry

William Adams George Hatsopoulos Alfred Nissan Edmond Perreault

Accuray Corp. Thermo Electron Corp. Westvaco (retired) Champion International Co.

Howard Harding Richard Ludwig George Boyd Ill Ronald Slinn

Thermo Electron Corp. Hammermill Paper Co. Kidder Peabody & Co. American Paper Institute

Workshop on the Petroleum Refining Industry

Van Boyette

National Petroleum

Association

Sherwood Breaux

Cities Service Co.

R. L. Jones A. L. Modiano

Refining American Petroleum Institute American Petroleum Institute

David Michael David Story

Mobil Oil Corp. Gulf Research & Development Co.

Workshop on the Chemicals Industry

A. C. Benjamin Byron Brown, Jr.

E. 1. du Pent de Nemours & Co., Inc. E. 1. du Pent de Nemours & Co., Inc.

James Borden L. M. Magner

E. I. du Pent de Nemours & Co., Inc. E. 1. du Pent de Nemours & Co., Inc.

Workshop on the Steel Industry

Donald Barnett* James Hamilton

American Iron and Steel Institute U.S. Steel Corp.

Frederick Corban Gerald Houck

Inland Steel Co. American Iron and Steel Institute

Robert Crandall Jack Kiefer

Brookings Institution Cameron Iron Works, Inc.

George Ferris Joseph Kotelchuck

Independent Consultant United Steelworkers of America

James Gay Roy Leidner

North Star Steel Bethlehem Steel

*Now at World Bank.

* *Now at Congressional Budget Office.

iv

Daniel Steinmeyer

Monsanto Co.

Robert Yates

Uniroyal Chemical

Gary Myers

Armco Steel

Louis Schorsch* *

American Iron and Steel Institute

Joseph Wyman

Shearson/American Express
OTA Industrial Energy Use Project Staff

Lionel S. Johns, Assistant Director, OTA

Energy, Materials, and International Security Division

Richard E. Rowberg, Energy and Materials Program Manager

James F. Ryan, Project Director

Eric Bazques Alan Crane AlIan Hoffman*

Joanne Seder Thomas Sheahen** Richard Thoreson

Administrative Staff

Virginia Chick Lillian Quigg Edna Saunders

Other Contributors

Bernard Gelb, Congressional Research Service: general industrial sector analysis

Robert Howell, Independent consultant: petroleum refining industry

Harvey Morris, Harvey Morris & Associates: generic technologies and pulp and paper industry

George St. Pierre, Ohio State University: steel industry

Kathryn White, Independent consultant: editor

Contractors and Consultants

Roy F. Weston, Inc., Philadelphia, Pa.

The Pace Co. Consultants & Engineers, Inc., Houston, Tex.

Energy and Environmental Analysis, Arlington, Va.

Technology & Economics, Cambridge, Mass.

Steven Carhart Associates, Washington, D.C.

Barry Richmond, Dartmouth College, Hanover, N. H.

Christian Kampmann, Dartmouth College, Hanover, N. H.

Marc Ross, University of Michigan, Ann Arbor, Mich.

Energy Productivity Center, Mellon Institute, Arlington, Va.

OTA Publishing Staff

John C. Holmes, Publishing Officer

John Bergling Kathie S. Boss Debra M. Datcher

Joe Henson Linda Leahy Donna Young

* Now at the National Academy of Sciences, Washington, D.C

* * Now at Stanford Research Institute, Washington, D.C.
Contents

Chapter Page

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix

1, Summary and Findings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2.The Industrial Sector: Growth, Trends, and Investment Behavior . . . . . . . . .

3. Industrial Energy: Uses, Technologies, and Policies . . . . . . . . . . . . . . . . . . . .

4.The Pulp and Paper Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

5.The Petroleum Refining Industry. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

6.The Chemicals Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

7.The Steel Industry. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Appendix A: The Industrial Sector Technology Use Model . . . . . . . . . . . . . . . . .

3

21

37

65

85

115

139

165

vii
Overview

For many years to come, energy need not be a constraint to economic growth

in the United States. OTA projects that in the next two decades investments in new

processes, changes in product mix, and technological innovation can lead to improved

industrial productivity and energy efficiency. As a result, the rate of industrial production can grow three times faster than the rate of energy use needed for that production.

Because the investments needed to improve energy efficiency are long term, a

reduction in energy use growth rates resulting from investments begun now will continue through the 1980’s and 1990’s. Furthermore, this improvement will continue

beyond 2000 as the proportion of new, energy-efficient capital stock increases. lmprovements in energy efficiency for the next several years will be largely a result of

housekeeping measures and investments that began during the 1970’s.

In 1981, the industrial sector used 23 Quads* of direct fuel, electricity,** and fossil

fuel feedstock, of which petroleum and natural gas constituted 73 percent. Four industries–paper, petroleum refining, chemicals, and steel–accounted for almost half

of all industrial energy used. Over the past decade, soaring energy prices have led to

significant changes in the absolute amount and mix of energy used in industry. Energy

used per unit of product in the industrial sector decreased by almost 20 percent. This

improvement was accomplished by housekeeping measures, equipment retrofits, and

new process technologies that produce existing products and new product lines.

In addition to reducing the energy use growth rate, industry will continue its

shift away from premium fuel use. For the next two decades, industrial coal use—particularly in boilers and in some large, direct heat units—will increase substantially because

coal is cheaper than oil and natural gas. Moreover, the demand for purchased electricity will probably grow faster than the total industrial energy demand if the price

difference between natural gas and electricity continues to decrease.

While industry has made significant strides in reducing energy use, opportunities

for further gains in energy efficiency from technical innovation are substantial. Because

capital stock has not turned over as quickly in recent years as it did in the 1960’s, there

is a large backlog of retrofit improvements to be made. Furthermore, high capital costs

and the limited capital pool have kept many new process technologies from penetrating

product markets. OTA projects that new processes or process technologies would

save more energy than would retrofits and housekeeping measures, and would reduce

overall costs by improving productivity and product quality. However, such process

shifts will entail large capital outlays, which in turn, will require general economic

growth over many years. Without economic growth, there will not be enough product demand or capital to support these productivity improvements.

A product mix shift away from energy-intensive products will also continue to

contribute to the decline in energy use growth rates. Product mix shift will occur within

specific industries (e.g., a shift from basic chemical production to agricultural/specialty chemical manufacture) as well as from one industry to another (e.g., a shift away

from steel to aluminum and plastics in auto manufacture). These shifts are driven by

*A Quad equals 1 quadrillion (1015) Btu.

* “This IS final demand, so that electricity IS accounted for at 3,412 Btu/kWh

ix
changing demand patterns and international competition, as well as by increasing energy

prices.

OTA found that corporations have a strategic planning process that evaluates and

ranks investments according to a variety of factors: product demand, competition, cost

of capital, cost of labor, energy and materials, and Government policy. In analyzing

energy-related investment behavior, OTA found no case in which a company accorded

energy projects independent status. Although energy costs are high in each of the

four industries examined by OTA, costs of labor, materials, and capital financing are

also high. Thus, energy-related projects are only part of a general strategy to improve

profitability and enhance a corporation’s competitive position.

Most firms regard energy efficiency as one more item in which to invest and not

as a series of projects that are different from other potential investments. This view

differs significantly from the view of firms that produce energy or energy-generating

equipment where the entire investment is focused on increasing energy production.

This difference has important policy implications because incentives aimed at reducing energy demand growth must compete with other strategic factors and are therefore

diluted. Energy incentives directed at increasing energy supply suffer no such competition.

Of the four most energy-intensive industries, chemicals and paper will show the

largest growth in production over the next two decades and will also show a substantial

increase in energy efficiency. In the paper industry, energy use has risen slightly since

1972, but the industry is now more energy self-sufficient. In 1981 the paper industry

generated half of all its energy needs through the use of wood residues as fuel. By 2000

self-generation of energy could result in the paper industry meeting over 60 percent

of its needs internally. The limitation on the percentage of self-sufficiency is the value

of the product foregone by using feedstock (wood) as fuel. Also, the paper industry’s

use of oil will decline as residual oil is displaced in boilers by coal and biomass fuels,

OTA projects that over the next two decades, energy use per ton of paper will decline,

owing to specific process changes in papermaking steps, such as oxygen-based

bleaching, computerized process controls, and new methods of making paper.

The petroleum refining industry will show a decline in overall product output

but will continue to improve its energy efficiency, although only slightly. Energy efficiency gains from retrofit and housekeeping measures will be merely offset by a shift

to heavier, high-sulfur, crude oil feedstocks and by increased use of energy in refining

because of market requirements for high-octane, unleaded motor fuels. Of the four

industries, this is the only one in which product or process shifts are not projected

to lead to less energy use. Nonetheless, overall efficiency can be expected to improve

as a result of a number of anticipated technological changes in refinery operations,

such as the extensive use of vapor recompression and waste heat boilers in the distillation and cracking processes and the use of computerized process controllers to optimize plant operations.

In the chemicals industry, energy efficiency improvements will result from a combination of retrofits to existing processes and technical innovation in new processes

and products. For example, vapor recompression, process controls, and heat recuperators and exchangers will be added to existing processes to improve thermal efficiencies. In addition, there is a trend toward increased use of electricity and coal and away

from premium fossil fuels, especially natural gas. OTA projects that by 2000, coal use

will account for almost one-third of the fuel used in the chemicals industry. An important source of energy efficiency improvement in the chemicals industry is a shift in

product mix. Because of higher profit margins and less foreign competition, the in-
dustry will increase production of less energy-intensive, higher value chemicals, such

as pharmaceuticals and pesticides, relative to more energy-intensive chemicals such

as ethylene and ammonia.

As the steel industry retools to meet foreign competition, there will be a large

reduction in energy intensity. The major source of this decline will be investments

in new processes— i.e., 1 ) the replacement of ingot casting by continuous casting, and

2) the substitution of electric arc furnace or mini mills for the blast furnace/basic oxygen furnace combination. With continuous casting, significant energy will be saved

by not having to reheat cooled metal ingots before shaping. Electric arc minimills will

save energy by substituting scrap metal feedstocks for iron ore, thus reducing coke

demand. This trend will also result in the substitution of steam coal for metallurgical

coal since the former will most often be used to generate electricity,

Over the years, Congress has passed a number of measures that affect the industrial

use of energy. in general, the goals of these measures have been to reduce oil imports, encourage domestic production of fossil fuels, and reduce energy demand through

efficiency improvements. OTA found that legislation directed specifically at improving energy efficiency in industry has little influence on investment decisions. At the

highest levels of corporate financial decision making, there is an awareness of Government tax and industrial policies. However, OTA found that technical decisions and

energy project evaluation tend to be separate from and subservient to corporate financial

decisions. Moreover, the decision to invest depends not only on an individual project’s return on investment, but also on such corporatewide parameters as debt-equity

ratio, debt service load and bond rating, and, most importantly, the aforementioned

strategic considerations of corporate decision making. Because energy must compete

with other factors of production when investment choices are made, policy incentives directed at energy demand alone will be just one of a number of considerations in making these choices. Unless such incentives are substantial, they are unlikely to alter a decision that would have been made in the absence of such incentives.

To assess the effects of a range of incentives on energy use in industry, OTA selected

a set of policy initiatives directed at energy specifically or at corporate investment in

general. The latter include the accelerated cost recovery system (ACRS) provisions of

the Economic Recovery Tax Act of 1981 (ERTA) and increased capital availability for

investment, while the former include broadened and expanded tax credits for energy

investments and the imposition of energy taxes on premium fuels. These policies are

compared to a reference case consisting of current economic conditions and the tax

code as amended by ERTA.

The effect of the ACRS on increasing energy efficiency depends on the ability of

the ACRS to increase investment. OTA found that the ACRS is a positive stimulus to

investment when the industry is profitable and growing. Under these conditions, total

investment and energy efficiency improvements would be accelerated by the ACRS.

As long as conditions of high interest rates, low-to-moderate demand growth, and

the like exist, however, the ACRS will do little to increase energy efficiency.

Energy investment tax credits at a lo-percent level have little direct influence

on capital allocation decisions in large American firms, and thus have little or no

influence on energy conservation. These tax credits appear to be too small to exert

any change in the return on investment of a company when the only factor they affect

is energy. However, energy investment tax credits directed at energy production, such

as cogeneration by third parties, would be effective. In this case, the entire investment would be covered by the tax credit, and energy would be the principal product

being produced by the investment. Regarding investments in technologies that improve

x i
the energy efficiency of industrial process technologies, however, OTA could find no

case where decisions to undertake a project depended on gaining a 10-percent energy

investment tax credit.

Taxes at a rate of $1 per million Btu on premium fuels—natural gas and petroleum—would change the fuel mix and cause energy efficiency to improve, although

not by more than a few percent. Because of the already large cost differential between

premium fuels and coal, the increase in costs as a result of the tax would not significantly

change the economic incentive to switch to coal. The effect of the tax would be more

significant for electricity, but there the availability of industrial production technologies

that use electricity instead of petroleum or natural gas would be the limiting factor.

Consequently, imposition of the tax would cause only a slight increase in conversion

to coal and electricity from natural gas and petroleum. Investments in energy efficiency through retrofits and new process technology would still primarily be limited by

capital availability and growth in product demand.

The fuel tax would have different consequences for each of the energy-intensive

industries investigated. OTA found that a premium fuels tax would accelerate energy

self-sufficiency and decrease natural gas consumption in the paper industry. The petroleum refining industry might be affected by a premium fuels tax in two ways:

I ) some energy-related projects would be given a higher priority, and 2) earnings would

decline because of a general decrease in product demand. In the chemicals industry,

the domestic impact of a premium fuels tax is potentially detrimental. The greatest impact would likely be on the ability of the industry to export products as well as to make

the domestic market more vulnerable to imports. Finally, a premium fuels tax would

be least detrimental to the steel industry because only a small percentage of the industry’s energy is derived from petroleum sources.

The best way to improve energy efficiency is to promote general corporate investment by reducing the cost of capital. Corporations that believe energy prices will

continue to rise have a strong impetus to use capital for more energy-efficient equipment. Low interest rates affect energy efficiency to the extent that lower rates may allow

a company’s cash flow to go further, its debt service to be less burdensome, or its ability

to take on more debt to increase. Lowering interest rates would increase capital availability and therefore allow more projects to be undertaken. Improvement in capital availability would magnify the effect of the ACRS because the ability to make use of the latter

depends on the investment climate. At the same time, however, it should be recognized

that growth in product demand is essential if investment is to take place, even with

lower interest rates.

xii
Photo credit: Sun Oil Co.
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.
Chapter 1

Summary and Findings

Virtually every function of industry uses energy.

Efficient use of this energy is affected by, among

other things, avaiIable technology, capital investment, and the cost of energy. Since 1973, the cost

of premium fuels such as petroleum distillates and

natural gas has increased over a factor of three

in real terms. I n response, the industrial sector

has taken numerous steps to reduce its energy

use per unit of output. However, many opportunities still exist to use energy even more efficiently. OTA examined those opportunities to determine why they were not being exploited and

to see if legislative policies could encourage faster

improvements.

The OTA study focused on the four industries

that use the most energy: paper, petroleum refining, chemicals, and steel. These industries were

examined in detail for three reasons. First, it was

assumed that if conservation and the more efficient use of energy had any role to play in U.S.

manufacturing, it would be most apparent in

these four industries. In 1981, these industries

used nearly 10 quadrillion Btu (Quads) of final

energy* (about 43 percent of all energy used by

the industrial sector). Thus, these industries are

likely to be the leaders in increasing energy

efficiency.

Second, to the extent public policies have an

effect on energy use, that effect should be greatest

and most apparent where energy use is greatest.

Such policies could result from a desire to reduce

oil imports, to forestall depletion of domestic supplies of energy resources, and, perhaps most importantly, to improve the Nation’s overall economic health.

Finally, by examining the operations and decisions of these industries and their constituent

● This numher idlues elrc trlc Ity at 3,412 Btu/kWh. It IS final c~emdnd

firms, it should be possible to evaluate progress

in energy conservation and the impacts of legislation as they would most likely occur. Each of

these four industries explicitly considers energy

in management activities and investment planning because energy use accounts for a significant share of each industry’s production costs.

OTA examined the technical options available

to each industry and the factors that guide investment decisions about energy efficiency improvements. A principal part of the analysis was a series

of case studies of both large and small companies

in each of the four industries. In addition, a series

of engineering consultants knowledgeable about

industry and its operations were asked to make

independent appraisals of each industry and casestudy firm. At workshops, industry representatives, consultants, OTA staff, and others integrated the results.

For the repot-t, OTA identified the technical and

economic potential for energy conservation and

also for switching from high-cost and insecure

premium fuels to lower cost domestic fuels in

each industry. Both changes were seen to improve energy efficiency because they decrease

the cost of energy per dollar of production. As

a necessary part of its analysis, OTA examined

the manner in which capital budgeting decisions

about energy efficiency-improving projects were

made. OTA also examined and identified the barriers that prevent efficient use of energy and

assessed the likely effects on each industry of a

selected list of Government policy initiatives on

energy use and capital funding. The policies included the accelerated depreciation provisions

of the 1981 Economic Recovery Tax Act, broadened and expanded tax credits for energy investments, imposition of energy taxes on premium fuels or equivalent price increases, and increased capital available for investment.

3
4 ● Industrial Energy U s e

U.S. INDUSTRIAL ENERGY USE

In 1981, U.S. industry used over 23 Quads* of

energy-bearing materials, mostly as fuel, but also,

in some cases, as feedstock. * * Manufacturing accounted for about 75 percent of that total; mining accounted for another 12 percent; and agriculture and construction, another 6 percent. The

four manufacturing industries studied in depth

by OTA accounted for about 57 percent of the

total energy used in manufacturing, including 74

percent of the oil and 60 percent of the natural

gas.

Between 1972 and 1981, American industrial

energy use declined by over 2 Quads, and energy

efficiency improved by almost 18 percent per unit

of production. Even more noteworthy than the

drop in absolute energy consumption was the decline in the rate of energy use compared to the

rate from the previous decade. if growth rates of

that decade had continued, industrial energy use

would have reached nearly 40 Quads by 1981.

While this decline might initially be considered

purely a gain in energy efficiency, analysis carried out by the Department of Energy (DOE) suggests that it is the result of a more complex

process in which a changing product slate and

a general decline in the growth of manufacturing output over the 1970’s combined with energy

efficiency to reduce overall energy use.

Industrial energy efficiency gains between 1972

and 1981 are notable in that they have occurred

at the same time the rate of economic expansion

declined. Given that capital has been severely

restrained because of high interest rates and

depressed sales, management has been less able

to purchase new fuel-efficient capital stock than

it could have if the economy were expanding at

1960-72 rates.

Domestic energy prices have greatly increased

(in real dollars) over the past decade, leading to

significant changes, both in the absolute amount

“Quadrillion Btu. This IS final demand, for which electricity use

is computed at 3,412 Btu/kWh. It Includes petroleum products, natural gas, coal, and nonpurchased fuels such as biomass. Including

conversion losses in producing the electricity, industry can be said

to have used over 29 Quads of primary energy,

* *Feedstocks are raw materials, natural or manmade, used in

production,

of energy and in the mix of energy used in industry. Prices for distillate petroleum products

have more than tripled over the past 12 years,

while the cost of natural gas has risen by nearly

four times. The overall average price of energy

has increased from $1.86 to $3.69 (in 1972 dollars) per million Btu.

The change in the amount and mix of energy

used by the industrial sector is shown in figure

1. Use of petroleum products increased from a

1951 level of under 5 Quads to a 1979 high of

10.3 Quads. It has since declined to almost 1970

levels. The use of coal has declined from a 1951

level of over 6 Quads to a 1981 level of 3.2

Quads. Natural gas use is down by over 1.0 Quad

since 1971, while electricity use has increased by

1 Quad.

In the pulp and paper industry, total energy use

has risen slightly since 1972. However, the industry is more energy self-sufficient, and energy

use from purchased fuels has declined. The integrated mills that convert trees to pulp and then

to paper are almost 25 percent more efficient now

compared to 1972. Mills that convert purchased

pulp to paper are almost 20 percent more efficient. Much of this energy efficiency has shown

up in decreased use of residual fuel oil* (down

40 percent since 1972). Overall, the paper industry has exceeded its voluntary goal of 20-percent improvement by almost 5 percentage points.

The petroleum refining industry has decreased

its overall energy use per unit of output by 20.8

percent, primarily by reductions in natural gas

use (down 37 percent since 1972) and distillate

and residual fuel oil use (down 62 percent and

31 percent, respectively). Based on 1972 production levels, the industry exceeded its voluntary

goal of a 20-percent energy savings.

In the chemicals industry, energy use per unit

of output has decreased by 24.2 percent since

1972 through decreased use of natural gas (down

24 percent) and residual fuel oil (down 42 per-

..— —

* Residual fuel oil IS the heavy hydrocarbon material remaining

after crude 011 IS distilled; distillate fuel oil iS the lightweight hydrocarbon material derived from crude 011 via distillation.
Ch. l—Summary and Findings . 5

Figure l.— Industrial Energy Demand, 1950-2000

35

I

I Historical demand I Projected demand I

30

t I

Non purchased J

energy A

c

.—o

n.—

I

Residual and

distillate petroleum I

cent). Compared to 1972 production levels, the through decreased use of bituminous coal (down

industry exceeded its 1980 industry improvement 35 percent) and metallurgical coke (down 36 pergoal by more than 10 percentage points. cent).

The steel industry has decreased its use of

energy per unit of output by 17 percent, mostly

ENERGY CONSERVATION

Energy efficiency improvements can be classified into four categories: 1) improved housekeeping; 2) equipment retrofit; 3) shifts to new process technologies (usually as a result of capacity

expansion) to make existing products; and

4) shifts to new, less energy-intensive, product

lines (see table 1). By and large, investments in

(1) and (2) involve relatively small commitments

of capital, whereas more is required of (3) and

(4). OTA finds that housekeeping procedures, by

and large, have been or are being done. Managers in energy-intensive American corporations

seem keenly aware of the cost of energy and

therefore of the need to minimize its use. Housekeeping is one way to accomplish this task rapidly

and inexpensively. Retrofits to existing equipment, however, are not as common. Given the

existing economic environment—with high interest rates, depressed capacity utilization, and,

in some cases, declining sales—retrofit additions

99-109 0 - 83 - 2
6 ● Industrial Energy Use

Table 1.—Categories of Energy-Related Capital Investment

Definition cost Payback period Example

Housekeeping

Substitution of labor Very low

and management

effects for energy

Equipment retrofit

Addition of new parts; Usually

substitution of existing moderate

parts on functioning

capital equipment

Process shift

Building of new facilities Often quite

to manufacture existing high

products with new

processes

Product switching

Undertaking the Moderate to

production of a new quite high

series of products

Very short

Months to

several years

Many years

One to many

years

Setting up routine procedures

to check, clean, or replace

steam traps; manually

adjusting and optimizing

boiler controls, monitoring

building for air leaks, and

the like

Installation of computerized

boiler control for maintenance

of optimum burner efficiency;

installation on process stream

lines of additional heat

exchanger surface

Building new minimill for

production of steel from scrap

metal; manufacture of linear

low-density polyethylene at

low pressure using new

catalytic system

Switching from production of

bulk commodity chemicals

to that of biotechnology

chemicals

SOURCE: Office of Technology Assessment

are often perceived as strategically unjustified.

OTA has found that most retrofits have very short

payback periods; i.e., the projects pay for themselves through decreased energy costs in less than

2 years.

Investment in new equipment is very likely to

be the most effective means of increasing energy

efficiency. As of 1975, 57 percent of all capital

equipment in manufacturing was 25 or more

years old. Much of this equipment was built

wherever space permitted at existing industrial

sites and with little regard for minimizing energy

losses. In new plants, final products can usually

be made with less energy. However, investments

in new processes and process equipment, especially in the 1981-82 economic environment,

have been rare, a situation that also existed

throughout the late 1970’s in some industries.

Capital costs are now very high, and in the present investment climate, risks seem great. Many

consider it better management to delay investments rather than risk damaging the economic

health of their companies.

Another trend, the shift to less energy-intensive

products, will also contribute to increasing energy

efficiency per economic output. This phenomenon accounted for about 10 percent of the total

reduction in industrial energy in 1981 relative to

a continuation of the 1950-73 trend. Product mix

shifts will occur within specific industries and will

also result from one industry growing while another declines. Product shifts can also result from

the introduction of new or improved products

that provide a given service but require less

energy to manufacture than do the products they

replace. Product shifts are driven by changing demand patterns, international competition, and increasing production costs (including energy

costs) .

To assess technical and economic opportunities

for improving energy efficiency, OTA projected

industrial energy demand based on assumptions

about future energy prices, product demand, interest rates, and the use of a range of technologies

available for increasing energy efficiency. Table

2 presents the energy price assumptions. Table

3 presents a summary of energy growth rate pro-
Ch. l—Summary and Findings ● 7

Table 2.—Average Industrial Fuel Prices Assumed in

OTA Modelinga (1980 dollars per million Btu)

1980 1985 1990 2000

Gas . . . . . . . . . . . . . . . . . . . . . . . . . 3.0 5.0 6.3 9.0

Residual oil . . . . . . . . . . . . . . . . . . 5.0 5.0 6.2 9.0

Distillate oil . . . . . . . . . . . . . . . . . . 6.7 6.6 7.7 10. 5

Coal . . . . . . . . . . . . . . . . . . . . . . . . 2.1 2.2 2.3 2.4

Electricity (at 3,412 Btu/kWh) . . . 12.6 13.8 13.7 13.8

Steam . . . . . . . . . . . . . . . . . . . . . . . 5.5 5.9 6.3 7.4

Assumptions

Gas —Price follows Natural Gas PoIicy Act (Public Law 95-621) deregulation

scenario

Residual oil —Follows Energy Information Administration’s (EIA) projected

refinery acquisition crude 011 price (steady at $32 through 1987, then up to $58

by 2000)

Distillate oil —Commanding a high premium over crude 011 because of growth

in demand

Coal —Follows EIA forecast of low growth in mine and transportation prices

Electricity —Follows 011 and gas prices in 1960’s, then shifts to those of coal

Steam —Price affected by boiler/cogenerator mlx and natural gas/coal fuel

demand

aOTA’s modeling effort actually uses a range of fuel prices that reflects the quality

of fuel and the different energy prices in various geographical regions of the

United States

SOURCE Off Ice of Technology Assessment

jections and their relationship to overall production in the entire industrial sector and in the casestudy industries.

Two major conclusions may be drawn from the

data in table 3. First, from the standpoint of the

entire industrial sector, including mining and

manufacturing, available technology and expected energy price changes* will allow industrial

output to grow at a much faster rate than that

of energy use. OTA projects that for the next two

decades industrial energy use can grow at a rate

of not more than 1 percent per year, with a 2.7

*Although OTA has not modeled fuel price sensitivity in detail,

higher price Increases are expected to cause even greater efficiency gains, and a lower energy growth rate.

percent per year average growth rate in the gross

national product (GNP). This compares to an

energy use growth rate of 3.1 percent per year

from 1950 to 1973 relative to a GNP growth rate

of 3.8 percent per year. Moreover, the output

growth projected here will occur with virtually

no increase in the use of the two premium fossil

fuels–natural gas and oil–because coal and electricity (generated from coal or nuclear fuels) can

provide the energy needed for growth. Dependence on premium fuels will still be high and industry will remain sensitive to oil and gas prices.

Figure 1 shows the projected changes in energy

used by industry.

Second, in three of the four major industries

closely examined by OTA, the two major alternatives for improving energy efficiency, product

and process shifts, will bring about greater improvement than will retrofit and housekeeping

measures. However, product and process shifts

are by far the most expensive investments and

depend on a strong product market to make them

economically attractive. These large investments,

however, do more than save energy; they increase overall productivity by reducing the costs

of all factor inputs and by improving product

quality. Indeed, the latter are the primary goals

of such investments, and without productivity improvements, energy efficiency gains will be considerably less.

An important point to note is that these investments are long term, for the most part; i e.,

their major effects will not show up until the

1990’s. Furthermore, these efficiency improvements will continue past the year 2000 as new

Table 3.—Relative Energy/Output Growth Patterns for Years 1980-2000 (percent per year)

Total

Paper Petroleum Chemicals Steel sector

Product output growth ratea . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.9 -0.3 4.0 1.2 2.7

Change in energy growth from:

Product/process shifts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -1.0 + 0.5 -1.7 -2.0

}

-1.7

Improved efficiency from existing processes and machines . . . -0.7 -1.2 -0.6 -0.4

Results in:

Energy demand growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2 -0.7 1.7 -1.7 1.0

iiln this projection, the indu~tri~l ~~ctor includes the a~tlvltles of mining, coflstructlofl, and agriculture a.s Well as manufacturing, Growth In industrial OUtpUt WaS prO.

jected by the Mellon Institute, using the macroeconomic models of Data Resources, Inc , and Dale Jorgenson Associates, Inc. In terms of these two models of the

U S economy, a 2 7-percent growth in Industrial output is consistent with a sim!lar rate of growth for the gross national product, For further discussion of macroeconomic

assumptions and analyses see Fma/ Report’ /ndustria/ Energy Producfw/ty Project, Energy Productivity Center, Mellon Inst!tute, September 1982, pp. 11-24.

SOURCE: Office of Technology Assessment.
8 ● Industrial Energy Use

processes and process technologies become a

larger share of total production and as production of less energy-intensive products becomes

a larger portion of overall industrial output. For

the 1980’s, increases in efficiency will be largely the result of retrofit and housekeeping measures and investments in new equipment made

during the 1970’s.

Investment Considerations

In setting overall priorities among different

product lines and production facilities, firms place

energy efficiency in the context of a larger strategic planning process. * In all cases analyzed, industry was found to make investment decisions

that affect energy efficiency on the basis of a

strategic planning process that considers not only

energy costs, but also a number of other factors.

The

1.

2.

3.

most important of those factors are:

Perception of product demand: In particular, energy conservation projects in product lines that are declining are not considered good investments, even at very high

rates of return. On the other hand, energy

conservation projects in product lines whose

markets are expanding will be undertaken

at even moderate rates of return.

Perception of competition: Competition can

arise either from a technological basis, such

as the challenge of electronic mail to the

paper industry, or from foreign competitors

within the same industry, because of lower

labor costs, lower capital costs, and so forth.

The cost of capital: Corporation managers

invest their money in projects related to one

of the four investment categories or in some

type of revenue earning account. Funding

required beyond that available within a company comes primarily from borrowing.

Given the economic circumstances of 1980

and 1981, one of the major barriers to investment in energy conservation projects is

the very high cost of capital, Also, because

banks, insurance companies, and other fi-

*There are, of course, many small investment opportunities, some

energy-related, which may not be subjected to exhaustive strategic

analysis. Funds for such projects are usually allocated by a supervisor or pIant manager from a small discretionary pool of funds in

the annual budget.

4.

5.

nancial institutions are reluctant to commit

funds to organizations with large debt loads,

many firms find themselves with capital

funds constrained by debt-related factors. As

a result, companies are forced to limit their

investment in new projects, and many highreturn, energy efficiency-improvement investments are foregone.

The cost of materials and labor: A project

may be energy efficient yet still economically

undesirable if it requires more expenditure

of labor or uses more material than is presently used. For instance, it is possible for integrated paper manufacturers (i.e., those

who produce both pulp and paper, rather

than purchase pulp to make paper) to become even more energy self-sufficient by

burning more of their wood feedstock. However, this practice would result in less pulp

available for other uses. At current energy

prices, this trade of material for energy

would be unacceptable.

Government policy, or lack of certainty

about Government policy. Government policy can address investment in general or be

targeted specifically to energy. Of major importance are those policies that affect the entire economy, since investment can be particularly constrained during periods of depressed economic activity.

When all capital projects being considered by

a corporation are examined, the investment

menu can be divided into mandatory and discretionary categories. OTA has found that mandatory projects are by far the most numerous. Discretionary capital funds are those that remain

after mandatory investments have been made.

Mandatory projects such as pollution control

equipment and projects needed to support a capital expansion are generally not affected by

energy costs and the five factors just listed above.

Discretionary capital investments, however, are

subjected to the corporation’s strategic planning

process, which is guided by the six (including

energy costs) factors. In some companies, the decision to invest in discretionary projects comes

only after a very formal process. In other firms

examined by OTA, the process seems less formalized, but still subject to the perceptions of
Ch. l—Summary and Findings ● 9 — . —

managers about growth potential of a product;

market and technological competition; and use

of capital, labor, and materials.

Energy efficiency investments fall within the discretionary category. All firms regard energy efficiency as one more item in which they could

invest, not as a series of projects that are different from other potential investments. In no

case has OTA found companies that accord energy projects independent status. Rather, energyrelated projects are part of the general strategy

governed by the factors listed earlier. These projects must contribute to the corporate goal of increased profitability and must enhance a corporation’s competitive position.

While ideas for energy conservation can arise

from anywhere, even outside a company, the approval process can often be complex and the

project analysis, exhaustive. OTA found that

technical decisions tend to be separate, and

subservient to, corporate financial decisions.

Plant engineers are usually not participants in

detailed financial assessments.

In general, individual project financing is not

considered when a large list of projects is being

evaluated for their technical merits, despite the

fact that when returns (i.e., energy savings) are

high and a project is highly leveraged (i.e., much

of the money used to buy the equipment is borrowed), the individual returns for each dollar invested can be very high. Large corporations consider borrowing funds only at the highest deci -

sionmaking levels and when all projects have

been evaluated. At that time, the decision to borrow is guided by the strategic considerations

listed earlier and depends not only on the returns

of an individual project, but on such corporatewide parameters as debt-equity ratio, debt-service

load, and bond rating. Because project economics and corporate finance are treated separately by corporations, a Government policy which

is designed to promote energy efficiency by influencing only project economics, but fails to

affect corporate finance, will be ineffective.

Case= Study Industries

Investment decisionmaking by the case-study

industries illustrates the importance of the several

investment factors and indicates the technology

choices being made.

Pulp and Paper

In the U.S. pulp and paper industry, investment

strategy is affected by the relative freedom from

import competition (no other nation except

Canada has a comparable resource base of marketable timber) and by the industry’s close association with the wood building products industry.

The absence of import competition and the presence of significant export prospects have been

major factors in keeping profits and investments

high. The paper industry’s special relationship

with the wood building materials industry is competitive in that they share the same resource base;

it is also cooperative, in that firms tend to be

engaged in both industries in order to spread risks

and to pool capital investments in timberland and

i n wood harvesting and handling technology.

Pulp and paper firms perform little research and

development; instead, they rely on that of equipment suppliers.

Energy conservation improvements in the pulp

and paper industry have come about through improved housekeeping measures and increased

capability to recover energy from waste. In the

latter case, the industry moved from supplying

41 percent of its energy needs from self-generated

sources in 1972 to 50 percent by 1981.

OTA projects that the energy intensity of

paper production—i.e., the energy required to

produce a ton of product-will decline by nearly

18 percent by 2000 (fig. 2A) because of specific

process changes anticipated for each of the

papermaking steps and from changes that

should occur in overall energy production and

use in the paper industry. In particular, major

economic opportunities exist for cogeneration,

Also, pulping energy demand will likely decline,

owing to the increased use of continuous digest-
IO . Industrial Energy U s e

Figure 2.–Energy Intensity Projections, 1970-2000

o

1-

A. Paper Industry

Historical Projected

data data

.- - .

1970 1975 1980 1985 1990 1995 2000

Years

c. Chemicals Industry

Historical Projected

data data

--- -

20

19

18

17

16

15

14

13

12

11

10

1970 1975 1980 1985 1990 1995 2000

Years

SOURCE Office of Technology Assessment

ers (as opposed to batch processing). I n addition,

projected secondary fiber pulping–i.e., recycling

of wastepaper such as newsprint—will contribute

to the decline. Energy savings can also be expected in the bleaching process by displacing

energy-intensive chemical bleaching with oxygen-based bleaching, assuming technological

risks of equipment failure and plant downtime

can be minimized. In the papermaking process,

energy can be used more efficiently if computerized process control and new technology

can be employed. Also, if natural gas prices continue to go up, this industry can be expected to

B. Petroleum Refining Industry

Historical Projected

data data

... -

1= 1970 1975 1980 1985 1990 1995 2000

Years

c

o

D. Iron and Steel Industry

c

.o-

=. -

2

Historical Projected

data data

--- -

38

36

34

32

30

28

26

24

22

20

18

1970 1975 1980 1985 1990 1995 2000

Years

substitute electricity for gas in its paper drying

processes.

Overall, the pulp and paper industry mirrors

aggregate industrial trends, except that its oil use

will decline rapidly as number 6 residual oil is

displaced in boilers by coal and biomass fuels.

This industry is unique in its long history with

biomass fuel (primarily wood) because of its dependence on biomass feedstocks. The biomass

fuel alternative will look more attractive in the

future as fossil fuel prices rise. Over the next 20

years total energy per ton of paper shipments
Ch. l—Summary and Findings ● 1 1

should decline by over 25 percent, while purchased energy should drop by 42 percent. The

difference reflects an anticipated increase in the

industry’s use of biomass fuels.

Petroleum Refining

The domestic petroleum refining industry is

dominated by vertically integrated firms that produce crude oil here and abroad and sell petroleum products to final consumers. Since petroleum production has been and should continue

to be profitable, investment in domestic refining

will be limited by available funds only in the sense

that refining activities must compete with exploration and drilling.

The domestic refining industry is getting smaller

because of the reduction in demand caused by

the rising prices of petroleum-based fuels relative

to prices of all other fuels and other goods and

services in general. This situation has led to the

substitution of other products for petroleum products and hence has reduced the demand for refinery outputs. In 1981, the refinery utilization

rate was onIy 65 percent of capacity. At the same

time, the refinery product slate was shifting away

from regular, leaded gasolines to unleaded,

higher octane products and to a steadily declining fraction of residual fuel oil. Also, there was

a shift in crude oil away from the more easily refined light, low-sulfur crude oils toward heavier,

high-sulfur crude oils.

The OTA projection presented in table 3 shows

energy use in petroleum refining operations to

decline 0.7 percent per year. This reduction is

primarily the result of retrofit and housekeeping

measures. The shift to heavier, high-sulfur crude

oil feedstocks, combined with the market requirements of high octane, unleaded motor fuels, necessitates a growth in energy use of 0.5 percent

per year to accommodate these product and

process shifts.

Of the four industries studied by OTA, petroleum refining is the only industry in which product or process shifts are not projected to lead

to less energy use. Nonetheless, overall energy

efficiency, as reflected in the decline of energy

intensity in refinery operations, can be expected

to improve, as shown in figure 2B. The average

energy intensity is projected to decline by nearly 10 percent from 1980 to 2000. This reduction

will be the result of a number of anticipated technological changes in refinery operations, primarily in distillation and cracking.

In distillation, energy can be conserved through

improved efficiency in distillation heaters, extensive use of vapor recompression and waste heat

boilers to maximize the recovery of heat content

from waste streams, and the use of computerized

process controllers to optimize plant operations.

New process technologies should be available to

convert undistilled residual oil (called residuum)

to middle distillate products suitable for further

refining and, at the same time, produce steam

for plant process use. Thus, while use of fossil fuel

for heaters is expected to grow slightly as the

economy expands, demand for steam from boilers will decrease. Overall electricity use will grow

because of the use of vapor recompression. In

the cracking processes, increased efficiency from

the use of vapor recompression and process control will be partially offset by the increased need

for energy to perform hydrocracking operations

on the heavier, more sulfur-laden, crude oil feedstocks.

Regarding shifts in refinery fuel, the projection

of existing trends indicates that there will be a

substitution of coal for gas in fuel boilers and as

a source of hydrogen in reforming. But the extent of both changes will depend primarily on the

price of natural gas. Gas price also affects substitu -

tion of gas for oil. If natural gas prices increase

sufficiently, oil could be substituted for gas in

direct heating.

Chemicals

The chemicals industry is the most dynamic of

the four industries examined by OTA. It makes

the most diverse set of products. The greatest portion of its energy use occurs in the production

of commodity chemicals such as ethylene, polyethylene, benzene, and the like. The proportion

of energy use is less in intermediate and final consumption chemicals, such as pharmaceuticals

and agricultural pesticides.

The chemicals industry uses the largest amount

of energy-bearing materials of the four industries
12 ● Industrial Energy U s e

examined by OTA. Its use of both total energy

and premium fuels—i. e., oil and natural gas—is

larger as well. The energy intensity of the

chemicals industry over the next two decades

is projected to decrease by about 9 percent (fig.

2c), resulting from a combination of retrofit

equipment and technical innovation in new processes; e.g., vapor recompression, process controls, and heat recuperators and exchangers that

will all be used to improve thermal efficiencies.

In addition, there is a distinct trend in this industry

toward increased use of electricity and coal and

away from premium fuels. For instance, as processes for producing ammonia and methanol from

coal come onstream in the next two decades, less

natural gas will be required and more coal will

be used. The OTA projection indicates natural

gas use will go from 45 percent of the total energy

used in the chemicals industry in 1980 to 19 percent in 2000, while coal will increase its share

from 6 to 29 percent.

For chemicals, probably the most important

source of improvement in energy intensiveness

is shifting the product mix. This shift-from

energy-intensive commodity chemicals to higher

value pharmaceuticals, pesticides, and other consumer products—is occurring for two reasons.

First, profit margins on commodity chemicals are

low, while margins are higher for lower volume,

higher valued products. Demand for the latter is

growing much faster, so that these less energyintensive products are attracting the bulk of investment in the United States. Investments in

processes for manufacturing chemicals such as

ammonia and ethylene are low because large

supplies have recently come on the international

market from OPEC and other energy-rich nations

that view the production of commodity chemicals

as the best way to increase revenues and to expand industrial employment.

Steel

Among the four key energy-using industries,

steel now suffers the most from declining domestic sales. In addition, older, large-scale, integrated

firms also suffer from competition from domestic

minim ills that can produce steel at much lower

costs. investment strategies vary a great deal between the older, integrated firms and the newer

minim ills. The former have been forced into

triage, sacrificing older mills to husband resources

for their most efficient and highest profit operations. Even for the latter, many energy-related

projects cannot be undertaken because of limited

funds or because of abnormally low use of existing capacity. At minim ills, capital availability

does not now appear to constrain investment in

energy efficiency or for any other objective as

long as target hurdle rates* for returns on investment are achieved.

OTA projects that energy use by the steel industry could decline at a rate of 2 percent per

year, while output would grow at an annual rate

of about 1 percent. The major source of this

energy efficiency improvement will be process

change—in particular, the replacement of ingot

casting by continuous casting and the substitution of the electric arc furnace production (using

scrap metal feedstocks) for the blast furnace/basic

oxygen furnace combination (using iron ore feedstocks). The latter change will also result in the

substitution (in the form of electricity) of steam

coal for metallurgical coal.

OTA projects a decline in energy intensity of

about 39 percent from 1980 to 2000 (fig. 2D). This

decrease will result from the decline of the integrated production of steel and from the continued improvement in the amount of steel produced by electric arc facilities and continuous

casting. Growth in mini mill steel production will

result in a decline in hot metal production from

open hearth or basic oxygen furnace operations

and a decline in coke production and coke use.

With continuous casting, there will be significantly more energy saved than with batch operations.

*An investment hurdle rate is defined as the minimum return a

project must have to be acceptable to a firm.
Ch. l—Summary and Findings ● 1 3

POLICY

To assess the effects of a range of incentives

on energy use in industry, OTA selected a set of

policy initiatives directed at energy or corporate

investment. These options include the following:

●

●

●

●

Option 1: Removal of the accelerated cost

recovery system (ACRS) provisions of the

1981 Economic Recovery Tax Act.

Option 2: Addition of a 10-percent corporate

income tax credit for investments in energy

efficiency-improving equipment.

Option 3: Imposition of a premium fuels tax

of $1.00 per million Btu on petroleum fuels

and natural gas.

Option 4: Lowered interest rates as a surrogate for capital availability.

In addition, OTA attempted to determine how

these policies would most affect the operation

of a corporation. While the analyses can be used

to project absolute energy use in each policy option case, their primary benefit is to allow a comparison of each legislative option to the reference

case.

REFERENCE CASE

The Current Economic and Legislative

Environment, Including the 1981 Economic

Recovery Tax Act

projections of total industrial energy demand

and fuel mix for the reference case have been

shown previously in figure 1. These projections

were based on the energy price assumptions

shown in table 2 and on the economic growth

rates shown in table 3. I n figure 3, OTA projects

industrial sector energy intensity between now

and 2000. Given the reference case, with its

assumption of the current legislative environment, including ACRS depreciation, purchased

energy use per dollar of industrial output should

decline from a 1980 level of over 50,000 Btu per

dollar to under 35,000 Btu per dollar by the end

of the 1990’s.

Two points should be. made about the projections presented. First, improvements in energy

efficiency are due primarily to investments in

new processes and process equipment. These

investments and the demand for energy, howOPTIONS

Figure 3.— — Industrial Sector Energy Intensity

Projection, 1972-2000

-- -

Historical Projected

data data

--- -

~ : ~

20

1970 1975 1980 1985 1990 1995 2000

Year

SOURCE: Office of Technology Assessment

ever, depend greatly on future profitability and,

therefore, on economic growth.

Second, projections of the four major sources

of industrial energy indicate that natural gas and

oil use will remain more or less steady, electricity

use will grow at about the same rate as total

product growth, and coal use will grow at twice

the rate of electricity. The projected, relatively

rapid growth of coal resuIts from the expectation

that virtually all new large industrial boilers will

be coal-fired. However, depending on the price

of natural gas and on whether it wiII compete on

the margin with residual oil or coal, the future

paths of oil and gas could be reversed. The less

expensive that gas is, relative to oil, the more likely it will be that existing oil heating will be converted to gas heating. Finally, electricity use will

keep pace with final product demand. Efficiency improvements in electric motors will be offset by increased use of electric drying. Depending on the price of purchased electricity and the

environmental restrictions on industrial cogeneration, a large share of this growing demand for

electricity may be supplied by onsite generation.

Figure 4 presents a comparison of energy use

in 199o and 2000 under the reference case and

under each policy option. It also presents a chart

showing energy saved in 1990 and 2000 (corn -
14 ● Industrial Energy u se

Figure 4.—industrial Sector Projections

Industrial sector fuel savings projections

1990 and 2000

Recovered Cogenerated

energy energy

I

1990 2000

Ref. No EITC Btu Cap. Ref. No EITC Btu Cap.

case ACRS tax avail. case ACRS tax avail.

Industrial sector fuel use projections

1990 and 2000

Natural Purchased Self-generated

gas Oil Coal electricity energy

[ I

1990 2000

Ref. No EITC Btu Cap. Ref. No EITC Btu Cap.

case ACRS tax avail. case ACRS tax avail.

SOURCE. Office of Technology Assessment
Ch. l—Summary and Findings • 15

pared to a 1976 base) under the reference case

and under each policy option. Following figure

4 is a discussion of each policy option, its impact,

and the energy projected to be used if it were

effected.

OPTION 1

Removal of Accelerated Depreciation

The ACRS can be a stimulus for investment,

provided industry is profitable. Under these circumstances, the ACRS wouId likely accelerate investment and, as a result, there would be a corresponding acceleration of energy efficiency improvements as old equipment is replaced. Consequently, removal of the ACRS wouId slow the

rate of improvement in energy efficiency, but

only if economic conditions improve so that substantial and sustained investment were relatively unconstrained. Currently, however, factors

such as high interest rates, high debt/equity

ratios, and low to moderate product demand,

are the factors limiting investment decisions.

Under these conditions, the absence or presence

of the ACRS will have little effect on industrial

energy efficiency.

Under a condition of restrained product

growth, the most significant shifts in energy use

arising from the removal of the ACRS would involve cogeneration and capital-intensive conservation technologies. OTA projects that market

penetration of these two categories of equipment

would be restricted if depreciation periods reverted to pre-ACRS scheduIes. A decrease i n cogeneration would cause a decline in the selfgeneration of electricity and in waste heat energy

recovery. Additional requirements for boiler-generated steam, to make up for the loss of steam

for cogeneration, would cause an increase in coal

use above that used in the reference case in each

of the four industries.

Finally, both the ACRS and the energy investment tax credits, discussed next, create situations

where third-party financing for tax shelter purposes can be attractive to individual investors

who wish to shelter personal income. Such situations can create opportunities for investments that

can lead to increased energy efficiency, particularly cogeneration. However, uncertainty

about the Internal Revenue Service’s approval for

these arrangements has prevented many of them

from occurring.

OPTION 2

Targeted Energy Investment Tax Credits

Energy investment tax credits (EITCs) at a 10-

percent level have little direct influence on capital allocation decisions in large American firms,

and thus have little influence on energy conservation. These credits appear to be too small to

exert any change on the returns on investment

of most projects or on the cash flow of a company. A firm has an overall objective of increasing productivity, and therefore profitability, when

it makes an investment in energy-using equipment. Energy is just one of many factors determining productivity of a given process, and a targeted incentive, such as the EITC, is diluted to

the degree energy efficiency must compete with

other factors of production for investment priorities.

In particular, the shift of 2 to 4 percentage

points in a typical 20-to 30-percent return on investment on a project brought about by a 10-percent EITC is usually not enough to cause a firm

to reorder the priorities of its capital allocation

plan. In some industries, OTA found that casestudy firms claimed only 1 percent of the dollar

amount for EITCs compared to that claimed for

the general investment tax credit, an indication

of the dilution that exists when targeting just one

of several factors of production compared to targeting the entire investment. In this connection,

tax credits applied to cogeneration are more effective, particularly to third parties whose only

objective is the production of cogeneration

equipment. Under these conditions, such credits

can make the difference between going ahead

with the investment or not.

A further barrier to the EITC is the decisionmaking structure of the firm. In some case-study firms,

OTA found that the technical staff who decide

on the engineering merits of a particular project

often have no authority or responsibility for the

financing considerations of the project. Such arrangements as third-party leasing and leveraged

capital purchases are the responsibility of the
16 ● Industrial Energy Use

financial offices. Therefore, the management staff

that has the final decision on whether or not to

undertake energy-related projects may not be the

staff that is aware of all the technical opportunities

that exist in an industrial facility. OTA’s survey

of firms in the energy-intensive industries indicates that economic calculations for individual

projects are carried out on the basis of IOO-percent equity financing, the rationale being that this

is the only way projects can be accurately compared. Only when considering the finances of the

entire corporation, such as its debt load and debtto-equity ratio, is leveraging (i.e, borrowing) considered.

In the steel industry, there is support for tax

credits, but only from the standpoint of cash flow.

That is, industry representatives agree that tax

credits do little to move energy projects ahead

of other possible investments; instead, they provide additional money from the energy projects

that are taken on (and would have been taken

on anyway), that can be used in general corporate operations. OTA projects that even if extending the EITC caused a slight increase in waste

energy recovery in the iron and steel industry,

the impact on the entire industry in terms of

overall increased energy efficiency would be negligible.

The response of the chemicals industry to EITCs

ranges from active support in one case, to neutral

indifference i n most cases, and corporate antipathy in a few others. Some chemical firms suggest that modest EITCs serve as indicators to the

manufacturing sector of the value the Government places on energy efficiency improvements.

However, it appears that a 10-percent EITC is less

effective than are existing and anticipated energy

prices in heightening corporate managers’ awareness about energy conservation. As with steel,

the impact of the modest 10-percent EITC on the

overall energy use in the chemicals industry is

projected to be negligible. For petroleum refining, the principal effect is projected to be a small

increase in cogeneration, reflecting the higher

leverage these credits have on energy production projects.

OTA has been unable to find any projects

throughout all the case-study firms where a decision to undertake a project hinged on gaining

a lo-percent tax credit. overall, the impact of

a 10-percent EITC on the total industrial sector

is judged to be minimal. For the EITC to be effective, it would have to be substantially increased, probably to above 40 percent.

OPTION 3

Tax on Premium Fuels

Taxes at a rate of $1 per million Btu on natural

gas and petroleum fuels—equivalent to about

a 25-percent tax, or to $6 per barrel of crude

oil—would change the fuel use mix in industry

and would cause energy efficiency to improve

slightly. In the case of coal, a premium fuels tax

would only add to an already large price differential, and therefore the economic incentive to

switch to coal would not be significantly increased. For electricity, the tax would be more

important in terms of relative prices, but the

limited existence of new technologies that efficiently use electricity to replace petroleum or

natural gas will constrain conversion to electricity

for several years.

Efficiency improvements that result from the

premium fuels tax would be a few percent greater

than those of the reference case. There are two

major reasons for this small increase. First, the

overall total cost of energy, despite a 25-percent

increase in the price of premium fuels, will be

considerably less than 25 percent, since gas and

oil account for about 60 percent of total industrial

fuel use. The net price increase will not greatly

accelerate the incentive industry already has to

invest in new process technology. Second, a tax

just on premium fuels would provide an incentive to switch fuels, which would not necessarily increase overall energy efficiency.

The tax would have different consequences for

each of the industries investigated. Within the

pulp and paper industry, a premium fuels tax

would accelerate the industry toward more energy self-sufficiency through use of biomass, and

would increase their use of coal. A number of

firms are considering replacing their oil-based,

steam-generating facilities with fuel-flexible or

coal-based ones. Such a tax would accelerate this
Ch. l—Summary and Findings • 17

change. A premium fuels tax is projected by OTA

to decrease natural gas consumption in the pulp

and paper industry by 5 to 10 percent. Much of

this decrease would result from a cutback in

cogeneration, with the result that the amount of

electricity purchased from utilities would increase.

Since coal is the dominant fuel in the steel industry, a premium fuels tax would have a small

impact. In 198?, the steel industry derived only

4 percent of its energy from petroleum sources,

and less than 25 percent from natural gas.

The petroleum refining industry might be affected by a premium fuel tax in two ways. First,

the tax would cause some reordering of energyrelated projects to positions ahead of other capital

projects. In particular, coal use for refinery operations would increase, while use of natural gas and

cogeneration would likely decrease. Second, the

fuel tax would undoubtedly decrease the industry’s earnings through a general decrease in demand for its products.

The domestic impact of a premium fuels tax

on the chemicals industry is less foreseeable. The

largest effect of a premium fuels tax on the chemicals industry wouId likely be the negative impact

on the ability of the chemicals industries to export products because of the resultant: 1 ) higher

prices on U.S.-produced goods in overseas markets; and 2) the increased cost advantage for foreign firms to sell their products, both in the

United States and throughout the world. OTA

projects the direct impact of a premium fuels tax

wouId be an increase in the use of coal and a

decrease in the use of natural gas. As with the

other industries, cogeneration, using natural gas,

wouId also decrease relative to the reference

case. Finally, the tax would probably cause a

slight reordering in project priorities.

OPTION 4

Lowered Interest Rates as a Surrogate for

Capital Availability

Corporations have a strong motivation to invest in new production equipment to maintain

or improve their market share. If these corporations also perceive energy prices to be high and

believe they will go higher, they have considerable incentive to make sure those investments increase energy efficiency. Therefore, low interest

rates affect energy efficiency to the extent that

lower rates may allow a company’s cash flow to

go further, its debt service to be less burdensome,

and its ability to take on more debt to increase.

In all cases, low interest rates increase the effective availability of capital and therefore allow

more projects to be undertaken. Even with an attractive interest rate, however, investment will be

restrained unless there is a perception of profitability and increased capacity utilization.

In this connection, if interest rates were to fall

considerably, automobile sales, house sales, and

the like would improve; capacity utilization rates

would rise; and corporate capital funding would

expand. However, even under these circumstances, especially for firms in the four energyintensive industries examined by OTA, some

companies cannot borrow funds because they

have already reached the debt ceiling imposed

by their desired bond rating. In these cases, the

size of corporate debt load, not the interest rate,

is the problem.

OTA finds that the availability of low-cost

capital would result in the most significant shifts

in total sector energy use from that of the reference case. In this situation capital-intensive

technologies, such as cogeneration and heat recovery devices, would be significantly more attractive and would find greater use. Coal use

would be greater because of increased penetration in both process and boiler applications. An

apparent anomaly would occur in natural gas use,

where the consumption figure for 2000 would actually be 3 percent higher than that in the reference case. This increase would be entirely attributable to the projected increased use of

natural gas in cogeneration. The impact of increased penetration of conservation technologies

and of greater numbers of energy-efficient processes in the low-capital-cost case would be a

decrease in total energy use that would equal a

full percentage-point drop in 1990 and half a percentage-point drop in 2000.

In the pulp and paper industry, OTA projects

a shift to more self-generated energy, with natural
18 • Industrial Energy Use

gas and oil use down, but cogeneration increas- capital were lowered. Low capital costs would

ing relative to the reference case. A low-interest permit a large cogeneration effort, which would

cost of capital should bring about a 5- to 10-per- increase natural gas use in this industry. Howcent decrease in energy intensity. ever, electricity demand from utilities would deThe chemicals industry is somewhat unique in crease, and the sum of energy used by the utilithat OTA projects for it a slight increase in energy ty and the chemicals industry would be lower.

used per unit of chemical output if the cost of

EFFECTS OF POLICY OPTIONS ON THE INDUSTRIAL SECTOR

For the entire industrial sector, under the conditions of the reference case, energy intensity

is projected to fall from its current level of approximately 51,000 Btu per dollar of industrial

output to a low of 33,000 Btu per dollar of output by 2000. The curve in figure 3 illustrates this

as well as the long-term nature of the investments

made by industry that would result in increased

energy efficiency. The rate of decline in energy

intensity will be less during the 1990’s than in the

1980’s. This decline should continue well past

2000 as the fraction of capital stock replaced by

new processes and process equipment continues

to grow. During this period, the use of coal

should increase from 5 percent of the total energy consumed to almost 18 percent as coal becomes a major fuel for process heat and steam

boilers. In addition, the amount of purchased

electricity should nearly double. This effect

should be balanced by decreases in the use of

natural gas, while use of petroleum-based fuels

should remain about the same.

OTA has found that investments in new technology are driven principally by judgments about

future profitability. This, in turn, is affected by increased product demand, productivity, and a

change in product mix. Where product demand

is expected to grow, as in the pulp and paper and

the chemicals industries, investment in expansion

wiII be large and, consequently, energy efficiency improvements will be extensive. Where large

changes in production technology are necessary

to avoid a substantial loss of market, as in the steel

industry, expansion of the industry will not occur,

but investment in new technologies will still be

large, The technologies in which steel will invest—primarily continuous casting and electric

arc minimills—will also provide enormous increases in energy efficiency. Finally, where product demand is declining but a product mix shift

will occur, as in the petroleum industry, investment will be needed to account for different

product slates. In the case of petroleum, the

changing characteristics of the crude oil feed stock

and shifts away from heavy fuel oil and gasoline

are the major factors. Again, efficiencies will

result, although to a lesser extent than with other

industries because investment will be less.

The policy options investigated by OTA do not

affect perceptions of profitability nearly as much

as do product mix shifts. The policy options are

primarily aimed at accelerating investment, once

a decision has been made, or targeting certain

aspects of that investment, in this case, energy.

They are most effective for those capital-intensive

items that are primarily concerned with energy,

such as cogeneration. Even here, however, the

attention to product demand and mix is so dominant that none of the options, with the exception of lower capital cost, changes the decision

pattern of manufacturing by a great amount.

Given a healthy economy and reasonable access

to capital, however, industry will make investments over the next few decades that will increase productivity and profitability and will

have a positive effect on energy efficiency. This

improvement can take place without additional

Federal incentives. The key is stable economic

growth, without which even much larger incentives than OTA has considered will not be of

much value.
The Industrial Sector:

and Inves

Growt

ment

h9

B

Chapter 2

Trends,

ehavior
.— — - .

,

The Industrial Sector . . . . . . . . . . . . . . ., . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Size and Growth of the lndustrial Sector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Industrial Productivity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Industrial Investment Decisionmaking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Uses of Capital ....*** ● .....,. ● . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Strategic Planning. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Factors That Influence lnvestment Decisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Levels of Decisionmaking. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Elements of a Strategic Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

TABLES

21

21

22

24

24

26

27

30

31

Table No.

d. Major Manufacturing lndustry Groups as Listed in the Standard Industrial

Classification Manual . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

5, Sensitivity Analysis of lnternal Rate of Return(lRR) Under Different Scenarios for

Computer Process Control System . . . . . . . . . . . . . . . . . . . 4 . . . . . . . . . . . . . . . . . . . . .

21

34

FIGURES

Figure No. . . . .

5. Output in the Industrial Sector ............. . . . . . . . . . . . . . . . . . . . . . . . . . .

6. . . . . . . . . . . . . . .

....,,

23

.

.
Chapter 2

The Industrial Sector: Growth, Trends,

and Investment Behavior

THE INDUSTRIAL SECTOR

As defined by the Department of Energy (DOE),

the industrial sector is essentially the goodsproducing part of the economy, It is largely concerned with obtaining raw materials—through extraction or through animal and plant husbandry–

and with the mechanical and chemical transformation of these materials and their derivatives.

The industrial sector contains agriculture (including forestry and fisheries), mining (including

oil and gas extraction), construction, and manufacturing. Manufacturing is the largest of the four

in dollar value of output and energy use.

These four components of the industrial sector correspond to the first four of eleven divisions

in the Standard Industrial Classification (SIC)

system. The SIC system defines industries and

groups of industries in accordance with the composition and structure of the economy. It covers

all economic activity. The Federal Government

and many other organizations use the SIC framework for collecting statistical data; many businesses use it to classify customers and suppliers.

Table 4 lists the SIC major manufacturing industry

groups.

Size and Growth of the Industrial Sector

The industrial sector accounts for nearly onethird of the gross national product (GNP). As

revealed in figure S, output (discounted for inflation) by the industrial sector has grown at a

respectable rate since the end of World War II.

Real industrial gross product increased 167 percent, or an average of 3 percent per year, between 1947 and 1980 (latest data available).

The industrial sector’s proportion of overall

U.S. economic activity has been decreasing, however, owing to two factors. First, service-type activities have grown more rapidly than goods-producing activities, a situation typical of highly

industrialized economies. Gross product originatTable 4.—Major Manufacturing Industry Groups as

Listed in the Standard Industrial Classification Manual

(1972 edition)

SIC code Major group

20. . . . . .

21 . . . . . .

22. . . . . .

23. . . . . .

24. . . . . .

25. . . . . .

26 a 

. . . . .

27. . . . . .

28 a 

. . . . .

29 a 

. . . . .

30. . . . . .

31 . . . . . .

32. . . . . .

33a 

. . . . .

34. . . . . .

35. . . . . .

36. . . . . .

37. . . . . .

38. . . . . .

39 . . . . . .

Food and kindred products

Tobacco manufactures

Textile mill products

Apparel and other textile productsb

Lumber and wood products

Furniture and fixtures

Paper and allied products

Printing, publishing, and allied industries

Chemicals and allied products

Petroleum refining

Rubber and miscellaneous plastics products

Leather and leather products

Stone, clay, glass, and concrete products

Primary metal industries

Fabricated metal products

Machinery, except electrical

Electrical and electronic machinery,

equipment, and supplies

Transportation equipment

Instruments and related productsb

Miscellaneous manufacturing industries

a

lndustries groups examined in detail by OTA study

bShortened title.

SOURCE: Standard Industrial Classification Manual, 1977 (Washington, D C

Office of Management and Budget, 1977).

ing* in nonindustrial divisions increased 243 percent between 1947 and 1980, or 3.8 percent per

year on average, compared with 3 percent on

average for the industrial sector. In 1980, gross

product originating in the industrial sector represented 31.6 percent of the real GNP, a drop

from 37.2 percent in 1947.

Second, among goods-producing activities,

there has been a historical shift toward higher

degrees of fabrication and more technologically

advanced products. For example, gross product

originating in the nonelectrical machinery, elec-

*Gross product originating in a division or Industry is that part

of the GNP attributable to the output of establishments in that division or Industry. It is the sum of the factor costs of production

(wages, salaries, profits, net Interest, and so forth) and nonfactor

costs, such as depreciation and Indirect business taxes,

21

99-199 IO - 83 - 3
22 . Industrial Energy Use

Figure 5.—Output in the Industrial Sector

(billions of 1972 dollars)

Other

$295

sect

Mining

$115

$11

1947

(Total economy $470)

tric and electronic equipment, and instrument

and related products industry groups, combined,

accounted for more than 6 percent of the GNP

in 1981, compared to about 3.5 percent in the

mid-l950’s. in contrast, the combined share of

the GNP accounted for by the primary metals and

fabricated metal products industry groups fell

from over 4.5 percent to less than 3 percent for

the same period. *

Both the faster output growth of nonindustrial

divisions and the shift to higher degrees of fabrication and more technologically advanced products

have an important bearing on the level of energy

use in relation to output in the industrial sector.

Others

$533

Construct

D $50

on

Mining

$15

1983

(Total economy $833)

Agriculture

$43

Construction

I $53

Ot

$1

Mining

$23

1981

(Total economy $1,482)

SOURCE: U.S. Department of Commerce, Bureau of Economic Analyses

The industrial sector employs about 30 million

people, or about 30 percent of the total employment in the U.S. economy (see fig. 6). This percentage is slightly higher (31 percent) when employment is figured according to the full-time

equivalent of workers rather than by the number

of full- and part-time workers. There are relatively

more part-time workers in the nonindustrial divisions, particularly in trade and services. (Unpaid

family workers, mostly in farming, are not included in this analysis. ) Employment in the industrial sector has increased about 15 percent

since 1947, while employment in the rest of the

economy has more than doubled. Despite relatively low nominal wages in agriculture, employee wages in the industrial sector as a whole are

about 1s percent higher than those in the economy as a whole.

Industrial Productivity

Industrial labor productivity, as measured by

the amount of output produced per hour of labor

used, has dramatically increased since World

War II. Production per person-hour in manufacturing (which accounts for three-fourths of industrial sector output) grew at an average rate of

2.6 percent per year between 1947 and 1981, In

*Data on gross product originating by detailed industry group

may contain considerable errors and are not published by the estimating agency–the Bureau of Economic Analysis (BEA) of the Department of Commerce. BEA strongly recommends that the figures

be used with caution.
Ch. 2— The Industrial Sector Growth, Trends, and Investment Behavior • 23

Ot

31

Figure 6.—Distribution of Employment in the

Industrial Sector

her

.2

sec

1.0 Manufacturing

15,4

1947

(Total employment 57.3 million)

Other

41.3

Mining

0.6

1963

(Total employment 66.3 million)

Agr

4.1

Con

3.6

fact

ture

ction

icultu

struc

uring

Mining

1.1

1981

(Total employment 96.0 million)

re

tion

ture

struction

ing

comparison, labor productivity in the private nonfarm economy as a whole increased 2.1 percent

per year on average during the same period. This

contrast reflects the more rapid gains in labor productivity in goods production than in the production of services. Part of the substantial rise in labor

productivity in the industrial sector has come

about through the use of more energy. Yet, at

the same time, the other factors contributing to

higher labor productivity–improvements and/or

increases in technology, physical capital, and the

skills and education of the labor force—have also

combined to actually decrease the amount of

energy used per unit of output.

SOURCE U S Department of Commerce, Bureau of Economic Analysts
24 . Industrial Energy Use

INDUSTRIAL INVESTMENT DECISIONMAKING

The significance of industrial energy demand

in overall U.S. energy use has focused considerable attention on means of encouraging

more rapid improvements in industrial energy

productivity. A business decision to invest in new

plant and equipment or in retrofits of old equipment for the purpose of cutting energy use (and

thereby reducing costs) is made, however, in the

context of many other competing criteria. An understanding of this decision making process is an

important goal of this study.

The fiduciary duties and responsibilities of

management are well known. In a modern society these responsibilities can be said to range from

protecting shareholders’ interests to assuring

employee welfare and safeguarding the environment. These fiduciary obligations play a major

role in the company’s decision making process,

ensuring that investments are prudent and that

they protect the company’s assets.

A well-managed company that wishes to expand its operations has many avenues open to

it for raising capital and does not have to rely entirely on the current profits generated. These

avenues range from selling company stock, to issuing interest-bearing paper—i e., debentures, to

borrowing the required amount of money and

paying interest to a lending institution.

Management responsibilities in these areas are

directed at ensuring that debts arising from borrowing or the issuance of stock do not overdilute

or undermine the asset value of the company.

It is this fiduciary responsibility, with its inherent

emphasis on prudent management, that gives rise

to financial planning and investment policies that

are incorporated into a strategic plan. Decisions

regarding all investments, including those related

to energy, are made within this area of strategic

planning.

Uses of Capital

Corporate funds can be used to pay the debt

and debt service on existing loans; to pay dividends to stockholders, for such payments often

serve to keep up the price of the stock so more

stock can be issued; and to pay for the working

capitaI—i. e., everything from the company’s inventory to the cost of raw materials. For many

companies, working capital is the largest dollar

expenditure but is allocated only after the first

three items have been satisfied.

Once a company knows the size of its capital

pool, it must decide how to allocate it. Certain

projects are considered mandatory–e.g., pollution control equipment, equipment required for

health and safety, and projects agreed to in collective bargaining. Also, some capital projects,

especially those in the capacity expansion category, obligate a company to spend in certain

ways to support a major project. Once a decision has been made to build a new pulpmill or

a new blast furnace, completing a number of

projects related to that decision becomes mandatory. Such things as purchasing additional

transportation equipment for the new product

would be in this category.

plants in the primary manufacturing industries

are often very large. To take advantage of critical

economies of scale, major expansion of industrial

capacity in these plants involves large blocks of

financial resources and delayed returns on investment during lengthy construction periods. To justify such investments, project lifetimes must be

predictably long term. Such long-term forecasts

are exceedingly difficult to make, especially during periods of economic instability. Consequently, at present, primary manufacturers requiring

long-term investment commitments involve greater apparent risks than do industries that offer

shorter term investment opportunities.

After all mandatory allocations are made, a

company is left with its discretionary capital pool

that is subjected to the corporation’s strategic

planning process for ranking investments. In

some corporations, investment decision making

is a very formal process. The company invests in

only its most productive product lines and plants.

In other firms, decisionmaking seems less formalized, but still subject to the perceptions of

managers on growth potential of a product, market and technological competition, and use of
Ch. 2—The Industrial Sector: Growth, Trends, and Investment Behavior ● 2 5

capital, labor, and materials. I n no case has OTA

identified companies that accord energy projects

special status. All firms regard energy efficiency

as one more item in which they could invest and

not as a series of projects that differ from other

potential investments. The economic incentive

to save energy because of its high cost is counterbalanced by high capital and labor costs and increasingly costly raw materials.

To be effective in the marketplace, management must have a strategic plan. The approval

process in developing the plan and its projects

tends to be complex and the project analysis, exhaustive. Technical decisions tend to be separate

from and subservient to financial decisions. The

corporate engineering staff performs detailed

technical analysis, estimating such factors as construction costs, potential energy, labor or material

savings, and project lifetime. A return on investment is then calculated. I n multi plant firms, proposals for capital projects are then submitted to

the plant manager, who may approve certain

areas and not others. This package is then sent

on to the corporate staff for consideration with

proposals from other plants. This capital fund request summary would be reviewed by senior corporate management, and only at this time would

funding source, tax credits, and the like be discussed.

As shown previously in table 1 energy efficiency improvements are generally classified into four

categories: housekeeping, equipment retrofit,

new plant construction or capacity replacement,

and product shift.

Housekeeping

Housekeeping refers to the substitution of labor

and management inputs for energy. It includes:

1 ) closer monitoring of process streams and

greater coordination of products in process in

order to minimize delays and reject rates, 2) more

frequent equipment repairs to increase average

energy efficiencies, and 3) improved job skill

training and motivation to minimize human errors. Because many of these alternatives are not

expensive and involve a very large return for little effort, they are often the first actions taken by

a company. The consensus of energy managers

and corporate investment analysts i n the four industries studied by OTA is that most firms have

done their housekeeping–that those things that

can be readily adjusted, insulated, turned down,

or turned off, have been.

Equipment Retrofit

Most existing equipment was installed when

energy costs were expected to be much lower

than they are today. Replacement with new

equipment would offer the greatest improvement

in energy efficiency and the greatest reduction

in fuel costs (via fuel switching). However, since

replacement is most expensive and a great deal

of capital in place may not have been amortized,

replacement would be tantamount to accepting

large, lump-sum losses. The alternative is to

retrofit existing equipment—e. g., by adding pipe

insulation, combustion controls, more efficient

motors, and heat exchangers to heaters and

boilers in order to achieve their maximum design

efficiencies; by adding computer controls to process streams in order to minimize deviations from

optimum temperatures and pressures; and by

adding or replacing a muItitude of other process

components whenever such installations do not

significantly increase downtime.

Most important energy-saving retrofit alternatives involve well-proven technology. Several

firms contacted used a lower hurdle rate for

energy conservation projects because they were

considered to be of low technical risk. On the

other hand, while there are a multitude of retrofit

project alternatives at any major industrial facility, the actual energy savings for a particular project may be severely constrained, or the investment outlays may be excessively large, because

of the existing plant configuration.

New Plant Construction or

Capacity Replacement

The most costly investment strategy (at least in

initial capital outlay) is to build entirely new

facilities that embody the latest energy-efficient

technology or any technology that lowers cost

and improves product quality. This alternative is

frequently the most attractive to growing industries. However, in the four subject industries, this
26 ● Industrial Energy Use

choice is less attractive because a new plant must

replace an old plant, with all the attendant losses

of jobs, established ways of doing things, and

even capital writeoffs if the old plant has not been

fully depreciated. Curiously, new construction is

attractive in the steel industry, which is experiencing the greatest overall decline in total domestic output. It occurs there at the initiative of relatively new minim ill firms that reprocess scrap

metal. These new firms are growing at the expense of older, established steelmaker.

Product Shift

Product shifts are unique to a given corporation and quite idiosyncratic. Whether the managers of a company choose to invest in maintaining their existing capital stock, add new capacity, or invest in entirely new product lines depends

on how those managers view their industry. Parts

of an industry may be more susceptible to competition than others, or have higher costs or lower

returns compared to other product lines in which

a firm could choose to invest.

Of all the factors that enter into a firm’s decision to invest, those that influence the two

categories of new capacity or product switching

are the most difficult about which to generalize.

The managers of one firm may decide to stay with

a product line or with an industry, while another

group of managers may decide to expand to another product line or industry. Once a firm makes

this type of evaluation, it locks itself into a particular kind of capital spending pattern. For instance, a paper firm that decides to build a new

pulpmill commits itself to 3 to 5 years of capital

expenditures before a single dollar in increased

sales or increased net profits attributable to that

investment is realized. This situation dramatically affects the size of the capital pool available for

other projects.

STRATEGIC PLANNING

There are as many strategic plans as there are

corporations because each corporation has its

own procedures for strategic planning. For the

purpose of this report, simple generalizations are

given to illustrate commonalities.

Strategic plans tend to have a framework of 5

to 10 years, but are revised annually. Often, the

chief executive officer devotes most of his attention to strategic planning. Such plans invariably

identify the markets and the products that are

most important to the company and direct management’s attention to strengthening the most

promising of these.

In a simplified strategic plan, business sectors

are ranked, and often individual factories within

a corporation are ranked. Most of management’s

interest, and most of the money for new investment, goes into highly ranked factories in highly

ranked business sectors. A facility ranked low on

both scales has little hope of acquiring new investment capital.

Strategic plans are based primarily on the assumption that a firm is operating in a normal

business environment and is not prone to drastic

fluctuations in commodity and raw material

prices, labor, interest rates, or other precipitous

changes that cannot be anticipated. Therefore,

in order for the strategic plan to work, the environment must be relatively stable. Although

managements go to great pains to attempt to

forecast disturbances in a worldwide environment, where factors ranging from political unrest

to large changes in government policies take

place, sometimes firms are surprised by unforeseen events and strategic plans break down. For

example, overnight, the U.S. car industry became

extremely vulnerable to the Japanese small-car

import, a situation almost entirely due to events

that took place in Iran in 1979 and to the subsequent 300- to 40()-percent increase in world oil

prices. The American car industry obviously

could not have planned in the mid-l 970’s for the

revolution in Iran.

Similarly, the whole infrastructure of the housing industry, from the basic forest products industry to the savings and loan bank mechanisms

that finance it, has matured and grown on the

basis of relatively low interest rates. The dramatic

rise in interest rates in the late 1970’s caused vast
Ch. 2— The Industrial Sector: Growth, Trends, and Investment Behavior • 27

dislocations to the market that could not possibly

have been foreseen by the strategic planner of

a forest products company planting trees 20 years

ago, or by a mortgage broker planning his loan

strategies in the 1960’s.

Factors That Influence

Investment Decisions

Fiduciary responsibilities strongly influence

management thinking. The first and possibly the

most overriding factor when dealing with investments is management confidence. In this context,

the word “confidence” does not describe management’s own view of its abilities, but describes

instead management’s perspective of all the relevant factors that make up and influence its

enterprise.

Management must be confident, for example,

that its investments are going to bear fruit. it is

more likely to invest when it is confident that the

market for its company’s products is growing, or

that the company can capture a larger share of

the market, or that the general economic climate

is improving. This confidence has a major impact

on how management views the risks associated

with an investment. As the confidence factor

grows, the impact of a risk factor is minimized.

Furthermore, management must demonstrate

to the financial marketplace that the company

is financially sound and that its investment

strategies and policies are well thought out. [t is

not uncommon for the chief executive officer

and/or his designated appointees to expend time

and effort explaining these plans and strategies,

not only to their immediate bankers, but also to

Wall Street analysts, brokerage houses, and

others in order to assure the decision makers in

capital markets that money raised and investments made are prudently managed.

The four industries examined for this report

identified five factors that affect their strategic

decisionmaking: product demand, competition,

cost of capital and size of capital pool, cost of

materials and labor, and general economic environment and Government policy.

Product Demand

Demand for primary industrial commodities depends on the general level of economic activity–

i.e., the GNP. When the economy is growing

steadily and existing capacity is fully operating,

profits that depend critically on capacity factors

are generally high, investment capital is generated

internally, and new energy technologies can be

adopted as soon as they become profitable. On

the other hand, when the economy is stagnant

or depressed, low-capacity utilization leads to low

profits and curtailed investment. So even if energy-related profits have calculated a return on

investment well in excess of normal corporate

hurdle rates, they may not be implemented.

The generally accepted opinion seems to be

that market opportunities for U.S. suppliers of

basic industrial commodities are below average.

Despite many uncertainties, analysis suggests that

the advanced industrial economy is gradually saturating markets for durable manufactures and

construction and moving into higher and softer

areas of technology, such as semiconductorbased computation and communication. For example, in the steel and petroleum refining industries, more production capacity is now in

place than is required for the next 5 years. In

1982, the steel industry used less than half its

capacity. As long as the economy is sluggish from

high interest rates, unemployment, and inflation,

the steel industry will not use much of that excess production capability. In addition, with the

recent U.S. recession, fewer durable goods, such

as refrigerators and washing machines, are being sold, and some goods that are sold tend to

be made of less steel.

The overcapacity (almost 30 percent) of petroleum refining in the United States, is due in part

to the high market price of the fuels produced–

which has in turn led to fuel conservation, the

use of more fuel-efficient autos, and the switch

from fuel oil to natural gas in residential heating.

In both the steel and petroleum refining industries, then, it is clear that major new capacity expansions will not be undertaken. The existing capacity, although not as efficient as it could be,
——

28 ● Industrial Energy u se

will provide sufficient steel, petroleum, and

associated products to meet anticipated growth.

In the paper industry, demand is forecasted to

grow at 2.5 percent per year, given a GNP growth

rate of about the same percentage. This anticipated growth is sufficient to encourage

managers to plan for new capacity, although it

would not be the only factor they would consider.

The chemicals industry expects product demand growth that exceeds that of paper and a

continued ability to export products outside the

United States. Because the chemicals industry has

more product flexibility than do the other industries discussed so far, it can be expected to

add new capacity on the basis of anticipated market growth, although, again, this would not be

the only factor considered.

Competition

Perception of competition also exerts an influence on investment decisions. There are two

types of competition: a technological one within

an industry and market competition, both local

and foreign. Although it is beyond the scope of

this report to examine the competitive quality of

products made by the four subject industries, the

report does identify within each of the industryspecific chapters, new technologies in which

these industries will most likely invest in the next

two decades to help maintain or improve their

competitive positions.

Two of the subject industries face severe market

competition from foreign companies. The steel

industry has initiated suits with the International

Trade Commission, alleging that foreign producers make steel that is subsidized by their respective state governments. The “subsidized” steel

is then sold in the United States at prices lower

than that of domestic steel. The U.S. producers

feel that an unfair advantage is accorded East

Asian and Western European manufacturers by

their governments in order to sell steel in the U.S.

market. The reasons for the alleged subsidization

seem clear: the desire for high employment and

the need to develop or maintain a heavy industrial base by each country. Such subsidization

raises major questions about U.S. dependence

on foreign sources for basic industrial materials.

In the chemicals industry, the United States

faces external competition, but of a different type.

Chemical manufacturers in the United States already have a large share of the overseas chemicals market. Foreign producers claim that the

United States subsidizes chemicals production by

artificially keeping feedstock (specifically, natural

gas) prices low through controlled prices. As

natural gas prices are decontrolled in the United

States, the $12 billion balance-of-payments surplus generated by the chemicals industry in 1981

will be reduced as foreign producers take away

foreign markets formerly dominated by the

United States.

The paper industry does not appear to face imminent foreign market competition, except perhaps from Canada. Petroleum refining should also

be free of competition. In both cases, transportation costs should limit intrusion by foreign

producers.

In generaI, exports of primary industrial commodities are unlikely to sustain U.S. industry

growth because developing nations typically emphasize relatively low-technology industries first,

making such commodities highly competitive in

international trade.

Cost of Capital and Size of Capital Pool

Money to be used for capital expenditures can

arise from several different sources. The major

sources are debt, equity, and retained earnings.

Corporation managers view their money as a resource that could be invested in any of the four

project categories (e.g., equipment retrofits) or

in some type of revenue-earning account. Any

returns from capital investment, in theory, must

exceed the interest return of possible bank deposits. The more funds a corporation must borrow from commercial sources to finance its capital projects, the more profitable a project must

be.

Corporations derive their funds for capital from

a number of internal and external sources. Internal sources include: retained earnings or money
Ch. 2—The Industrial Sector: Growth, Trends, and Investment Behavior ● 2 9

remaining after the costs of production are paid,

the delay in paying corporate taxes, and the

claiming of tax credits. External sources include

borrowing money and paying interest, or equity, and selling ownership (stock) in the company.

Many firms try to mantain a specific debt-equity

ratio in order to avail themselves of particuIar

financial sources. If a firm is already at or near

its desired debt-equity limit (usually about 35 percent), borrowing ability can be severely constrained. The only way to alleviate this problem

would be to issue more stock. However, if the

company cannot purchase the stock at an adequate price, because of poor returns, the size of

the company capital pool cannot be expanded.

In the steel industry, with its low capital return

and its need to finance from debt sources, high

interest costs of capital restrict the ability to invest in energy saving or any other kinds of projects. The other three industries also find themselves constrained by the cost of capital, but for

them it is but one of the capital allocation decision factors.

interest rates also impact these industries in

other ways. When interest rates are high, consumer sales are restricted; then, consumer goods

that use products from the chemicals, steel, and

wood products industries do not sell rapidly.

Thus, firms may not invest in many technologies

that would save energy, either because they do

not expect sales volumes large enough to return

a profit on the new outlays or because they simply cannot raise the money, no matter how profitable an investment might be. High interest rates

also give firms that have traditionally produced

primary commodities at least a strong positive incentive to diversify. Diversification can occur by

vertical integration downstream into more finished products that generally offer larger profit

margins. Also, a firm might engage in an entirely

different industry by acquiring another company.

Cost of Materials and Labor

Individual firms in particular industries compete

with one another to purchase raw materials and

energy at the lowest levels of cost possible, a goal

that affects both day-to-day operations and strategic planning. Management can compete by investing in projects that minimize the cost of production by minimizing labor or by substituting

one material for another (or using it more efficiently). process controls and automation can offer a company significant cost savings through improved quality control–i,e., more efficient use

of material—and labor savings. Such changes

place more demand on corporation managers to

use their employees more productively and often

require employee retraining.

From a raw materials standpoint, apart from the

price of the raw materials, large and mature companies in the industries discussed also see security

of supply as a major problem that couId affect

both their fiduciary responsibilities and their competitiveness in the marketplace. If, for example,

during the time of a fuel embargo, a company

has to tell its customers that it cannot supply them

because its plants are shut down from lack of

energy, it might very well lose those customers

forever to a company that can supply them.

Therefore, it is not unusual for firms to couple

these two factors, price and security of supply,

into one strategic decision. For instance, a steel

company may choose to own iron ore and coal

resources or a paper products company may

choose to own forests and timberland.

General Economic Environment and

Government Policy

Obviously, management is concerned not only

with the immediate environment within its own

company and industry, but also within the general economic environment. In the large, multinational firms, this concern has both national and

international ramifications. The factors that affect

economic outlook are therefore very important

to management and vitally affect investment decisions, including the obvious criteria —i. e., interest

rates, inflation rates, GNP, and the like.

In the larger corporations, such factors could

include international trade agreements, Eurodollar and Japanese interest rates, and international labor rates. It must also be considered that

the international competitor could, in fact, be

government owned and subsidized in terms of

interest rates, research and developing backing,

subsidized pricing of the product, and so forth.
. —

30 ● Industrial Energy Use

Such backing may be carried out in the “national

interest” to the extent that the fiduciary responsibility to operate the company at a profit is greatly diminished.

Government regulations or taxes that unnaturally tip the balance of the marketplace are considered extremely detrimental by industry. For example, if a Btu tax were applied to oil, the nonintegrated papermill would be at a severe disadvantage with an integrated papermill because the

integrated papermill can use wood waste, black

liquor, and other materials to meet its fuel requirements. These resources are unavailable to

the nonintegrated mill.

Conversely, pollution legislation that applies

equally to all companies can be viewed by industry as a pass-through that does not alter the

company’s competitive position. However, in today’s marketplace, pollution legislation that is applied in the United States, but not equally applied

in other industrialized countries, could be considered detrimental to U.S. manufacturers because it upsets the competition balance of the

worldwide marketplace.

Finally, the perception of Government policy

affects strategic planning. Changing policies, indefinite policies, and policies whose provisions

take a long time to effect can play havoc with

an industry’s strategic planning. For instance, one

problem with energy investment tax credits is that

it often takes 6 months to 1 year to determine

if a project will qualify for the credit. The suggestion heard time and again in case study visits

and workshops was to avoid changing policy.

With respect to natural gas deregulation, managers said that, by far, the best policy for the

Government to pursue was to fix a definite date

for deregulation (as has been done) and then to

allow sufficient time for the corporation to react

to the anticipated price increase.

Levels of Decisionmaking

The responsibility for assessing and minimizing risks falls on all levels throughout the corporation. In most major corporations, those responsibilities are clearly defined. Examples of the provinces of risk decision making are given below.

However, it must be emphasized that each individual corporation would have its own criteria

and decision making levels that may be different

from those given.

Senior Management

Ensuring the security of energy, material, and

labor supplies in a strategic plan is a pivotal aspect

of risk reduction for senior management. For example, often the site of a new plant is chosen

because of the perception that it will ensure a

secure labor or materials supply. In addition, efforts invested in better employee/management relations make a major contribution to risk minimization by avoiding potential strikes in which

losses of both profits and wages would be high.

Upper/Middle Management

Upper and middle management play an extremely detailed and comprehensive role in risk

management. At this level proposed investments

that are compatible with the corporation’s strategic plan are reviewed and selected for approval

before the commitment of funds is made.

Innovations in new energy-saving processes

face a series of hurdles pertaining to risk. One

of the greatest of these is skepticism about

whether they will actually work as well as they

are supposed to. Most companies are reluctant

to be the first to try out a new idea. * The manager

who accepts an unproven innovation and commits his production line to it reaches for a possible incremental gain on the upside, but may face

a total shutdown on the downside. The manager

of another mill, who waits to see how his competitor fares, suffers none of the costs of debugging a new idea and generally loses less than a

year in catching up if the new idea works. In fastmoving fields like genetics, pharmaceuticals, and

computers, a year can be devastating; but in

paper, steel, or energy-intensive chemicals, it

makes little difference.

*This reluctance on the part of business leaders was recognized

by the Energy Research and Development Administration (predecessor to DOE) in 1976. Subsequently, the Office of Industrial Programs within DOE focused its industrial energy conservation program on full-scale demonstrations of new technologies.
Ch. 2— The Industrial Sector: Growth, Trends, and Investment Behavior . 31

Plant Management

The day-to-day operations of risk management

and risk planning that affect plant production are

usually dealt with by plant management at the

corporate and plant engineering levels. In a multiproduct, multi plant company, individual managers know their performance is graded, among

other criteria, on the quantity and quality of products produced. An innovation installed on one

machine, even when parallel machines are functioning properly, increases a manager’s perceived

risk, Vendors of process equipment compete not

only on price, but also with guarantees of minimum installation time and debugging periods.

Furthermore, certain key components (e.g., the

recovery boiler in a papermill) have no backup

unit, so that something as simple as retrofitting

a new combustion sensor could be seen as carrying enormous risk because it jeopardizes the

entire unit.

Even in negotiating a new contract with a supplier, the risk of delivery failures and the penalties

for such failures are of great concern. To cushion

against such risks, some companies hold inventories of raw materials many times the size of inventories of finished products held in the warehouse. The magnitude of possible losses owing

to downtime (labor, idle capital, and so forth)

warrants this precaution.

Industry managers are also sensitized to regulatory pitfalls that may accompany new technology. A new process or a variation of an old process may come under new Occupational Safety

and Health Administration rules, and a new combustion method or new byproduct may require

an Environmental Impact Statement. In the recent history of major industries, regulatory requirements have delayed the implementation of

certain innovations and cut into profits.

A new technology can best penetrate an industry, therefore, if it has established a record of

simple, safe, and rapid installation and startup.

Also if the manager can establish checkpoints at

which to decide whether to continue with the

project, the project stands a better chance of being accepted quickly. The history of process control equipment is an example of this. The steps

toward computer control were first to install

stand-alone gauges (in the 1950’s), then to add

simple analog control systems requiring constant

surveillance (in the 1960’s), and finally, in the

1970’s and 1980’s, to introduce fully computerized production lines, including robotics, to replace or augment manual labor.

Elements of a Strategic Plan

The strategic plan that gives rise to investment

must, of necessity, incorporate sophisticated

methodologies and techniques to analyze risks

and attempt to minimize them. Some of these

techniques follow.

Time Concepts Within the Strategic Plan

Time considerations not only apply to risk perception, they also play a major role in every facet

of the business. Making payroll, paying critical

suppliers, repairing critical items of a plant are

short-term considerations that fall under the

fiduciary responsibility of management. A company must be able to generate the cash to meet

its obligations. Obviously, in times when interest

rates are high, borrowing money for these purposes can be a critical strain on a company’s resources, particularly if sales and profit margins

are being eroded. Thus, under some circumstances, even if an excellent long-term investment

opportunity arises, it must defer to the short-term

obligation. Many energy conservation opportunities are either deferred or not even considered, for just this reason.

A short-term consideration at another level

would be the delaying of investments intended

to increase future market shares through the

modernization and/or expansion of capacity. This

decision can have a critical effect on energy efficiency, for the introduction of new technologies

associated with modernization and/or increasing

capacity invariably lead to increased energy

efficiency.

An example of an intermediate-term consideration would be the investment in dual-fired boiler

capabilities to protect against and minimize the

risks associated with fuel supply interruptions and

resultant plant closures. This type of investment

wouId not have a calcuIable return, for the plant
32 ● Industrial Energy Use

may never be closed. It is, instead, insurance

undertaken purely to meet fiduciary responsibility

and reduce risk. Of course, if an interruption does

take place, the investment becomes very worthwhile indeed.

Finally, an example of a long-term consideration would be a forest products company buying woodlands or planting trees, or a steel company purchasing iron ore mines and ore-bearing

rights. Again, there is a fiduciary responsibility

associated with this type of investment, together

with the minimization of risk that comes from

protecting raw material supplies into the future.

However, such long-term investments would take

second place to short-term considerations associated with cash flow.

Investment Levels Within the Strategic Plan

Investments can be considered as falling into

two broad levels of priorities. In the first level are

short-term demands that enable the company to

meet its fiduciary responsibilities on a day-to-day

basis, for example, meeting payroll. Although

these investments can be categorized as “mandatory, “ decisions associated with them are still

very much part of the strategic plan and involve

discrete management judgments. For example,

a decision to reduce a skilled labor force or accept a small market share by shedding marginal

operations in order to protect cash flow in the

short term could seriously jeopardize the company’s growth in the future if its market position

improved. The company may not be able to recapture easily the skilled labor force or the market

share it lost.

The second level of investments, categorized

as “discretionary,” are made after mandatory investments. They are chosen from a list of alternatives and are subjected to various criteria of

evaluation, from technical scrutiny to rigorous

financial analysis. Investments in energy conservation fall into this category when they are part

of the overall strategic plan, most often under the

discretionary investments associated with cost

cutting.

The importance of cost cutting within a plan

depends on the overall economic climate and

health of the company. In general, cost cutting

that does not involve capital outlay is always

welcome. Energy conservation that often falls in

the subcategory of cost cutting is housekeeping.

Cost cutting is usually a very low, if not the

lowest, level of priority within the overall plan,

particularly when capital outlays are involved.

Therefore, Government tax policies–e.g., directed energy investment tax credits that attempt

to influence the outcome of industrial investment

analysis—only come into play at the lowest level

of corporate strategy. The major decisions associated with an investment are based on other aspects which, from management’s point of view,

are infinitely more important.

Financial Analysis

All corporations have extremely sophisticated

methods for carrying out financial analyses, using

certain accepted financial and accounting practices. Each corporation has its own criteria that

reflect its basic management style and philosophy. Once a decision to proceed on an investment has been made, a detailed investment analysis, including returns on investment, discounted

cash flow, and tax and depreciation implications

is undertaken. Although these implications were

considered in the formative stages of planning,

their specific importance was not quantified in

detail until the decision to proceed was made.

However, and most important, these implications

are not expected to make any material difference

to the decision. For example, an energy tax credit

on a very small percentage of a multimillion dollar

investment would have negligible impact on the

decision to undertake the project. A change in

depreciation rates that alters cash flow would play

a larger role, but again would be unlikely to

reverse the decision. However, a large increase

in interest rates or a perceived downturn in the

market could abort the project immediately.

Any capital investment requires money to be

spent at the front and before any revenue stream

can be generated from the investment. Because

these investments generate returns over long

periods of time, methodologies have been developed to calculate accurately the returns on investment, from a project’s conception to the end

of its useful life. These methodologies consider
Ch. 2—The Industrial Sector: Growth, Trends, and Investment Behavior • 33

inflation rates, depreciation rates, cost of money,

and so forth, and produce calculations that attempt to predict cash flow and the returns on investment over the lifetime of the project.

Methodologies of varying complexity are often

used within a corporation when evaluating investments. These methodologies calculate such

parameters as simple payback period, net present value, internal rate of return, equivalent rate

of return, and profitability index. In choosing

which parameter to calculate, corporations reflect

both the management style and accounting practices that are compatible with the operation of

their business. Each parameter is described briefly

below.

SIMPLE PAYBACK PERIOD

The simplest estimate of profitability is obtained

by taking the initial capital cost and dividing it

by the positive cash flow in the first full year of

operation. For typical projects, this gives a number between 1 and 10, which is called the “simple payback period.” For example, a $1.2 million

investment which returns $400,000 per year

“pays back” the original investment in 3 years.

NET PRESENT VALUE

When the sophistication of the analysis is increased, two steps are taken. First, the impact of

depreciation and taxes are included because

after-tax dollars are important factors in determining corporate cash flow. Second, future streams

of income are discounted to recognize the greater

value of a present over a future dollar.

The effect of the resultant net present value

calculation is to produce a number that reflects

the dollar value of the specific project to a company, compared to the value of the money used

to undertake that same project if that money were

invested.

INTERNAL RATE OF RETURN

For most projects where the cash flow is negative at first and positive later, there exists a discount or interest rate such that net present value

is zero—e.g., such that the initial capital outlays

exactly balance the later profits, The interest rate

at that point, called the “internal rate of return”

(lRR), can be looked on as the interest rate at

which money is returned to the company for the

dollars invested in the capital project.

PROFITABILITY INDEX

One indication of the profitability of a project

is made by comparing the capital outlay of money

to a project and the revenue stream of money

from a project, discounted back to the present.

The ratio of the two dollar values is the profitability index.

Comparison of Methods

These sophisticated analysis techniques and the

wide variety of capital formation opportunities

open to industry are designed both to assess accurately the profitability of the investments and

to facilitate their financing. By varying the different parameters, some of the risk involved can

be assessed, that is, various interest rates or inflation rates could be examined in order to ascertain the potential vulnerability of the investments

to changes in external factors.

The choice of methods used to calculate the

value of a capital investment reflects the management style of and within a corporation. It is not

unusual for the energy engineering department

to assess a project in simple payback terms while

the finance department takes the engineering calculations and applies the more sophisticated techniques used by the corporation.

For the purposes of this study, OTA has selected the IRR method for most of its calculations.

IRR has the advantage that it lets each project

stand alone, unencumbered by the choice of corporate discount rate within any firm. The industry-specific and general investment opportunities

discussed in later chapters are evaluated quantitatively using the IRR. The impact of the legislative options on investment decisions concerning specific projects can be seen quite well using

the IRR.

The financial assessment is not the final assessment undertaken, however, particularly where

major projects are concerned. Sensitivity analysis,

which takes into account all other factors—from

R&D to final market potential—can also have

major impacts on the success of investments,
34 . Industrial Energy Use

Sensitivity Analysis and Its Effects

A number of hypothetical investments were

carried out by OTA and shown to industrial managers at case study firms in each of the four industries. Upon seeing the results, they cautioned

OTA not to take return on investment calculations too seriously. The fact that an initial

10-percent tax credit changed the after-tax IRR

by 6 percentage points was not considered persuasive enough to induce investment in a project.

In order to understand this position more fully,

further calculations were carried out, incorporating parameters that couId be considered uncontrollable by a corporation. This simple sensitivity analysis was applied to a process control system

ing:

1.

2.

3.

4.

5.

project using five simple variations, includnegotiating a small change in the vendor’s

centract,

incurring unexpected repair costs equivalent

to 10 percent of the investment,

experiencing a recession during the lifetime

of the project,

achieving a performance rate of only 90 percent of what was expected, and

having prices held down by competition, as

shown in table 5.

The results of these analyses, compared to the

effect of a 10-percent energy investment tax credTable 5.—Sensitivity Analysis of Internal Rate of

Return (IRR) Under Different Scenariosa

for Computer Process Control System

Condition After-tax IRR

1. Base Case. . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.4

2. Vendor escalates service contract . . . . . . . 15.3

3. Unexpected repair cost in year 4 . . . . . . . . 14.8

4. Recession in midlife of project . . . . . . . . . 13.1

5. Profits only 900/0 of expectations. . . . . . . . 12.3

6. Prices held down by competition . . . . . . . . 10.4

7. Addition of a IO% EITC . . . . . . . . . . . . . . . . 21.5

a

lnvariant conditions:

Project: Installation of Computer Process Control System

Project lifetime = 7 years

Inflation rate = 6 percent

10 percent Investment tax credit

ACRS depreciation schedule

SOURCE Office of Technology Assessment

it (EITC), indicate that external factors such as

those listed above can have as dramatic an effect on the potential profit derived from a capital

project as that of a 10-percent EITC. OTA calculations show that a mild recession can cause a capital project IRR to shift 3 percentage points—i. e.,

to fall from 16.4 to 13.1 percent. On the other

hand, a 10-percent EITC would cause the IRR to

shift upward by only 5 points; for example, from

16.4 to 21.5 percent, which may in part explain

why aversion of risk and anticipated energy prices

drive project decisionmaking more than do tax

credits and other Government policies.

—

Contents

Industrial Energy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Sources of Industrial Energy. . . . . . . . . . . . . . . . . . . .

Energy Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Characteristics of Industrial Energy Use . . . . . . . . . . . .

Determinants of lndustrial Energy Use . . . . . . . . . . .

Qualitative Characteristics of Energy Use . . . . . . . . .

Quantitative Energy Use Characteristics . . . . . . . . . .

Variability of Energy Intensiveness. . . . . . . . . . . . . . .

End-Use Profile.. . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Trends in Energy Use Per Unit of Output. . . . . . . . .

Industrial Energy-Related Technologies and Processes

Housekeeping. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Retrofitting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Computer Control Systems . . . . . . . . . . . . . . . . . . . . .

Waste Heat Recovery. . . . . . . . . . . . . . . . . . . . . . . . .

Electric Motors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Fuel Switching. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Policies That Affect Industrial Energy Use . . . . . . . . . .

Existing U.S. Industry Energy-Related Legislation . . .

The Industrial Energy Conservation Program . . . . . .

Foreign Industrial Energy Use and Policy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

National Programs To Spur Industrial Energy Conservation . . . . . . . . . . . . . . . . . . . . .

Implications for the United States . . . . . .......

TABLES

Table No.

6.U.S. Industrial Energy Use by Source . . . . . . . .

7. industrial Energy Use by Division. . . . . . . . . . .

8. Distribution of Purchased Energy for Heat and

industry Croup in U.S. Manufacturing 1979 .

00..... . . . . . . . . . . . . . . . . ● . . . .

Power of Output by Selected

9. Estimated Distribution of U.S. lndustrial Energy Use, by Energy Service, 1978 ..46

10. lndustrial Energy and Oil Use by Representative IEA Countries 1973 and 1979,..

11. Comparative Energy Efficiencies-of lndustrial Processes unrepresentative IEA

‘countries . . . . . . . . . . . . . . . . . . . . . . . . . . ...... ........ ● ..***.. ....*** . . .

12.

13.

Changes in industrial Energy Consumption in lEA Countries between 1973

and 1978 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Projected Trends of industrial Energy and Oil Use in Selected IEA Countries

Through 1990.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

FIGURES

Figure No.

7. lndustrial Energy Demand, 1950-81 . . . . . . . . . .*..***. . . . . . . . . . ● **.*.*** ****

8. industrial Energy Prices, 1970-81 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

9. Overall Age Distribution of Equipment in the Manufacturing lndustry, 1975 . . . . . .

10. Energy Trends in lndustry, 1972-81 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Page

38

44

45

46

59

59

60

60

39

41

44
Chapter 3

Industrial Energy: Uses, Technologies, and Policies

INDUSTRIAL ENERGY

Energy does not flow through the industrial sector in simple or direct ways. Some energy or

energy-bearing materials are recycled and reused.

Substantial portions of energy used are derived

from unusual sources. Some materials are processed in ways that yield both energy and feedstock value. Finally, some energy materials are

not used at all for energy purposes. Thus, conceptual and data collection problems arise in

defining and measuring the energy used by the

industrial sector. ’

Sources of Industrial Energy

In the industrial sector, petroleum is the dominant energy source for motor-driven mechanical equipment of agriculture and construction.

Natural gas is the dominant energy source in mining because of its availability in the relatively

remote operations of the oil and gas extraction

industry. Natural gas is used in manufacturing

because it burns cleanly and provides easy flame

control. It has also been used as a feedstock and

as fuel for the special needs of a number of processes, such as glass manufacture and some ceramic production processes.

The use of petroleum and coal as raw materials

accounts for about half of the manufacturing use

of each of these fuels. * Most of the remaining half

of petroleum use in manufacturing is for direct

heat or for steam generation. This is also true for

coal, but coal is used more for steam generation

because there are relatively few goods produced

using direct heat that can tolerate the impurities

emitted by burning coal. For some energy uses,

1 Substantial parts of the discussion concerning the definition,

measurement, and determinants of industrial energy use are based

on material in the following: John G. Myers, et al., Energy Consumption m Manufacturing (Cambridge, Mass.: Ballinger Publishing

Co., 1974); John G. Myers and Leonard Nakamura, Saving Energy

in Manufacturing: The Post-Embargo Period (Cambridge, Mass.: Ballinger Publishing Co., 1978), and Bernard A. Gelb and Jeffrey Pliskin,

Energy Use in Mining: Patterns and Prospects (Cambridge, Mass.:

Ballinger Publishing Co., 1979).

“Metallurgical coal that IS converted to coke is counted as a raw

material.

particularly for large boilers (for water heating or

steam production), coal, oil, and gas are easily

interchangeable in a technical, if not economical,

sense. Many facilities, in fact, have dual or even

triple fuel capabilities—with oil and natural gas

the most likely combination.

As with other energy use variables, the diversity of use of various energy sources is more striking at lower levels of aggregation. Table 6, which

shows energy use by source for the divisions, also

has data for three selected industries in the manufacturing and mining divisions. Papermills, with

a wide distribution of purchased energy source

use, contrast with steel, which is heavily dependent on coal and coke, and the chemicals industry, which uses large quantities of natural gas and

electricity. overall industrial energy use from

1950 to 1980 is shown in figure 7.

Energy Costs

Although the use of energy in industry is a

major contributor to the character of modern

economies, the share of energy in the total cost

of producing goods is relatively small. In manufacturing, for example, purchased energy (fuels

and electricity) accounted for only 7.5 percent

of gross product in 1979, even after the steep

energy price increases of the 1970’s. Given the

variability of energy intensiveness across industries, the relative share of energy in total production costs is much higher in the more energyintensive industries. Thus, the cost of purchased

energy equaled 23 percent of the cement industry’s value of shipments in 1979, 14 percent of

the paperboard industry’s value of shipments,

and 25 to 30 percent of those for steel mills.

The degree of the energy price increases of the

1970’s should not be understated. prior to the

early 1 970’s, manufacturers’ energy costs rose

moderately in nominal terms and actually fell relative to inflation. Between 1970 and 1979, however, the average real cost of fuels and electricity purchased by manufacturers increased from

3 7

99-109 0 - 83 - 4
38 ● Industrial Energy Use

Table 6.—U.S. Industrial Energy Use by Source (quadrillion Btu)

Entire Selected industries, 1979b

industrial Sector divisions, 1979a

Steel Chemicals

Energy source sector, 1981 Agriculture Mining Construction Manufacturing Papermills industry industry

Coal and coke . . . . . . . . . . . . . . . . . . . 3.12 (c) 0.10 (c) 3.69 0.18 1.91 0.31

Natural gas . . . . . . . . . . . . . . . . . . . . . . 8.12 0.17 1.70 (c) 6.67 0.41 0.64 1.37

Petroleum . . . . . . . . . . . . . . . . . . . . . . . 8.12 1.32 0.62 1.58 6.68 0.41 0.21 0.76

Purchased electricity at

3,412 Btu/kWh . . . . . . . . . . . . . . . . . 2.85 0.13 0.26 0.02 2.50 0.15 0.17 1.00

Total. . . . . . . . . . . . . . . . . . . . . . . . 22.21 1.62 2.68 1.60 19.54 1.15 2.93 3.44

NOTE: Recent revisions of petroleum and natural gas use data by DOE have been substantial, and make it difficult to reconcile DOE figures on energy use by fuel

with figures published by the Bureau of the Census for manufacturing and mining.

aEstimated.

b

purchased energy only.

cNone, or less than 5 trillion Btu.

SOURCE: Energy Information Administration, U.S. Department of Energy, Month/y Energy Review, March 1982; End Use Energy consumption Data Base: Series 1, Tables,

June 1978; Economics, Statistics, and Cooperative Service, U.S. Department of Agriculture, Energy and U.S. Agriculture: 1974 and 1978, April 1980; Bureau

of the Census, U.S. Department of Commerce, 1979 Annual Survey of Manufactures and 1977 census of Mineral Industries; American Iron and Steel Institute,

Annual Statistical Report for 1960; Chemical Manufacturing Association, “1980 Report to the Office of Industrial Programs, Department of Energy.”

Figure 7.—industrial Energy Use, 1950-81

30

25

20

15

10

5

0

*

1950 1955 1960 1965 1970 1975 1980 1985

Year

SOURCE. Energy Information Administration
Ch. 3—industrial Energy: Uses, Technologies, and Policies ● 3 9

$2.34 to $4.44 per million Btu (see fig. 8). The used by manufacturers continued its pre-1971

cost per million Btu of distillate oil jumped from trend toward more expensive energy sources (oil

$1.76 to $5.31, and that for natural gas increased and electricity) and away from coal, at least unfrom $0.63 to $1.76. Despite this dramatic in- til 1979.

crease in energy prices, the mix of energy sources

8

7

6

5

4

3

2

1

0

SOURCE: Energy Information Administration.

CHARACTERISTICS OF INDUSTRIAL ENERGY USE

The manner of accounting for energy use in this Iated data are collected, what is actually measreport is defined as the attribution to industry (or ured and reported is the quantity of fuels and

its divisions) of the energy that is applied or con- electricity purchased by the industrial sector that

verted to nonenergy products. This is the so- does not leave the sector as fuel or electricity.

called disappearance approach. As a conse- This approach has the disadvantage of excluding

quence of the way in which energy use and re- from energy use the process byproducts and
40 ● Industrial Energy Use

-- —

waste materials that are consumed for their heat

value. * It also excludes utility generation and

transmission losses.

If defined to exclude utility generation and

transmission losses, industrial energy use directly reflects changes in technology, product mix,

and other developments in a sector or industry.

On the other hand, distortions result from this

method if the sector or industry generates part

of its electricity internally and the proportion of

internally generated electricity changes over time.

For example, a decrease in the proportion of electricity that is self-generated will “shift” the heat

losses from industry to the electric utility sector,

causing an apparent decline in Btu consumed per

unit of output, even if industrial energy efficiency has been unchanged.**

The analytic focus of this chapter is on final

rather than primary energy use. Mainly for this

reason, energy use by the industrial sector has

been defined to equal the direct heat content of

fuels and purchased electricity used plus the heat

equivalent of the energy materials used for nonenergy (feedstock) purposes.*** Energy materials —

*An approach that avoids the above disadvantage is to measure

the energy content of all materials and electricity taken in by the

sector or industry and to subtract from it the energy contained in

all products shipped. Since this entails the enormous task of determining the energy content of each of the millions of commodity

input and output flows, this method has not been used herein.

* *The choice between the measures of heat value of purchased

electricity is particularly important for the industrial sector because

the proportion of electricity used that IS self-generated can be significant for the sector as a whole and appreciable for some lndustrles. For instance, more than 46 percent of the electric power

used by paper and paperboard mills (excluding building paper) in

1979 was self-generated. However, for industry as a whole, the selfgenerated electricity share has decreased markedly. While such

self-generated electric power accounted for 21 percent of electricity

used in manufacturing establishments in 1958, it was only 9 percent in 1979. Appropriateness of measurement method hinges on

purpose of analysis, the particular Industry group under examination, and the level of disaggregation. Correct analytical treatment

of electrical generation heat losses wiII become more critical if there

IS rapid growth of cogeneration. This is true whether the electric

power IS used by the industrial plant or IS sold to a utility.

* * *Use of the narrower definition of the energy content of purchased electricity has another analytical advantage for the present

purpose. While the overall measure of energy in purchased electricity IS helpful in Indicating the total impact of a sector or industry

on the total demand for energy in the economy, it IS not a good

Indicator of the effects on energy use brought about by changes

within the sector or industry, This is because changes in the amount

of heat used by external electric utilities to generate each unit of

electricity are Incorporated into the energy use totals of the sector

or Industry. Average thermal efficiency of electric utilities Improved

by nearly one-third between 1947 and 1967, fell a Iittle from 1967

to 1971, and has Since risen slightly, but Irregularly.

used for feedstock represent as much a demand

for energy resources as do energy materials used

for heat or power. The energy value of purchased

electricity is calculated to be its theoretically contained energy–3,41 2 Btu/kilowatt-hour (kWh)–

rather than the total amount of energy used in

generating and delivering the electricity, which

is more than three times that number of Btu/kWh.

Self-generation, it should be noted, is a broad

term denoting the generation of electricity by an

industrial plant whose primary activity is not the

production of electric power. Such self-generation may or may not constitute part of a cogeneration operation, in which the energy in the

steam used for electricity generation is also used

to meet (entirely or partially) one or more other

energy needs. Cogeneration can mean the complete use of all the energy within the plant, or

the sale of some of the energy or one of the

energy forms to an electric utility or an energy

end user.

Determinants of Industrial Energy Use

The total amount of energy used in industry at

any one time depends on the level and composition of demand for the products of industry, the

relative price of energy, the quantities of capital

equipment available for use, the level of technology, Government regulations, and the cost of

equipment for improving energy efficiency.

Changes in any of these variables will influence

the amount of energy used.

Analyzing the determinants individually (i.e.,

holding the others constant) the following observations have been made:

● Product demand: In the short run, total energy use generally increases when demand

rises and more goods are produced. Since

the production of every kind of industrial

commodity requires some energy, only a

shift in the composition of demand (product

mix) to less energy-intensive commodities

can prevent energy use from increasing

when output increases. Such product mix

changes can result from changes in the economy. For example, there is evidence that in

recent years the sharp increase in the price

of energy has reduced the demand for energy-intensive products and slowed the
Ch. 3—industrial Energy: Uses, Technologies, and Policies . 41

●

●

●

o

●

●

growth of energy-intensive manufacturing industries.

Relative price of energy: In production,

those processes that use less energy for making a commodity become more economical

and attractive when the relative price of energy increases. Another way to reduce energy losses is by instituting more careful

housekeeping.

Use of capital equipment: Energy use over

the long term can be affected by an increase

in the amount of capital equipment. For example, a change from a labor-intensive process to one that is highly mechanical can increase energy consumption. However, capital can be substituted for energy, such as

when a furnace or steam pipe is insulated.

Level of technology: An improvement in

technology results in a decrease in the

amount of one or more inputs needed to

produce the same amount of output (holding

other factors constant). While energy frequently is one of the inputs reduced, sometimes its use will rise as a result of a technological change. For instance, a new process

may economize on labor, yet consume more

energy.

Government regulations: Energy use can be

affected by Government regulations, particularly those aimed at protecting the environment or worker safety and health. In

most cases, additional procedures are required, such as processing of wastes and instituting work area security measures, that

entail the use of energy.

Cost of equipment for improving energy efficiency: The cost of equipment for improving energy efficiency can have a direct impact on energy use within an industry. A

piece of equipment may return many dollars

in savings via decreased energy costs; but if

the initial investment is very expensive, the

corporation may not have the funds to undertake such a project.

Qualitative Characteristics of Energy Use

Capital Intensiveness

Energy use in any sector is related to the available stock of capital equipment in use. While

energy intensiveness is not solely a function of

capital intensiveness, the connection is strong.

When data on capital equipment per person employed are compared with figures on energy use

per unit of output, divisions and industry groups

that have high ratios of capital to labor appear

to be those with high energy intensity. z

In “capital-dominated” industries, increases in

overall productivity (which normally means reduced energy intensity) are most likely to come

from additions of new equipment or processes.3

However, because the initial cost of capital equipment is high and the average useful life of capital

ranges from 5 to as many as 50 years, replacement of equipment is slow (see fig. 9). This fact

limits the rate at which new equipment with dif2

John w. Kendrick and Elliot S. Grossman, Productivity in the

United States, Trends and Cycles (Baltimore: The Johns Hopkins

University Press, 1980).

3Bela Gold, Productivity, Technology, and Capita/ (Lexington,

Mass.: D.C. Heath & Co., 1979), pp.-98-100.

Figure 9.—Overall Age Distribution of Equipment

in the Manufacturing Industry, 1975

601 - 57

2 5 +

16

16.25 11-15 6-10

Age of equipment

(in years)

7

0-5

SOURCE: John Govoni and Cyr Livonis, “Age of Manufacturing Plants, ” Joint

Statistical Meetings, San Diego, Calif., August 1978.
42 . Industrial Energy use

———

ferent energy-use characteristics can be adopted  ̃ feedstock by the Bureau of the Census because

by industry.

In some cases, improved raw materials result

in improved productivity in capital-dominated industries. A notable example is the steel industry,

where the use of pelletized iron ore (produced

in the mining division) has decreased coke and

heat energy requirements.

Process-Specific Technologies

The processes employed in the output of industrial products are many and diverse. Each of

the many industrial substances handled and transformed requires a process suitable to the location of the industrial activity and the commodity’s physical state, chemical composition, and

final use. For example, some furnaces in the steel

industry are used to melt materials to permit further processing, whereas furnaces in brick manufacture are used to harden the product. Because

technological change in one process often has

little or no applicability to other processes, the

rate at which changes in industrial energy use can

occur is limited.

Raw Material Use

In its role as the goods-producing part of the

economy, the industrial sector uses large quantities of energy materials primarily, if not exclusively, as feedstocks for products that are not

intended for energy purposes. This situation is

unique among the major energy-using sectors.

The energy materials used as feedstocks by the

industrial sector in 1979 had a heat value of nearly 6 Quads, roughly one-fourth of the total industrial energy use.

The use of energy materials for feedstocks is

concentrated in manufacturing and construction.

Most of such feedstock materials are petroleum

products and natural gas. Petroleum-based feedstocks are used mainly in the petrochemical industry–e.g., for industrial organic chemicals and

in construction asphalt. Natural gas is a major

feedstock for ammonia and fertilizer manufacture.

Most of the substantial amount of coal purchased by the steel industry is classified as a

it is processed to produce coke and other byproducts. Coke is essential to the chemical change that

occurs when iron ore is changed to molten iron,

and it is a source of the necessary heat. In 1981,

metallurgical coal with a heat value of approximately 1.4 Quads was converted into coke.

Use of Captive Energy

A significant proportion of energy used for heat

or power by the industrial sector is derived from

waste materials or byproducts generated by industrial processes. Examples are exothermic heat

generated in chemical reactions, the production

of coke oven and blast furnace gases in the steel

industry, and the combustion of waste wood in

the paper industry.

The energy content of the used “captive” energy may or may not be counted in Department

of Energy (DOE) or Census Bureau compilations,

depending on the type of energy source. For example, where the energy source is a petroleum

product, its full heat value has already been

counted by DOE, but not by the Census Bureau

in its quinquennial Census of Manufactures or the

Annual Survey of Manufactures reports. If the

source is not a conventional industrial energy

source (e.g., wood wastes in a papermill), the

heat value of the used captive energy is counted

by neither DOE nor the Census Bureau. In the

first case, the demand for energy sources is

known, but there is no information on the part

that went for heat or power rather than for incorporation into a product. In the second case,

there is no reflection in overall energy use data

of this portion of energy use in the economy,

even though its existence has an effect on the

amount of “conventional” energy consumed. In

both cases, some information is missing that

would assist analysts in learning about the manner, efficiency, and extent of both conventional

and unconventional energy use.

Shifts in Energy Use Between Sectors

Changes in the relative prices of goods and

services over time affect the location of energy

use in the economy. Such changes can result

even if there has been no change in the composi-
Ch. 3—industrial Energy: Uses, Technologies, and Policies • 43

tion of demand. Awareness of energy displacement is important to avoid incorrect conclusions

about energy conservation in an industry, division, or sector. Many such shifts have occurred.

For example, a shift to the mixing of concrete by

suppliers, as opposed to builders, has resulted in

a shift in energy use from the construction to

manufacturing (the ready-mix concrete industry).

Rapid growth in fertilizer and pesticide use by

agricuIture has increased farmers’ output relative

to energy input, but has added substantially to

total energy use in manufacturing. Finally, the expansion of the frozen food industry in manufacturing has decreased the amount of energy used

for food preparation in the residential sector.

Awareness of such shifts is crucial to proper interpretation of industrial energy use figures.

Capital Effects and Capacity Utilization

Energy use per unit of output is generally high

when the level of production is low. One reason

for this is simply the need, at reduced levels of

output, to reheat furnaces, ovens, or boilers that

have been allowed to cool during exceptionally

slack periods. The steel industry provides an especially good example of this effect. During the

recession years of 1970 and 1975, energy use per

ton of raw steel produced rose 6 and 10 percent

respective y.

An exception to this effect is found in industries

where plants can be partially or completely shut

down if there is a decline in demand and when

it is feasible to shut down the least efficient

facilities. Such a situation requires a homogeneous product and a comparatively small number

of firms in the industry. A

Quantitative Energy Use Characteristics

Overall Sector Consumption

Energy directly used by the industrial sector for

heat, power, and feedstocks accounts for almost

one-third of the total energy used in the United

States. In 1981, the heat value of such direct

4

This discussion of cyclical effects is based on material in J. G,

Myers, et al., Energy Consumption in Manufacturing (Cambridge,

Mass,: Ballinger Publishing Co., 1974); and J. G. Myers and L.

Nakamura, Saving Energy in Manufacturing (Cambridge, Mass.: Ballinger Publishing Co., 1978).

energy use totaled 25 Quads, or 30 percent of

the economywide aggregate of 73.8 Quads.

In contrast to the other broad, energy-using sectors, direct energy use by industry has decreased

from 40 percent of the U.S. total in 1947, to 30

percent in 1981. This decline was due partly to

the decline in the share of the gross national product (GNP) accounted for by the sector.

As shown in figure 10, extrapolating historical

trends prior to 1972 would lead to an estimate

of 40 Quads of energy use for 1981. However,

actual energy use in 1981 was only slightly higher

(29 Quads) than in 1972. DOE analysis indicates

that a slower growing economy accounted for

4.4 Quads of this difference: the economy went

from an annual GNP growth rate of 4.0 percent

in 1972 to 2.6 percent in 1981. In addition, the

United States now uses a slate of industrial products different from that used in 1972. For example, consumers drive more fuel-efficient automobiles, made of less steel and less petroleum-based

plastics. Moreover, U.S. production is now greater in areas such as computers and biotechnology and less in steel production and petroleum

refining. This market-induced phenomenon is

due, in part, to perceived or anticipated rising

energy prices and also to expanding markets in

these new areas.

In addition, there is a historical trend toward

even more energy-efficient production facilities,

Even when energy costs were stable or declining, industrial managers had significant reason to

make efforts to conserve energy. Moreover, as

manufacturing technology continues to evolve,

it becomes more energy efficient. Between 1972

and 1981, the 2.3 Quads of energy saved because

of new technology would have been saved even

if prices had not increased since 1972,

Finally, 1.1 Quads of energy were saved because of efficiency improvements made specifically to existing equipment to counteract the

quadrupling of energy prices since 1972.

Energy Use by Divisions

Energy use by the industrial sector is not proportional to the relative sizes of the divisions in

dollar value of output. Just as the divisions are
44 . Industrial Energy Use

—

x

Improved

efficiency

)

Slower growth (4.4 Quads) —Industrial output slowed from 4.%

per year to 2.6% per year after 1972;

Shifts in output mix (2.6 Quads) —depressed output among large,

energy-using industries (steel, cement, chemicals, aluminum,

paper) is offset by increased growth in lighter manufacturing

(textiles, fabrication of aircraft and machinery parts, computers,

and food processing);

/reproved energy efficiency (3.4 Quads)—new technologies and

better energy management. Part is due to the historical trends

(2.3 Quads) in improving energy efficiency associated with

capacity expansion and capital stock turnover; the remainder

is due to accelerated gains (1.1 Quad) in improved efficiency

associated with higher energy prices.

1972 1974 1976 1978 1980

Year

SOURCE: R. Marlay, Off Ice of Plannlng and Analysis, U.S. Department of Energy. Analysis based on data from the Board of Governors of the Federal Reserve System,

the U.S. Department of Commerce, the Energy Information Administration, and on “Industrial Energy Productivity, 1954 -1980,” Massachusetts Institute -.

of Technology, Cambridge, Mass.

diverse, so are the activities and products within

each division. The bulk of industry’s energy use

takes place in manufacturing—the largest division

in output. Direct energy use in manufacturing

totaled an estimated 19.5 Quads in 1979, or 75

percent of the total for the industrial sector (see

table 7). Gross product originating in manufacturing was 76 percent of industrial sector gross

product (in 1972 dollars) that same year.

Almost half of the rest of the energy used by

industry is accounted for by mining, but mining’s

share of the sector total is disproportionate to its

output. Estimated energy use in mining was 2.7

Quads in 1979, while gross product originating

in mining accounted for only 4 percent of the industrial sector’s total. Agriculture and construction each used about 1.6 Quads in 1979, or 6 percent each, of total industrial energy use. These

divisions’ respective shares of sector gross product originating were 8 and 12 percent. The different proportions between energy use and outTable 7.—industrial Energy Use by Division

(in quadrillion Btu)

Division 1954 1967 1972 1979

Agriculture. . . . . . . . . . 0.90 1.40 1.61 1.63

Mining . . . . . . . . . . . . . 1.27 1.78 1.99 2.68

Construction . . . . . . . . 0.82 1.24 1.60 1.60

Manufacturing. . . . . . . 11.78 — — 17.62 19.76 19.54—

Total . . . . . . . . . . . . . 14.77 22.04 24.96 25.45

NOTES: The energy value of purchased electricity is defined hereto be the theoretically contained energy of the delivered electricity—that is 3,412

Btu/kWh.

The data shown are estimates and include energy substances used

as raw materials. Recent revisions by DOE of energy consumption data

have been substantial and make it difficult to reconcile DOE figures on

energy use with figures published by the Bureau of the Census for

manufacturing.

SOURCES: Bernard A. Gelb and Jeffrey Pliskin, Energy Use in Mining: Patterns

and Prospects, Cambridge, Mass., 1979; John G. Myers, Industrial

Energy Demand, 1976-2000, draft report prepared for the General Accounting Office, July 31, 1979; Economics, Statistics, and Cooperative

Service, U.S. Department of Agriculture, Energy and U.S. Agriculture:

1974 and 1978, Washington, D. C., 1980; Tetra Tech, inc., Energy Use

in the Contract Construction Industry, prepared for the Federal Energy

Administration, Feb. 18, 1975; Bureau of the Census, U.S. Department

of Commerce, 1977 Census of Mineral Industries, “Fuels and Electric Energy Consumed,” February 1981; Energy information Administration, U.S. Department of Energy, End Use Energy Consumption

Data Base: Series 1 Tab/es, Washington, D. C., 1978; Energy information Administration, 1981 Annual Report to Congress, Washington,

D. C., 1982; Bureau of Mines, U.S. Department of the Interior, Minerals

Yearbook, several issues, Washingtonj D, C.; Bureau of Mines, Energy

Through the Year 2000, Washington, D. C., 1972.
Ch. 3—industrial Energy: Uses, Technologies, and Policies ● 4 5 ———.—. -—. —————————.— .

put reflect large differences in energy use per unit

of output among divisions.

Much more is known about energy use in manufacturing and mining than in agriculture and

construction because of the availability of detailed

industry data over an extended time period from

the quinquennial Census of Manufactures and

from the Bureau of Mines industry surveys and

Minerals Yearbook. In recent years, the Annual

Survey of Manufactures has provided yearly figures on energy use i n manufacturing.

Variability of Energy Intensiveness

The energy used per unit of product varies

markedly among divisions and industries. Examples of high energy use in relation to output

can be found in the following industry groups:

primary metals, chemicals, petroleum and coal

products, and paper and allied products. Purchased energy use per unit of output by these

groups ranged from 39,000 to 57,000 Btu per dollar of value added in 1979, compared with 17,000

Btu for all of manufacturing (see table 8). Together, the five groups accounted for approximately 65 percent of manufacturing’s purchased

energy for heat and power in 1979, as against 26

percent of manufacturing, valued added.

In sharp contrast, the following four groups

together accounted for 40 percent of manufacturing, value added, but only 11 percent of

energy use: nonelectrical machinery, transportation equipment, electric and electronic equipment, and fabricated metal products. Energy use

per dollar of value added by these groups ranged

from 3,400 Btu to less than 6,700 Btu.

Greater differences in energy intensity can be

seen at the lowest basis of aggregation—the individual industry (four-digit SIC level). For example, in 1979 purchased Btu (for heat and power)

per dollar of value added ranged as high as

332,000 Btu for the lime industry to as low as

5,000 Btu for the motor vehicles and car bodies

industry. These differences in energy intensity are

important for evaluating prospects for reduced

energy use i n the economy by virtue of shifts i n

product mix.

End-Use Profile

Attesting to its diversity, industry uses energy

for probably a wider variety of purposes than

does any other sector of the economy. Estimates,

updated for this report, by the Energy Information Administration (E IA) and other organizations

indicate that each of seven different types of

energy service account for at least 2 percent of

sector use5 (see table 9).

The most energy-intensive industrial processes

entail the direct application of heat to break and

rearrange atomic bonds through chemical reactions. Since processes such as smelting, ore beneficiation, cement manufacture, and petroleum

refining typically involve large amounts of such

5Energy Information Ad m I nitration (EIA), Department of Energy,

End Use Energy Consumption Data Base: Series 1 Tables (Sprlngfield, Va.: National Technical Information Service, June 1976), p.

206.

In preparing its data on energy consumption by end use, EIA used

only explicit published figures, and made few, if any, estimates,

As a result, large quantities of energy use were not categorized by

end use, but designated as “other. ” The Congressional Research

Service has used additional related Information to categorize most

of this use in the case of the industriaI sector.

Table 8.—Distribution of Purchased Energy for Heat and Power of Output

by Selected Industry Group in U.S. Manufacturing, 1979

Energy used

Energy used per dollar

Value added of value added

Industry group (Trillion Btu) (% of total) ($ billion) (o/o of total) (thousand Btu)

Paper and allied products . . . . . . . . . . . . . . . . . . . 1,300 10.1 29.7 3.8 43.8

Chemical and allied products . . . . . . . . . . . . . . . . 2,889 22.5 73.4 9.5 39.4

Petroleum and coal products . . . . . . . . . . . . . . . . 1,245 9.7 24.8 3.2 50.1

Stone, clay, and glass products . . . . . . . . . . . . . . 1,266 9.8 24.1 3.1 52.6

Primary metals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,689 20.9 47.6 6.2 56.5

Total manufacturing . . . . . . . . . . . . . . . . . . . . . . 12,869 100.0 772.6 100.0 16.7

NOTES See note to table 7 regarding energy content of purchased electricity Percentages were calculated from unrounded numbers

SOURCE: U S. Bureau of the Census, 1979 Annual Survey of Manufactures
46 ● Industrial Energy Use

Table 9.—Estimated Distribution of U.S. Industrial

Energy Use, by Energy Service, 1978 (percent)

Energy service Manufacturing Entire sector

Space conditioning . . . . . . . 2

Direct heat . . . . . . . . . . . . . . . 30

Machine drive . . . . . . . . . . . . 5

Vehicles b . . . . . . . . . . . . . . . . 2

Steam . . . . . . . . . . . . . . . . . . . 22

Electrolytic process . . . . . . . 5

Raw material . . . . . . . . . . . . . 30

Other c . . . . . . . . . . . . . . . . . . . 5

Total . . . . . . . . . . . . . . . . . . 100

2

26

13

8

16

4

27

4

100

alnclude~ space heating and cooling, light, water heating, and refrigeration.

bOff highway.

C

ln some cases where no amounts are shown, the small quantities of energy

use accounted for by particular energy services have been included in “other.”

SOURCES: Energy Information Administration, U.S. Department of Energy, End

Use Energy Consumption Data Base: Series 1 Tables (Springfield, Va.:

National Technical Information Service, June 1978); Solar Energy

Research Institute, Building a Sustainable Energy Future, vol. 2,

published by the U.S. Congress, House Committee on Energy and

Commerce, April 1981, estimates by the author.

heat, it is not surprising that more than one-fourth

of industrial energy use is accounted for by direct

heat applications. Because steam is another

source of heat, most notably in the manufacture

of paper and chemicals, this energy service represents another one-sixth of industrial energy use.

Thus, heat of some sort accounts for nearly half

of total industrial energy applications. When

energy sources used for feedstocks (more than

one-fourth of the total) are subtracted, direct heat

and steam account for nearly three-fifths of industrial end-use energy demand. Using energy

to provide fuel and electrical power for machinery and vehicles is predominant in agriculture,

construction, and mining, where it accounts for

an estimated 86, 45, and 57 percent, respectively, of energy use in those divisions.

Trends in Energy Use Per Unit of Output

Overall industrial energy use per unit of output has decreased steadily since the late 1940’s,

including both before and after the Arab oil embargo of 1973-74.

Post-World War II to 1972

Between 1947 and 1972, energy use per dollar

of real gross product in the industrial sector fell

an average of 1.1 percent per year. Also, use of

energy per unit of output in manufacturing decreased an average of 0.8 percent per year between 1954 and 1972. Most of this decline was

traced to: 1 ) faster energy saving by the energy-intensive manufacturing industry groups compared

to other manufacturing industries, and 2) faster

output growth by the less energy-intensive industries. Among the energy-intensive manufacturing industry groups, the 8 or 10 largest users

(which accounted for half of manufacturing energy use) reduced their energy use per unit of output faster than did the remaining energy-intensive

industries.

Within manufacturing, declines in energy-output ratios were the net result of a number of opposing influences. Probably most important was

the introduction of new technology that permitted an industry to produce a given volume of

product with a smaller quantity of capital, labor,

energy, and materials. The introduction of new

technology nearly always entailed new or expanded manufacturing facilities. In some cases,

improved raw materials aided overall productivity. Labor and energy were frequently the inputs

that were economized.

Improvements in management techniques also

contributed to the decreases in energy consumption per unit of output. However, such managerial and technological developments were largely

incidental to innovations designed primarily to

enhance overall productivity. Finally, the shift in

production from energy-intensive industries toward those that were less energy-intensive also

contributed to the decline in the energy-output

ratio for all manufacturing. The former are mainly

basic material industries; thus, this shift is part of

the long-term development toward higher degrees of fabrication.

In contrast, energy use per unit of output in

manufacturing was boosted by an acceleration

in the late 1960’s in the growth of industries using

large amounts of energy-bearing commodities for

raw materials—particularly petrochemical feedstocks and natural gas. Such industries included

plastics, manmade fibers, and agricultural chemicals. The decline in energy use per unit of output would probably have been steeper without

this development.

The preembargo period also saw a drastic shift

in the sources of energy used by industry, some
.

Ch. 3—industrial Energy: Uses, Technologies, and Policies . 47 ——.— ———— .

of which may well have contributed to the decline in energy use per unit of output. Between

1947 and 1972, the share of industrial energy use

accounted for by coal—which burns relatively inefficiently—shrank from 55 to 20 percent. At the

same time, shares of natural gas and petroleum

expanded from 23 and 19 percent, respectively,

to 45 and 25 percent. To some extent, the growth

in natural gas and petroleum was attributable to

rapid expansion of their use as feedstocks.

Meanwhile, use of electricity by industry grew

rapidly, continuing the electrification of the sector that began early in the 20th century. Expansion of electricity use took place mainly from increased purchases of utility electricity, in part because the real price of electricity to industry fell.

But self-generated electrical power also grew in

absolute terms, though its relative share of the

total amount of electricity used by industry fell.

Purchases in 1972 were about five times the 1947

level; self-generated electricity was twice the 1947

volume.

Perhaps most notable about the drop in energy

use per unit of output in industry between the

late 1940’s and early 1970’s is that it occurred

when the real price of energy was falling.

Trends Since 1972

The rate of decline in industrial energy use per

unit of output has accelerated since 1972. Sector energy use for fuel and nonfuel uses per unit

of output fell an average of 2.4 percent per year

between 1972 and 1980, compared with the 1.1

percent decline of the earlier period, The causes

of this more rapid decline appear to be a combination of: 1) a decrease in the energy-output

ratio within each division, caused both by better housekeeping and by major capital equipment

modifications, and 2) a product mix shift to less

energy-intensive products. b

At the division level, manufacturing experienced an average annual decline of 3,4 percent

per year in energy use per constant dollar of gross

bSome anaIysts have attributed more of the acceleration In the

decline in energy use per unit of output by the Industrial sector

to the shift to less energy-intensive products than has been done

here. See the DOE analysis described in fig. 10. Such a difference

In resuIts may be due to d Inferences I n the respective methods used

and in the data available to and used by the analysts.

product between 1972 and 1979 and, as the largest energy-using division, provided most of the

impetus to lower energy use per unit of output

in the industrial sector.

Energy use per unit of output in agriculture also

fell, but less rapidly. Data for energy use and output in mining indicate a notable rise in energy

use per unit of mining output. However, it is possible that difficuIties encountered by estimators

at the Department of Commerce i n determining

gross product originating in mining have resulted

in an understatement in mining gross product and

therefore an overstatement of energy use per unit

of output in 1979.

Analysis of manufacturing energy use during

the 1970’s reveals considerable energy savings

throughout the sector. In many cases, this energy

efficiency improvement was assisted by faster output growth, especially in the less energy-intensive industries. Among industry groups, only one

(tobacco manufacture) did not experience a decrease in energy use per unit of output between

1971 and 1979 (using Federal Reserve Board production indices to measure output change).7 Most

industry groups achieved overall decreases of

more than 30 percent in energy use per unit of

output over the 8 years.

Smaller than average reductions in per-unit

energy use by the largest and most energy-intensive industries during the 1970’s are due to

several factors. Slow economic growth and a

major recession tended to hold down capacity

utilization and, therefore, to boost energy use per

unit of output. Slow growth in demand for an industry’s products also reduced the rate of infusion of new state-of-the-art plants and equipment

and minimized opportunities to incorporate the

most energy-efficient, fixed capital, and production methods. Imposition of a variety of worker

health and safety and pollution control regulations also had a negative impact on energy efficiency in the industries affected. a

7

0TA calculations based on production Indices obtained from

the Board of Governors of the Federal Reserve System and the

energy use data from The Annual Survey of Manufactures, Bureau

of the Census, Department of Commerce.

“Edward F. Denison, “Effects of Selected Changes in the lnstitutional and Human Environment Upon Output Per Unit of Input, ”

Survey of Current Business (Washington, DC.: U.S. Department

of Commerce, Bureau of Economic Analysis, January 1978), pp.

21-44.
48 ● Industrial Energy Use

INDUSTRIAL ENERGY-RELATED TECHNOLOGIES AND PROCESSES

Certain energy-related, industrial technologies

and processes, such as steam generation, transcend any particular industry. The generic technologies discussed in this chapter are technologies which, for the most part, exist today and

are used by all four of the case study industries

examined by OTA.

Although not a technology, perhaps the most

important influence in conserving energy is the

corporate energy manager, who is often used in

conjunction with an energy review committee.

Such an individual who can step back and examine the energy flows in an entire mill, or between mills in a corporation, can often achieve

highly cost-efficient energy savings which others

with more confined attention have not seen. The

fact that this is not a hardware purchase, but

rather a commitment of human talent should not

disguise its importance as a means of energy conservation. Extensive documentation exists on the

rewards attributable to making such a serious corporate commitment to energy conservation.9

Housekeeping

Housekeeping items are numerous. In the area

of maintenance and repairs they include weatherstripping, replacement of wornout pipe insulation, improved maintenance of steam traps, and

tuning of combustion equipment. Those measures for controlling energy waste range from

manually switching off lights, machinery, and

other energy-using equipment not in use, to

designing and operating production schedules

that ensure operation of equipment at maximum

efficiency. An example of the latter would be ensuring that furnaces are operated only when their

load is fully needed. A large amount of the energy

savings by industry during the period 1974-80

were obtained by housekeeping.

9See, for example, NBS Handbook 115, Energy Conservation Program Guide for Industry and Commerce, Gatts, Massey, & Robertson (eds. ) (Washington, D. C.: U.S. Government Printing Office,

1974).

Retrofitting

In the context of reducing energy use and increasing energy efficiencies, typical examples of

retrofitting would be the installation of computer

process and production control systems, combustion control systems on a burner array, an economizer on a boiler, or a variety of other heat exchange equipment designed to capture and use

wasted heat.

Retrofits can be highly cost effective, not only

because of the energy they save, but also because

they often increase the performance level of their

host equipment and thereby allow increased production without building new facilities. In this

event, a retrofit can leverage much bigger costs

elsewhere i n the corporation and simultaneousIy offer t he possibility of increasing output. Moreover, the small scope of many retrofit projects

gives them an advantage: they are incremental

purchases and hence have little associated risk.

The cost of a retrofit is often low enough to be

accommodated in the discretionary or contingency funds available to many mill managers.

Computer Control Systems

Two easily distinguished varieties of computer

control systems—combustion control and process

control—are examples of generic technology that

can be bought specifically as an instrument to

save energy, as with a combustion controller, or

as part of an overall profit improvement program

that saves energy in an incidental way, as with

a process controller.

Combustion Control

In the combustion process, a given quantity of

fuel requires a fixed and easily measured quantity of air. Having an excess (i.e., nonoptimal)

quantity of air or fuel results in either unused air

being heated or incomplete combustion of fuel.

In either case, the full heat value of the fuel is

not captured, and the overall conversion of fuel

to electrical, mechanical, or thermal energy is not

as efficient as it could be.
Ch. 3—industrial Energy: Uses, Technologies, and Policies • 49

The aim of a combustion controller is to maintain the fuel-to-air ratio as close as possible to optimal by controlling the rate at which each is introduced to the combustion chamber. The controller performs its function by measuring the ratio

of combustion products found in the exhaust

gases. Products of combustion can include oxygen, carbon dioxide, and carbon monoxide. By

monitoring ratios of these products, a computer

can calculate an optimal air-fuel ratio, and make

necessary corrections or adjustments to minimize

inefficient combustion.

Modern combustion controllers are electronically based and, apart from being far more accurate than their old mechanical counterparts,

are able to act more quickly to correct any imbalances. They are, therefore, far more efficient

in their intended operation. Combustion control

systems have been extensively applied to industrial operations and are expected to play an

even greater role in the future.

Process Control

Process control is defined here as the computerized monitoring of process variables for the

optimization of production. Process controls are

almost universally applicable to industry; and

although saving energy is not their primary function, it becomes a secondary benefit of the effort to increase overall efficiency and productivity.

Because of the increased speed of industry

processes, hand-operated and slow-acting analog

controls create inefficiencies. The advent of the

microprocessor and of computer control systems

has enabled industry to advance the speeds of

processes, thereby maintaining higher efficiencies without losing control. Although not adopted

universally, the use of process control technologies is expected to increase throughout industry

over the next two decades.

Waste Heat Recovery

Wherever fuel is burned, the products of combustion are a potential source of wasted heat. industrial processes employ a vast variety of fuelburning equipment; therefore, the recovery of

Photo credit: American Petroleum Institute

Control room at a modern petroleum refinery

waste heat has major potential for numerous energy conservation programs throughout the industrial sector. The task is to find suitable applications for the waste heat, much of which is at too

low a temperature to be used as is.

Heat Exchangers

Heat exchangers are devices that transfer heat

or energy from a high-temperature, waste heat

source (e. g., the combustion gases) to a more

usefuI medium (e. g., steam) for Iow-temperature

use. The energy transferred can then be employed within the plant. Heat exchangers take

many forms and include heat wheels, recuperators, economizers, waste heat boilers, regenerators, and heat pipes.

The cost of a heat exchanger of any type is

often deceptively low, Installation costs are frequently triple (or more) the base price of the unit.

Furthermore, maintenance costs can be significant, particularly if there are moving parts (as in

a heat wheel), or where the flue gases are corrosive (as when burning high-sulfur oil or coal).

In many industrial applications, heat exchangers

are usually a more attractive investment when

they are purchased as part of the original package

of the furnace or boiler.

Upgrading Energy

Apart from these high-temperature, waste heat

sources, industry has a variety of low-temperature
50 • Industrial Energy Use

and low-level waste heat sources that can only

be utilized by upgrading them–i.e., by raising

their temperature and pressure. Two technologies

for upgrading heat are:

●

●

Vapor recompression: By vapor recompression, low-pressure steam is recompressed

mechanically to a pressure and temperature

that can be used in an industry.

Heat pump: A heat pump converts waste

heat into useful energy through a cycle of

operations that can be described as a reverse

refrigeration cycle.

In both cases energy must be added to upgrade

the energy contained in the waste heat sources.

In terms of Btu, low-level waste heat sources

would appear to have enormous potential. A substantial percentage of industrial energy input is

rejected as low-level heat. However, the economics of recovering these Btu in the form of

usefuI energy through such devices as vapor recompression and the heat pump vary greatly with

the origin and quality of the waste heat source,

the capital costs of the compressor or heat pump,

and the energy cost associated with driving the

system. Therefore, although these upgrading

steps are technically the same across many industries, some pertinent applications and factors

are industry-specific.

Electric Motors

The use of electricity by industry in 1980 was

2.8 Quads (or three times greater if one includes

the electricity generated by utilities burning fossil

fuels). Of that, roughly 80 percent was for mechanical drive, which essentially means electric

motors. Accordingly, there is a large energy-saving opportunity associated with increasing the efficiency of electric motors. Standard electric

motors range in efficiency from between 80 to

90 percent. By increasing the iron and copper

content of the core and windings, respectively,

energy efficiencies can be improved to beyond

95 percent.

This incremental increase in efficiency may not

appear significant at first sight. However, electric motors are almost unique among capital investments in that their capital costs are only a

small fraction of their operating costs, even with

the added iron and copper content of the higher

efficiency motors. For example, an electric motor

could use in excess of 10 times its capital cost

in energy each year, and the difference between

a 90- and 95-percent efficiency could mean an

annual energy saving of between 50 and 60 percent of a motor’s capital costs. However, the electric motor is a very reliable item of equipment.

In normal atmospheric applications it can have

a life expectancy in excess of 20 years. Because

of this, the replacement of a low-efficient electric motor with its high-efficient counterpart often

comes under discretionary spending. Although

the replacement of a functioning motor could be

economically justified, it would certainly not be

mandatory. On the other hand, when an electric motor has reached the end of its useful life,

it is common to replace it by a newer, more efficient type.

Fuel Switching

In U.S. manufacturing, there exists an economic incentive to use one fuel over another when

prices differ, In addition, noneconomic factors

would also lead a firm to use one fuel over

another. Such noneconomic factors are usually

related to security of supply or to government

reguIation.

OTA analysis indicates that there are two trends

in fuel switching that will continue for the next

two decades. The first trend is toward the use of

coal as a primary boiler fuel at industrial plant

sites. The second is toward the increasing use of

cogeneration facilities in which both electricity

(or perhaps mechanical and drive power) and

steam are produced simultaneously.

Technology for Converting to Coal

Although switching from natural gas or oil to

coal does not usually constitute an improvement

in energy efficiency, it may very well be a desirable goal from a national point of view, Coal

prices are often one-quarter of the cost of oil in

terms of Btu purchased.
Ch. 3—industrial Energy: Uses, Technologies, and Policies . 51

Some of the well-documented1o barriers preventing a smooth and consistent transition from

natural gas or oil to coal, however, include the

 following:

1.

2.

3.

4.

5.

Within the corporate plant, switching from

natural gas or oil to coal would be of very

low priority in the discretionary spending

pool unless it could be readily coupled to

security of supply.

Unless the boilers were originally designed

for coal, a complete new boiler plant would

be required, including all the coal storage

and handling equipment, as well as equipment for ash removal. if existing boilers were

still operational, their premature replacement would very rarely make economic

sense.

The installation of material-handling equipment, as described in (2), above, requires

large amounts of space, as does the storage

of coal. Such space is often at a premium

at most industrial sites.

Pollution control technology for coal is extremely expensive and far more complex

than that necessary for gas or oil. In fact,

natural gas requires no special technology,

and, providing that one can purchase lowsuIfur oil, all other regulations can easily be

met. Even if low-sulfur coal can be obtained,

it requires equipment to remove fly ash and

particulate. Furthermore, there is now a

perceived risk involved in burning coal because of the attention and publicity associated with acid rain.

In the large installations, deliveries of coal

can involve major capital and space allocations for railroad facilities and sidings. On

the other hand, oil and gas for this type of

facility can be fed into the plant via pipeline.

Thus, despite the large cost advantage of coal,

most of the problems listed above tend to undermine the attractiveness of coal. Some of the

newer coal-burning technologies (i.e., fluidized

bed combustion or the burning of coal/water mixtures) may reduce these problems. However, until these technologies have actually been proven,

I o The Direct Use of Coal: Prospects and Problems of Product/on

and Combustion (Washington, D. C.: U.S. Congress, Office of Technology Assessment, OTA-E-86, April 1979).

there is no way to assess their impacts, and, under

the present economic and competitive environment, it will take a long time for coal to make

major inroads as an energy source in most industries.

Cogeneration

Cogeneration is defined as the production of

both electrical or mechanical power and thermal

energy from a single energy source. 11 In industrial

cogeneration systems, fuel is first burned to produce steam. This steam is then used to produce

mechanical energy at the turbine shaft, where it

can be used directly, but more often is used to

turn the shaft of a generator, thereby producing

electricity. Although the steam that leaves the turbine is at a lower temperature and pressure than

that which entered, it still has sufficient thermal

energy to perform the heating and mechanical

drive duties required throughout the plant. In

contrast to cogeneration systems, conventional

industrial power systems produce their own thermal energy at the plant site but usually buy their

electrical power from a utility.

The principal technical advantage of a cogeneration system is its ability to improve the efficiency of fuel use. In producing both electric and

thermal energy, a cogeneration facility uses more

fuel than is required to produce either electrical

or thermal energy alone. However, the total fuel

required to produce both types of energy in a

cogeneration system is less than the total fuel required to produce the same amount of power

and heat in separate systems. Because it produces

two energy forms, a cogenerator will have less

electrical output from a given amount of fuel than

will a comparable powerplant. However, when

steam and electrical efficiencies are summed, the

cogenerator will achieve overall fuel use efficiencies 10 to 30 percent higher than the sum of separate conventional energy conversion systems.

Cogeneration does not easily fit into any of the

previously described categories such as retrofitting or housekeeping, and although presented in

this section, is not entirely a generic technology.

11A more detallecf cfiscussic)n of promising cogeneration technologies and their potential Impacts can be found in: /ndustria/ and

Cornrnercia/ Cogeneration (Washington, D. C.: U.S. Congress, Office of Technology Assessment, OTA-E-1 92, February 1983).
52 • Industrial Energy Use

Cogeneration is really a new name for an old and

proven practice. Around the turn of the century,

industry produced more than 50 percent of the

electricity generated in the United States. By

1950, only 15 percent of the U.S. electricity was

produced by cogeneration systems in large onsite industrial plants; by 1970, this figure had

dropped to less than 5 percent.

Historically, in order to justify a cogeneration

system economically and technically, a plant

either had to have a balanced need for thermal

and electrical or shaft power that was congruent

in both time and amount (e.g., the peak requirement for electricity and steam had to be coincident, and their load profiles similar). If such

balance and congruence were not present, the

system had to be able to distribute excess electricity to other sites or to purchase backup electricity from the local utility. However, few industrial processes had power needs that were this

balanced. Moreover, systems that sold electric

power were subject to regulation as utilities, and

backup power often was more expensive than

was regular electrical service. Thus, throughout

this century, as electricity from utilities became

progressively cheaper, industry found other uses

for its capital, and the use of cogeneration by industry declined.

Now, however, the picture has changed, both

from an economic and legislative standpoint. In

economic terms, the cost of a new, large, utility

generating plant increased in recent years to well

over $1,000/kW. Furthermore, utilities have been

affected by the massive increases in energy prices.

The combined effects of increased capital and operating costs have increased the attractiveness of

cogenerating facilities once again. I n addition,

Congress has passed the Public Utility Regulatory

Policies Act (PURPA, Public Law 95-61 7), which

mandates that utilities purchase the excess electrical energy generated by a cogeneration facility and provide backup service at a reasonable

rate. This situation alleviates the necessity of a

rigorous energy balance within the plant and allows the cogenerator to retrieve some of its

capital expenditure through the sale of electricity to a utility or the purchase of electricity from

a utility.

The economic key to cogeneration is the utilization of the waste heat from the cogeneration

process, a potential not usually available to a utility. A high level of efficiency for a utility operation would be on the order of 35 to 37 percent,

whereas an industrial cogeneration operation

may reach an overall efficiency in excess of 70

percent.

Although most of the regulatory problems associated with the sales of industrially cogenerated

electric power have been removed by PURPA,

industry is unlikely to rush to make the significant new investments required for such operation. Examples of the disincentives facing industry

are the following:

1.

2.

3.

The environmental implications of cogeneration can be a problem to industry, although

they are sometimes overlooked in discussions of the benefits from cogeneration.

There is no automatic way for a potential industrial cogenerator to get regulatory approval for the emissions its additional use of

fuel will generate. Even though incremental electrical energy will be made available

at perhaps half the emission rates of the utility’s powerplant, the industrial emitter gets

no credit for this improvement. Instead, the

emissions would be charged directly and entirely to the industry.

How the financial returns from cogenerated

electrical energy can be predicted is still uncertain. There has been considerable publicity about the “high” prices (from 5¢ to perhaps even IO¢/kWh) that a utility will have

to pay cogenerators and other producers of

electricity for the energy that the utility has

been able to “avoid” generating or purchasing from the grid. But the situation is not this

simple. In many areas (e. g., where utilities

have excess capacity or low-cost generating

plants), the rates for purchases of power

from cogenerators maybe as low as 1¢/kWh.

Achieving cogeneration efficiencies at the

cost of reducing utility coal use and increasing industrial use of petroleum-derived fuels,

would probably not be desirable if the primary goal of national energy policy were net

oil savings.
—

Ch. 3—industrial Energy: Uses, Technologies, and Policies ● 5 3

4. Finally, and this may in many instances be

the ultimate consideration, even a very attractive cogeneration project may not meet

industry management’s exacting requirements for the short paybacks and high rates

of return that are used to evaluate all projects seeking a share of the hard-pressed,

companywide capital budget.

Product Mix Shift

As energy costs increase or uncertainties prevail

over future fuel costs and supply, industries will

almost automatically, and on an evolutionary

basis, move to minimize these costs, risks, and

uncertainties. One method of achieving this is to

manufacture existing product lines with less process energy through the introduction of more efficient technology.

However, three other alternatives are also available. First, a company could cease manufacturing products that are energy-intensive and put

capital to work instead in other spheres of business and industry. For example, Japan, which is

having great difficulty in competing with U.S.

manufacturers of aluminum and paper, may take

measures to secede from these businesses entirely.

Second, a company could develop and manufacture new products that use less energy, yet

compete with the old energy-intensive product.

An obvious example is the small automobile in

competition with the large automobile. Even

within this broad category are competing considerations. For example, in the car itself,

aluminum and plastics readily replace other

metals, such as steel. Arguments that the energy

intensity associated with making one product is

more desirable than that used for making another

product are not really conclusive. Examples include debates about which packages are less energy-intensive— i.e., the glass bottle v. the plastic

bottle or the aluminum can v. the steel can. In

the final analysis, the marketplace, which considers many other costs besides energy, determines which product wins or loses.

The third course of action occurs when the

energy used to make a final product is shifted

away from the manufacturing facility to the user

of the product, An example of this can be found

in the petroleum refining industry. Although less

refined gasolines require less energy to produce,

they burn less efficiently in automobiles, thereby

lasting fewer miles per gallon and increasing the

energy cost of transportation. The refinery has

essentially shifted part of its energy losses to consumers using these products.

The measurement and quantification of the impact on energy conservation by product shift and

product change is beyond the scope of this report. However, it should be noted that over time,

these changes almost will inevitably take place

to an extent that products and even whole industries could radically contract and disappear.

POLICIES THAT AFFECT INDUSTRIAL ENERGY USE

Existing U.S. Industry

Energy-Related Legislation

During the 1970’s and early 1980’s, Congress

enacted several major laws that affected industrial

use of energy. The general goals of these measures were to reduce oil imports, to encourage domestic production of fossil fuels and the development of nuclear and alternative energy sources,

and to reduce energy demand through conservation and energy efficiency improvements. Incentives to meet these goals fell into three general

categories: 1 ) pricing mechanisms, 2) regulations,

and 3) financial incentives. In addition, DOE conducts several programs designed to study industrial energy use and ways to improve energy efficiency in industry.

Pricing Mechanisms

Oil and natural gas pricing issues dominated

congressional energy debate in the 1970’s. The

difference between domestic oil prices and higher

world energy prices was significant and had to

be resolved. After a year-long debate, the Energy

Policy and Conservation Act (EPCA, Public Law

99-109 0 - 83 - 5
54 • Industrial Energy Use

94-1 63) was enacted in December 1975. The law

provided for the eventual decontrol of oil after

September 30, 1981; however, mandatory Federal oil price controls were continued until June

1, 1979, EPCA gave the President authority to

continue, modify, or remove the controls after

that date. In April 1979, President Carter submitted to Congress his plan, later approved by

Congress, to phase in oil decontrol to cushion

consumers from rising prices. Oil decontrol proponents believed higher prices would encourage

domestic oil production and discourage use while

advocates of price control were concerned that

higher domestic oil prices would contribute to

inflation and burden consumers without providing commensurate new supplies.12

To accompany oil decontrol, the Crude Oil

Windfall Profits Tax Act (WPTA, Public Law

96-223) was passed in April 1980. Designed to

capture some of the windfall profits that oil companies would realize from decontrol, this new tax

was levied only on the difference between the

base price (ranging from $12.81 to $16.55) and

the actual selling price of a barrel of oil. The tax

rate varied from 30 to 70, depending on the type

of oil, the date the well was tapped, the method

of production, and the size of the producer. 13 To

date, total revenues collected from the windfall

profits tax amount to $28.1 billion ($3.7 billion

in fiscal year 1980, $13.8 billion in fiscal year

1981, $10.6 billion in fiscal year 1982). These

revenues have been added to general U.S. Treasury funds and not to specific energy-related or

transportation projects. On January 28, 1981,

President Reagan lifted price and allocation controls on gasoline and crude oil.

For natural gas, the Natural Gas Policy Act

(NGPA, Public Law 95-621) provided for continued controls indefinitely on most natural gas

contracted for prior to 1977, thus avoiding a sudden windfall for producers. The act further specified that price controls on new gas and certain

intrastate gas be lifted entirely by 1985 and that

gas from certain onshore wells be deregulated

in July 1987. NGPA also provided for incremen12Enerw poi;cy, zd ed, (Washin@on, D. C.: Congressional Qua~erIy, Inc., March 1981), p. 25.

‘

3

1 bid., p. 224.

tal pricing, thus placing the initial burden of gas

price deregulation on industrial customers. The

incremental price is equal to the price of newly

discovered natural gas plus regulated transportation costs. This industrial gas price is mitigated

through a ceiling determined by regional alternative fuel oil prices for either number 2 or number 6 fuel oil.

The Federal Energy Regulatory Commission

(FERC), which administers NGPA, is now considering raising old natural gas* prices. FERC

plans to issue a Notice of Inquiry that will explore

whether NGPA fosters market ordering problems,

such as unequal distribution of gas among interstate and intrastate pipelines, and whether such

problems can be alleviated by raising the price

of old gas. The FERC staff has suggested that

higher prices would eliminate the cushion of

price-controlled gas now enjoyed by interstate

pipelines. The record developed during the

Notice of inquiry could be used as a basis for

future FERC rulings.14

On February 23, 1983, the administration submitted to Congress a proposal to eliminate all

natural gas price controls and enable pipelines

and producers to abrogate long-term contracts

that are believed to be keeping prices high. In

addition to the administration proposal, several

alternative proposals have been introduced. Legislative debate has focused on the decontrol of

old gas. Decontrol, opponents argue, means

higher rates for homeowners who cannot easily

switch to other fuels. Also, there is concern that

rising gas prices could prompt industrial and utility users to switch to oil. Because gas prices, in

some areas, have surpassed industrial fuel oil,

switching has already begun to occur. However,

proponents argue that eliminating all controls

would encourage the production of old gas and

cause old gas prices to increase and new gas

prices to decrease.15

*Old gas is that which was discovered before 1977, and whose

price is federally controlled.

lq/n~j~e E~ergy (New york: McGraw Hill, April 1982), PP. 7-8.

I ~Congressional Qua~erly Weekly Report, ‘‘Natural Gas Prices:

Ready for the Free Market?” vol. 41, No. 9, Mar. 5, 1983, pp.

443-447.
—

Ch. 3—industrial Energy: Uses, Technologies, and Policies . 55

Regulations

The Government can also intervene in the energy marketplace through regulation. in the industrial sector, Government policies seek to promote the switch from oil and natural gas to coal

or renewable resources. Since 1974, the Federal

Government has administered coal conversion

programs under provisions of the following legislation: EPCA, the Environmental Supply and Environmental Coordination Act (ESECA, public Law

93-319), and the Powerplant and Industrial Fuel

Use Act of 1978 (FUA, Public Law 95-620).

ESECA prohibited any powerplant or major

fuel-burning installation from burning natural gas

or petroleum as a primary fuel source if the plant

or installation had the capability and necessary

equipment to burn coal. EPCA expanded the authority of the Federal Energy Administration to

order major powerplants and fuel-burning installations to use coal instead of oil and gas. FUA

further modified and expanded coal switching

programs and established new regulatory policies

for converting industrial users of oil and natural

gas to coal. Under FUA, new facilities may not

burn oil or gas until the owners demonstrate to

DOE that an exemption is justified. Also, FUA

prohibited the burning of natural gas in existing

powerplants from 1990 on and restricted its use

prior to then. However, a full range of temporary

and permanent exemptions was established.16

The omnibus Budget Reconciliation Act of

1981 (Public Law 97-35) made changes in FUA.

It repealed the general prohibition against burning gas in existing powerplants and withdrew the

authority of DOE to prohibit burning oil/natural

gas in existing powerplants if the plant were

capable of using coal or alternative fuels. Instead,

the law allows a utility to certify to DOE whether

a powerplant is capable of burning coal/oil or

coal/gas and gives DOE authority to prohibit the

burning of oil/gas in such plants as certified.

The effectiveness of coal conversion programs

is questionable for a number of reasons. The cost

of fuel conversion is staggering, and it may be

impractical to retrofit some plants. Capital conlbcongresslonal Research Service, The 9.5th C0frg~e55 afl~ ~fle~gy

Po/icy, prepared for the House Subcommittee on Energy and Power,

January 1979, p. 13.

straints will stretch the time for completion even

further. And, while coal is cheaper than oil on

a Btu basis, it is not necessarily a cheap fuel when

transportation, handling, and pollution control

costs are included. In addition, coal-fired boilers

are more expensive to purchase than are oil-fired

boilers. This reality could be a deterrent to greater

coal use, particularly in smaller companies that

do not have access to the capital necessary to buy

new boilers or to retrofit old ones. In addition,

exemption provisions of the law still allow companies to continue burning oil and gas. A company can petition for an exemption for a variety

of reasons: air quality, site limitations, and cost.

Another law that can affect energy use in the

industrial sector is PURPA. PURPA is intended to

encourage the production of power by means of

cogeneration and the use of renewable resources,

primarily by removing the principal barrier to

electric power generation—market entry. Prior

to PURPA, utilities were often reluctant to purchase cogenerated electricity at a rate that made

grid-connected cogeneration economically feasible. Some utilities charged very high rates for providing backup service to cogenerators (for that

electricity that cogenerators could not provide

for themselves), With PURPA, utilities must purchase from and sell power to cogenerators and

small power producers at economically justified

and equitable rates. However, not all cogenerating facilities qualify for the PURPA benefits. A

qualifying cogenerating facility* must meet FERC

requirements for fuel efficiency, reliability, and

the like. Presently, the potential size and structure of the market for cogeneration and small

power production is largely unknown.

The U.S. Supreme Court recently upheld the

FERC regulations implementing PURPA that require: 1 ) utility rates for purchases of cogenerated power to be based on the utility’s “full

avoided cost, ” * * and 2) utilities to interconnect

with cogenerators and small power producers.

A Federal Court of Appeals decision had found

● A cogenerating facility, as defined by the law, is one that produces both electric energy and steam, or other forms of useful energy (such as heat), which are used for industry, commercial heating,

and cooling.

* ● The cost of power generated by conventional means that is

avoided or replaced by power from alternative energy technologies.
56 • Industrial Energy Use

that full avoided cost pricing deprives other utility

ratepayers of any share of the benefits and that

the FERC interconnection requirement violated

other provisions of the Federal Power Act. ’ 7 The

Supreme Court ruled that, while full avoided cost

pricing would not directly provide any rate savings to consumers, it would provide a significant

incentive for the development of cogeneration

and small power production, and ratepayers and

the Nation as a whole would benefit from the decreased reliance on scarce fossil fuels through the

more efficient use of energy. The Supreme Court

also held that FERC’s authority under PURPA is

adequate to promulgate rules requiring utilities

to interconnect with cogenerators and small power producers.

In an earlier decision, the U.S. Supreme Court

upheld the constitutionality of the PURPA requirement that utilities buy power from cogenerators and small power producers and upheld

the provision that exempts these facilities from

regulation as electric utilities. ’a These aspects of

PURPA had been declared unconstitutional by

a Federal district court on the grounds that they

exceeded the scope of the power granted to the

Federal Government under the U.S. Constitution. 19

Financial Incentives

Financial incentives, such as tax credits and accelerated depreciation measures, can be directed

toward encouraging the use of coal or alternative

energy sources and the adoption of conservation

projects. Since the Arab oil embargo, the political

climate has generally been favorable to the use

of financial incentives. Opposition to these measures was not directed at the concept, but at the

amount or timing of the incentive. Some critics

argued that the tax credits proposed were not

strong enough to affect energy conservation efforts or to compensate for the increased capital

outlay and technological risks associated with

I TAmerjcan E/.trjc power Service Corporation V. FERC (675 F.2d

1226 (D.C. Circ. 1982), cert. granted in Case Nos. 82-34 and 82-226

(Oct. 12, 1982).

laFecjera/ Energy Regulatory cO177mlS510n V. Mississippi, —

Us. —, 102 S. Ct. 2126 (1982).

~~MiSSiSSippi v. Federal Energy Regulatory commission (unreported opinion, U.S. District Court for the Southern District of Mississippi).

greater coal usage. Others argued that tax credits

involve the Government in the industrial decisionmaking process too heavily. What finally

emerged from this congressional debate were

several laws that provided a number of financial

incentives to industry: the Energy Tax Act of 1978

(ETA, Public Law 95-618), WPTA, and ERTA.

ETA provided a 10-percent business investment

credit for: 1 ) specified equipment, such as boilers

that use coal or alternative fuels; 2) heat conservation; and 3) recycling and shale oil equipment.

This credit could be applied to equipment placed

in service between October 1, 1978 and January

1, 1983. At the same time, the law denied a tax

credit and granted a rapid depreciation allowance

for early retirement of oil- and gas-fired boilers.

ETA also encouraged the production of additional

fuel supplies, particularly natural gas, by providing a tax credit for equipment used for the production of natural gas from geopressurized brine.

WPTA increased the tax credits for solar, wind,

and geothermal equipment from 10 to 15 percent and extended to 1985 the cutoff for granting credits. Also, the law provided a tax credit

equal to 10 percent of the cost of cogeneration

equipment and extended the tax exemption for

industrial development bonds to bonds used to

finance facilities that produce energy from

renewable resources, as long as the facility was

State-owned, backed by sufficient taxing authority, and eligible for financing by general obligation bonds,

One of the most important tax initiatives for industry is ERTA. This law simplified the tax code

for depreciation, replacing all capital retirement

categories with just four: 3 years for vehicles; 5

years for most machinery and equipment and single-purpose agricultural structures, petroleum

storage facilities, and public utility property with

a life expectancy of 18 years or less; 10 years for

recreational facilities and park structures, mobile

homes, and qualified coal conversion property

and other public utility property with a life expectancy of 18.5 to 25 years; and 15 years for

depreciable real property and public utility property with a life expectancy of 25 years or more,

Also, the law encouraged investment in both new

and used property placed in service after 1980

by establishing new credit rules: 6-percent credit
Ch. 3—industrial Energy: Uses, Technologies, and Policies ● 5 7

applies to qualified property in the 3-year depreciation class and 10 percent applies for all other

qualified property. The investment credit carryover period is extended to 15 years for credits

arising in taxable years ending after 1973. In addition, ERTA provided a 25-percent tax credit for

research and development (R&D) expenditures

paid or incurred in carrying on a trade or business, rather than in connection with a trade or

business. Eligible expenditures include supplies

used in conducting research and wages to employees performing the research. Furthermore,

ERTA reduced the tax on newly discovered oil,

and decreased the credit allowed where the cost

of energy savings is excessive or where capacity

increases as energy is conserved.

Since ERTA shortened the period in which businesses could write off investments, companies

could deduct larger amounts each year from their

corporate income taxes, thus lowering tax bills

and presumably encouraging investment. Critics,

however, point out that accelerated depreciation

would favor large businesses and would affect individual industries very differently. Furthermore,

accelerated depreciation would substantially increase certain types of distortions that exist in

present law—particularly those that favor equipment over structures. They also point out that accelerated depreciation will cost the U.S. Treasury

billions of dollars in lost revenues. Proponents,

on the other hand, say the act simplifies tax laws

and will stimulate the economy, increase productivity, and moderate inflation.20

ERTA also liberalized earlier leasing rules to

promote the sale of tax benefits—both investment

credits and depreciation deductions.

Under these new leasing regulations, a corporation who (because of small or nonexistent tax

liabilities) is unable to make use of a property’s

depreciation and tax credits can sell the property and its associated income tax credits to another

corporation, and then immediately lease the

property back for continued use. The original

owner, now a lessee, receives a downpayment

and a note for the balance. The new owner, now

a lessor, receives payments for rent and makes

payments for principal and interest on the outstanding note. Since the property never leaves

it original site, and the rental and debt payments

are equal, the net effect is that the original owner

of the equipment has sold its unusable tax and

depreciation credits for the dollar amount received as a downpayment. 21

In an alternative third-party safe harbor lease

arrangement, the lessee is not the actual owner

of the property. The new owner purchases the

property from the actual owner and then leases

it to the lessee at an annual rent that is lower by

the tax benefit amount associated with the property,22

The U.S. Treasury reported that the value of

leased property in 1981 totaled $19.3 billion.

About 84.5 percent of the tax benefits from Ieased

property went to the lessee, while 14.2 percent

was retained by the lessor. The remaining 1.3 percent covered transaction costs to third parties. 23

The Tax Equity and Fiscal Responsibility Act of

1982 (TEFRA, Public Law 97-248) modified the

safe-harbor leasing provisions of ERTA with

respect to eligibility requirements, eligible property, ACRS deductions, investment credits, and

lessee/lessor limitations.

Under prior law, the term of a safe-harbor lease

could not exceed the greater of 90 percent of the

useful life of the property or 150 percent of the

average depreciation range (ADR) midpoint life

of the property. Under the new law, the lease

term cannot exceed the greater of the recovery

period of the property or 120 percent of the ADR

midpoint life. A second change brought about

in TEFRA is that public utility property is no longer

eligible for safe-harbor leasing. A third change is

that only 20 percent of an investment tax credit

(ITC) for property in a safe-harbor lease is allowable in the first taxable year and 20 percent in

each of the four succeeding taxable years. previously, 100 percent of an ITC was allowable

when the property was placed in service. Fourth,

a lessor is not allowed deductions or credits from

20Congressional Research Service, ‘‘The Capital Cost Recovery

Act: An Economic Analysis of 10-5-3 Depreciation, ” Jan. 28, 1980,

p. 2.

ZI u .s. @pa~rnent of Treasury, Office of Tax Analysis, ~re/;mjnW

Repofl on Safe Harbor Leasing Activity in 1981, Mar. 26, 1982, p. 2.

*

z Ibid., p. 1.

231 bid.
58 ● Industrial Energy Use

safe-harbor Ieases to the extent those deductions

or credits reduce its income tax liability by more

than 50 percent. Finally, the law repeals safeharbor lease provisions for leases entered into

after December 31, 1983.

The Industrial Energy

Conservation Program

The DOE Industrial Energy Conservation Program focuses on improving the energy efficiency of the most energy-intensive processes used

in the U.S. industrial sector and on utilizing waste

heat from these processes. The DOE Office of industrial Programs administers this program, which

is divided into four subprograms.

1, The Waste Energy Reduction Program

focuses on improving energy efficiency and

on substituting abundant for scarce fuels in

processes that are common to many industries. Activities within this program include

R&D for waste heat recovery and for combustion efficiency improvements.

2. The Industrial Process Efficiency Program

focuses on increasing energy efficiency in

the most energy-intensive industries. The

areas of activity include cost-shared research, development, and demonstration

(RD&D) efforts in steel, paper, aluminum,

and textiles. Specific projects include a

dewatering process development for pulp

and paper, the identification of energy conservation potential in the chemicals and

petroleum industries, and the continuous

casting and hot inspection of steel ingots.

3.

4.

The Industrial Cogeneration Program focuses on improving and implementing advanced cogeneration systems that offer large

energy savings, while minimizing oil and gas

consumption.

The Implementation and Commercialization Program focuses on stimulating new as

well as existing, but underutilized, energy

conservation technologies in the industrial

sector. An important activity of this program

is the industrial energy efficiency reporting

program established by EPCA. That act directed DOE (then the Energy Research and

Development Administration) to rank the

top 10 energy-consuming industries and establish voluntary efficiency-improvement targets for each and a system for reporting annual progress. The National Energy Conservation Policy Act of 1978 (NECPA, public

Law 95-61 9) expanded the reporting requirements of the program to include all industries

using 1 trillion Btu per year. This program

was one of the Government’s earliest efforts

in industrial energy conservation and helped

achieve a higher visibility for conservation.

The future of the Industrial Energy Conservation Program is questionable. The Reagan administration has recommended that Federal industrial energy conservation programs be curtailed. Also, several bills were introduced in the

97th Congress to dismantle or eliminate DOE. If

that were to occur, it is not known whether the

Industrial Energy Conservation Improvement Program will be shifted to another agency.

FOREIGN INDUSTRIAL ENERGY USE AND POLICY

A useful context in which to view U.S. industrial energy use is within comparable energy use

by industries in other developed nations. * If interpreted carefully, such comparisons can indicate the potential for U.S. energy productivity im-

“Industrial energy use data are readily available only for IEA countries and not for other industrial nations such as those in South America. Hence, this discussion of comparative energy use will focus

on IEA countries.

provements in the future and help identify policies that can facilitate such improvement.

Total industrial energy and oil use by seven international Energy Agency (IEA) countries in 1973

and 1979 are shown in table 10. * Based on ratios

of energy use to per capita income, GNP, or gross

*IEA was established in November 1974 within the framework

of the Organization for Economic Cooperation and Development

(OECD) to implement an international energy program.
Ch. 3—industrial Energy: Uses, Technologies, and Policies . 59

Table 10.-lndustrial Energy and Oil Use by Representative IEA Countries,

1973 and 1979 (millions of barrels of oil equivalent)

1973 1979

Country Total use Oil use Total use Oil use

Australia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135.3 50.6 177.2 52.8

Canada. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 352.9 162.0 458.8 156.9

West Germany . . . . . . . . . . . . . . . . . . . . . . . . . . . 676.8 344.5 654.2 274.1

Italy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 386.5 234.6 344.2 164.2

Japan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,084.7 644.3 1,130.9 687.6

Sweden . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122.8 67.4 105.5 46.2

United Kingdom . . . . . . . . . . . . . . . . . . . . . . . . . . 510.7 272.7 473.1 221.4

United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,452.2 939.0 3,257.8 1,172.8

IEA total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,503.6 3,136.5 7,465.2 3,195.1

SOURCE: Energy Conservation: The Role of Demand Management in the 1980’s, International Energy Agency, 1981.

domestic product (GDP), the United States is a

highly energy-intensive nation and has been for

many years.* ln fact, among the developed Western nations and Japan, only Canada is mor e

energy-intensive than the United States.

This fact has prompted speculation that the

United States could shift to significantly reduced

Ievels of energy use without adverse impaction

economic activity. However, studies carried out

at Resources for the Future (RFF)24 point out that

intercountry comparisons are complex and that

“energy/GDP ratios taken by themselves are at

best only a partial indicator of energy conservation potential among countries or of progress in

energy conservation over time. ”25 Specifically,

RFF points out that careful attention must be paid

to differences in composition of economic output, the structure of fuel supply, the vintage of

energy-using equipment, energy prices, differences in geography and tastes, and the relative

energy intensiveness of a wide range of activities.

The RFF study concluded that approximately 40

percent of the difference between the higher U.S.

energy/GDP ratio and the lower foreign ratios

could be attributed to such U.S. structural characteristics as the large size of the United States

and its dispersed population patterns. About 60

percent of the difference arises from energy intensity differences in specific applications. For example, energy use per unit of output in a number

of manufacturing activities is higher in the United

States than in Europe (see table 11). Evidence is

accumulating that, in substantial part, such differences are due to the historically higher energy

costs seen by foreign industry. European energy

prices have generally been held above market

levels through taxation, while in the United States

they were held down through the use of controls

from 1971 through early 1981.

Under sharp increases in average real energy

prices paid by industrial users since 1973, overall

industrial energy use in the 21 IEA countries

evolved as shown in table 12. While industrial

Table 11 .—Comparative Energy Efficiencies of

Industrial Processes in Representative

IEA Countriesa

*For most countries the difference between gross domestic product (GDP) and gross national product (GNP) is relatively minor. Energy-to-GDP ratio is most often used for energy comparisons because GDP reflects only a nation’s domestic economic activity, excluding income derived from overseas enterprises and investments,

and is therefore the more appropriate national accounts measure

to which to relate a nation’s domestic energy consumption. The

U.S. GDP is virtually identical to U.S. GNP. For some nations the

GDP may be as much as 5 percent below the GNP.

24JOelDarm5tadter,joy Du nkerly, and Jack Akerman, ‘‘HOW 1‘-

dustrial Societies Use Energy: A Comparative Analysis” (Baltlmore,

Md.: The Johns Hopkins University Press, 1977).

*

s

JOY Dunkerly, “Energy Use Trends in Industrial Countries: implications for Conservation, ” Energy Po/icy, June 1980.

Petroleum

Country Crude steel Pulp and paper products

Canada. . . . . . . . 102 116 200

Italy. . . . . . . . . . . 62 59 50

Japan . . . . . . . . . 94 88 51

Sweden . . . . . . . 73 84 54

United Kingdom 88 108 81

United States . . 100 (543) 100 (579) 100 (90)

West Germany . 60 76 89

aRelative 1975 ~on~umption in Btu per ton of product; U.S consumption defined

as 100 In all cases. Actual U S consumption is 104 Kcal/ton of product shown

in parentheses.

SOURCE: “Energy TOPICS : A Periodic Supplement to IGT Highlights” (table 7),

Institute of Gas Technology, Apr. 11, 1977
60 . Industrial Energy Use

Table 12.–Changes in Industrial Energy Consumption in IEA Countries Between 1973 and 1978

Energy carrier Iron and steel Chemicals Petrochemicals Other Nonenergy uses Total industry

Absolute change: 9

Oil . . . . . . . . . . . . . . . . . . . . . . . . . . –95.3 +51 .3 + 102.6 –58.6 +29.3 + 36.7

Gas . . . . . . . . . . . . . . . . . . . . . . . . . –44.0 +22.0 —b –205.2 –227.2

Electricity. . . . . . . . . . . . . . . . . . . .

—

+7.3 –22.0 +51.3 +36.7 + 73.3

Solid fuels . . . . . . . . . . . . . . . . . . .

—

– 175.9 +7.3 — –73.3 — –249.2

Total . . . . . . . . . . . . . . . . . . . . . . –307.9 +58.6 + 153.9 –300.4 +29.3 –366.5

Percent change:

Oil . . . . . . . . . . . . . . . . . . . . . . . . . . –36.2 +28.2 + 14.2 –4.9 +4.6 + 1.2

Gas . . . . . . . . . . . . . . . . . . . . . . . . . –20.3 + 11.2 — + 14.3 – 12.6

Electricity . . . . . . . . . . . . . . . . . . . .

—

+4.1 –9.5 +854.9 +5.2 +7.0

Solid fuels . . . . . . . . . . . . . . . . . . .

—

–18.8 +19.9 — –14.1 — +17.0

Total . . . . . . . . . . . . . . . . . . . . . . –19.5 +10.0 +21.0 –7.9 +4.4 –4.9

a ln ~l~l~”sof barrelsofollequivalent.

b— indicates negligible change.

SOURCE: Energy Conservation: The Role of Demand Management in the 1980’s, International Energy Agency, 1981.

production increased by 8.3 percent between

1973 and 1978, total energy use decreased by

4.9 percent. Oil use rose slightly (l.9 percent),

mainly as a result of increases in oil use in the

petrochemical and chemical industries.

Looking ahead, primary fuel use is expected

to increase 36 percent between 1985 and 1990,

while oil use is expected to rise only 4 percent,

according to IEA projections (see table 13). However, fuel use in individual countries varies considerably. For example, while industrial oil use

is expected to decrease in the United States and

in four other IEA countries, it is expected to stay

level or increase in 16 others.

National Programs To Spur Industrial

Energy Conservation

IEA countries generally identify energy prices

and taxes as the most important targets of industrial energy conservation programs because

of industry’s sensitivity to increased costs. Thus,

almost all IEA countries have introduced a range

of other measures to complement the effects of

increased energy prices. These measures vary

from country to country, reflecting different social

philosophies and economic conditions. Some

countries place primary emphasis on voluntary

and incentive measures, while others rely on

mandatory programs. As summarized by IEA,

Table 13.-Projected Trends of Industrial Energy and Oil Use in Selected

IEA Countries Through 1990a (millions of barrels of oil equivalent)

1985 1990

Country Total use Oil use Total use Oil use

Australia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 230.6 53.6 268.3 54.2

Canada. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 557.4 146.6 640.9 137.8

West Germany . . . . . . . . . . . . . . . . . . . . . . . . . . 704.6 274.1 741.0 271.2

Italy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 404.3 160.5 441.1 140.7

Japan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,500.6 796.8 1,882.6 841.5

Sweden . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140.8 63,8 151.0 54.2

United Kingdom . . . . . . . . . . . . . . . . . . . . . . . . . 531.6 245.6 564.6 245.6

United States . . . . . . . . . . . . . . . . . . . . . ......3,553.2 1,048.2 3,940.0 945.6

Total for all 27 IEA countries. . . . . . . . . . . . . . 8,801.8 3,327.1 10,088.1 3,319.0

a[nClude9 nonenergy ‘Ses.

SOURCE: Energy Conservation: The Role of Demand Management in the 1980’s, International Energy Agency, 1981
Ch. 3—industrial Energy: Uses, Technologies, and Policies • 61

the most important measures that have been

adopted so far in IEA countries are:

● fiscal and financial incentives, to encourage

investment in energy saving techniques and, in

particular, to speed up the marketing of new

energy-saving equipment. Projects with a longer pay-back period or a high risk are generally

given priority assistance. Notable programs of

this kind are the financial and fiscal incentives

which are given in Denmark, the Netherlands,

and Sweden in order to promote energy-saving

investment in industry;

● reporting and auditing schemes, often in combination with mandatory or voluntary target setting. Information from reporting and auditing

schemes is also used to advise the various sectors of industry and to help governments formulate an energy-related strategy. For instance,

mandatory reporting of energy consumption

figures or compulsory energy audits are used

in the United States and Spain. Voluntary systems exist, for example, in the United Kingdom’s industrial Energy Thrift and Audit

Scheme;

● information activities, including advisory services, in particular to small- and medium-sized

industries. They are most effective when they

are developed and implemented in close cooperation with industry. A notable example of

this kind of program—among others—is the

Canadian National Energy Business Program

which provides computer-equipped buses to

carry out energy audits and give on-site energy

conservation advice. Canada has agreed to a

close cooperation with the European Community in order to establish similar advice systems

in Europe.

With respect to longer term RD&D programs,

a recent report prepared for the Battelle Pacific

Northwest Laboratories, which compared U.S.

industrial energy conservation RD&D programs

with those in West Germany, France, England,

Sweden, and Japan, concluded that:

The U.S. Government will probably spend

more, in absolute terms, on industrial energy conservation RD&D in 1981 than any one of the four

European countries considered.

At the same time, the U.S. Government will

spend less than any one of the four European

countries per unit of industrial activity. For example, the expenditure of Swedish Government

funds per unit of industrial activity is 22 times the

U.S. expenditure.26

These findings and others in the Battelle study

are supported by a report prepared for DOE by

DHR, lnc.27 The Battelle and DHR studies also

point out that foreign RD&D is often cost-shared

with industry to ensure the earliest possible commercialization and that project funding is seldom

awarded on a competitive basis. I n addition, foreign governments place greater emphasis than

does the U.S. Government on developing technologies for export and in encouraging conservation in industries that must compete in international markets.

Implications for the United States

An important conclusion to be drawn from

comparing U.S. industrial energy use with that

in other developed nations is that considerable

latitude exists for making U.S. industry more

energy efficient, but not to the extent that a simple comparison of energy/GDP ratios would suggest. The United States could clearly benefit from

foreign conservation research programs and

couId learn from foreign energy-using practices,

but it would be incorrect to assume that foreign

experience provides an easy path to decreased

U.S. energy use.

In addition, when historical energy cost differences are taken into account, higher U.S. energy

intensities generally do not imply economically

inefficient or wasteful practices by U.S. industry.

Rather, they indicate rational responses to socially

dictated energy price signals. Foreign experience

provides considerable evidence that energy use

is responsive to energy prices, at least over the

long run. Thus, an increase in price may have

the effect of reducing energy use, but not necessarily on a short time scale. It is this delayed

impact of higher energy prices that has led almost

all IEA countries to introduce complementary

conservation measures.

26’’Government-Sponsored Industrial Energy Conservation Research, Development, and Demonstration: A Review of Programs

in the Federal Republic of Germany, France, United Kingdom,

Sweden, and Japan,” Hagler, Bailly, & CO., Aug. 6, 1981 (BatteJJe

contract No. 6-641 54-A-H),

zTCon5ewatlon and solar Energy R&D Expenditures,. An lnternationa/ Comparison, DH R, Inc., Nov. 9, 1981 (DOE contract No.

DE-ACO1-81 CE1OO97).
.
—.——..— ——— .

Contents

Industry Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Industry Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . .

..*,*.. . . . . .

. . . . . . . . . . . . . . . . . . . . . . . ...O

Product Mix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Economics of Paper Products Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Energy and Technology. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Production Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Energy Consumption . . . . . . . . ...**** ● . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Energy Conservation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . .

.*..*.. . . . . . . .

Investment Choices for the Paper industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

lmpact of Policy Options on the Paper industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

The Reference Case . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Projected Effects of Policy Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

TABLES

Table No.

14.

15.

16.

17.

18.

19.

20.

Definition of SK 26-The Paper and Allied Products Industry . . . . . . . . . . . . . . . . .

Paper Corporations Earning More Than $1 Billion in 1981 .,*..*. . . . . . . . . . . . . .

Pulp and Paper industry Projects To Reanalyzed for internal Rate of Return (lRR)

Values . . . . . . . . . . . . . . . . . . . . . . . . . . .*..**. ● .....+. . . . . . . . . . . . . . . . . . . . . . .

Effects of Policy Options on IRR Values of Paper Industry Projects., . . . . . . . . . . . .

Overall Production and Energy Demand Trends in the Paper Industry . . . . . . . . . .,

Projected Product Mix Changes in the Paper Industry . . . . . . . . . . . . . . . . . . . . . . . .

Effect of Lower interest Rates on lRR Values of Paper industry Projects. . . . . . . . . .

FIGURES

F@mNa

11.~~~l~dustry ftevenu eat i~pitalfipe~fi~res, 1970-82 . . . . . . . . . . . . . . . . . . .

12, P~~lodustry Ernpbyrnenq 1969-?9 ● **,,.., .***..*.. . . . . . . . . . ● .,.****. ● , *

13.Materials Fkvvinanlr@gr@Al%permiti .$***.. ● ....**. . . . . . . . . .....,.0 . . .

14, 1%perlnd ustryTrends, 19724$1 ...*,** *.....*. . . . . . . . . . . . . .

15. Changing Fuel Mix in the U.S. Paper k#tiwry, 1972-81

. . . . . . . ● ..*.*.

● *4*.*. ..**.*.. . . . . . . . .

16. Comparison ofPaper lndustty EnergytJseand Production Output, 1972

wXf1981 . . . . . . . . . . . . .****.. . . . . . . . . .4.,.... . . . . . . . . . . . . . . . . . . . . . . . . ,

17. Paper industry Energy Intetwiif%ojectkm, 1970-2000 . . . . . . . . . . . . . . . . . . . . . . . .

18. Paper industry Projections of Fue#LJse and Energy Savings, 19%land 2000.... . .

.

65

65

66

66

67

67

71

73

73

75

75

77

65

66

74

75

76

76

80

WJ

67

68

72

72

73

77

7a
—

Chapter 4

The Pulp and Paper Industry

INDUSTRY OVERVIEW

The pulp and paper industry is the 11th largest

manufacturing industry in the U.S. industrial sector, but is the third largest energy consumer. Unlike other industries, however, the pulp and

paper industry can generate a large percentage

of its energy needs through the use of wood residue. As a result, the industry is in a unique position to reduce its purchased energy costs, as well

as its vulnerability to fuel shortages and/or disrupt ions.

As the world’s largest producer of paper and

board, the U.S. paper* industry accounted for

roughly 35 percent of the world’s total output and

produced over 62 million tons of paper and board

products in 1981. The value of industry shipments

in 1981 dollars totaled over $35 billion. ’ In addition, the United States has the highest per capita

paper and board consumption in the world.

Industry Structure

The paper and allied products industry, classified under SIC heading 26, includes firms that

produce and market pulp, paper and paperboard, packaging, and building paper and board.

The subgroups of this industry are listed in table

14.

This report focuses on the three most energy-intensive industries within this SIC group: pulp,

paper, and paperboard mills. Although building

products and lumber are not examined further

in this chapter, it is important to remember that

the pulp and paper industry is closely tied to, and

is becoming integrated with, these industries. Accordingly, management and investment decisions

are often based on strategic business criteria that

extend beyond making pulp and paper.

The paper industry is generally organized into

integrated and non integrated mills. Vertical in-

*The word 1‘paper ‘‘ is used as shorthand for “pulp and paper’

throughout this report. Also, the term “ton” is shorthand for the

more precise, “air -dryed ton. ”

1 U .S, Department of Commerce, U.S. /ndustria/Out/ook 7982,

p. 45,

Table 14.—Definition of SIC 26—The Paper and

Allied Products Industry

SIC 26 includes the manufacture of pulps from wood and

other cellulose fibers and from rags; the manufacture of paper

and paperboard; and the manufacture of paper and paperboard into converted products such as paper coated off the

paper machine, paper bags, paper boxes, and envelopes.

SIC 26 contains the following subgroups:

SlC Title

261 . . . . . . . . . . Pulpmills

262. . . . . . . . . . Papermills, except building papermills

263. . . . . . . . . . Paperboard mills

264. . . . . . . . . . Converted paper and paperboard products

except containers and boxes

265. . . . . . . . . . Paperboard containers and boxes

266. . . . . . . . . . Building paper and building board mills

SOURCE: Office of Management and Budget, Standard Industrial Classification

Manual, 1972.

tegration (i.e., producing raw materials as well

as finished products) is common among the companies in the paper industry because various industry activities are often complementary. Vertical integration often begins with timber, the

most common raw material, and culminates i n

distribution centers that assure finished product

outlets. Integrated mills start with raw timber,

which is processed onsite into finished paper.

Nonintegrated mills either: 1) produce marketable pulp from raw timber, or 2) secure pulp from

available markets and convert it into finished

paper products. Based on the 1977 Census of

Manufactures data, about 80 percent of U.S.

market pulp originates in nonintegrated mills and

about 20 percent in integrated mills,2

Currently in the United States, 400 companies

operate more than 1,000 papermills and pulpmills. s Since World War 11, the U.S. paper industry’s primary productive capacity has been

progressively concentrated in large new mills

located in the South: roughly 65 percent of pulping capacity and 50 percent of papermaking capacity are now below the Mason-Dixon line. The

secondary or converting sectors of the industry,

‘I bid., p. 40.

3Directory of the Paper and Allied Products Industry, Lockwood

Publishing Co., 1981.

65
66 . Industrial Energy Use

on the other hand, locate plants close to large

metropolitan markets throughout the United

States.4 5

The paper industry has a relatively low level

of concentration. No company has captured

more than 10 percent of the market. Efficient production of paper can be done at a mill throughput

of 300 tons per day. (The largest mill, Union

Camp, located in Savannah, Ga., produces 3,000

tons per day.) This wide range of efficient production is one of the reasons the industry remains

fragmented. Table 15 lists a number of corporations that earned over $1 billion and used at least

1 trillion Btu of energy for the production of pulp,

paper, or paper products in 1981.

Product Mix

The products of the paper industry are extremely varied. While paper has retained its traditional

uses throughout the centuries—newsprint, writing

papers, tissues, etc.— new uses and applications

are continually evolving. The growth of the industry during the past few decades has been due

largely to new applications and uses of paper and

paper-based materials.

Economics of Paper Products

Production

Product Demand

Because the paper industry has a wide spectrum of end products, its growth patterns closeIy resemble those of the general economy. While

some sectors of the product mix are more closely related to changes in industrial activity, others

are more directly affected by changes in levels

of personaI income or by demographic factors.

Combined overall consumption of paper and

board has closely tracked the changes in the gross

national product (GNP).67

4U. S. Industrial Outlook, 1982, op. cit., p. 39,

‘H. N. Hersh, Energy and Material Flows in the Production of

Pu/p and Paper, Argonne National Laboratory Publication ANL/

CNSV-10, February 1981.

6U.s. /ndustrja/ Outlook 1982, op. cit., p. 40.

7U. S. Industrial Outlook 1982, op. cit., p. 39.

Table 15.—Paper Corporations Earning

More Than $1 Billion in 1981

Revenues

Corporation (in billions) Employees

Georgia Pacific . . . . . . . . . . . . . . . . $5.02

International Paper . . . . . . . . . . . . . 5.00

Weyerhaeuser. . . . . . . . . . . . . . . . . . 4.53

Champion International . . . . . . . . . 3.75

Crown-Zellerbach . . . . . . . . . . . . . . . 3.07

Mead Corp. . . . . . . . . . . . . . . . . . . . . 2.71

St. Regis . . . . . . . . . . . . . . . . . . . . . . 2.71

Kimberly-Clark Corp. . . . . . . . . . . . . 2.60

Scott . . . . . . . . . . . . . . . . . . . . . . . . . 2.08

Union Camp . . . . . . . . . . . . . . . . . . . 1.57

44,000

46,000

49,000

42,300

32,000

25,000

29,700

31,200

20,800

16,097

SOURCE: Standard and Poor’s Register of Corporations, Directors and Executives, vol. 1, 1983.

Capital Investment

Sales, profits, and retained earnings were high

in the 1970’s when the industry operated close

to a supply/demand balance, an important factor in the performance of a capital-intensive industry. This approach led the industry to invest

substantial and increasing amounts of its revenue

in new capital, an amount that rose from 8 percent in 1970 to over 11 percent in 1980. However, in the face of high interest rates, a depressed timber market resulting from few housing starts, and the like, this ratio has declined

slightly (fig. 11),

Like other manufacturing industries, the paper

industry is very sensitive to environmental regulations on air and water quality. Between 1973 and

1970 1972 1974 1976 1978 1980 1982

Year

SOURCE: American Paper Institute,
.—

Ch. 4—The Pulp and Paper Industry . 67

1981, the industry reportedly spent a total of

$37.6 billion to comply with these regulations.

The added capital requirements for new pollution abatement facilities, mainly centered in

pulping activities, increased the capital-intensive

character of the industry. B

Imports and Exports

In 1981, the U.S. paper industry, a major exporter of pulp and paper products, exported

some 3.7 million tons of pulp valued at $1.8

billion (current), and an estimated 4.43 million

tons of paper and board valued at $2.18 billion

(current). 9 In the same year, the United States also

imported almost 10 million tons of pulp and

paper products, relying heavily on newsprint and

pulp imported from Canada. In the past 2 years,

however, the margin of the U.S. paper industry

trade deficit has narrowed because of relatively

larger export volumes and an upgraded export

product mix.10

High prices for energy and raw materials have

forced Western European and Japanese producers to cut their production capacity. Japanese producers, for example, plan to phase out 1.1 million

8U.S. Industrial Outlook 1982, op. cit., p. 45.

9U.S. Industrial Outlook 1982, op., cit., p. 39.

10U.S Industrial Outlook 1982, op. cit., p. 44.

tons of paper industry capacity by 1985 because

of huge increases in the prices of wood chips imported from the United States and of oil imported

from Indonesia and the Middle East. This decline

in foreign production capacity has opened up

new export markets for U.S. papermakers, thereby providing a cushion against domestic demand

fluctuations.

Employment

Employment in the paper industry has been

very steady over the last 10 years. Both sales and

tonnage have risen during this time, so the flat

employment profile can be attributed to automation of the mills with its corresponding increases

in worker productivity (see fig. 12).

Figure 12.—Paper Industry Employment, 1969-79

800 t 1

750 “

650 r

---

1989 1971 1973 1975 1977 1979

Year

SOURCE: Argonne National Laboratory, Energy and Materials Flows in the Production of Pulp and Paper, May 1981

ENERGY AND TECHNOLOGY

Production Processes

Paper is made by separating the cellulosic fibers

in wood and then removing the Iignin that binds

the fibers (pulping). The cellulose fibers are usually further conditioned–often by bleaching and

refining—before being interlaced in sheets. Finally, water is removed from the sheets by mechanical pressing and the application of heat, leaving

the final product, paper (see fig. 13). Many small

companies use purchased pulp to begin their

paper forming process.

The following is a brief description of the major processes in the paper manufacturing process,

including energy’s role. It should be noted that

process control is included under its own heading

because it covers all phases.

Pulping

Pulping is energy-intensive, using about 4.5 million Btu per ton (MMBtu/ton) of paper. Commercial pulping operations are of three principal

types: mechanical, full chemical, and semichemical.11 The method of pulping used by a mill depends on the input (kind of trees) and the desired

output (products). Within these constraints, the

I I McGraw.Hill Encyclopedia of Science and Technology, vol. 9.

1977, p. 609.
68 . Industrial Energy Use

Figure 13.—Materials Flow in an Integrated Papermill

Sto

departrnent~- A

Digester — f -

Chip Bark

storage storage~ ,

~ Cookin g

– }

liquor

+

~ ‘

y Chipping Barking-,,,, 4

Screening

— discharge >~ - ‘~

.

Wood storage Short

wood Wuuu

SOURCE: National Science Foundation

- A - Cooking chemical

dryers

pulping processes on the basis of energy and raw

material costs, as well as utilization rates, labor

intensity, and ancillary costs, such as pollution

control.

Mechanical pulping involves the reduction of

wood to fibrous states by purely mechanical

means. In the traditional stone groundwood pulping, logs are first ground into pulp by large revolving grindstones, while water is sprayed against

the stone to control the temperature and carry

away the resulting pulp. Except for a few watersoluble components, all the constituents of the

wood remain in the pulp; thus, the yield of pulp

may be nearly 95 percent of what was originally

in the tree. Thermomechanical pulping (TMP),

which uses pressurized disk refiners i n conjunction with heat and occasionally chemicals, is replacing the standard groundwood process fairly

rapidly. It requires more purchased energy, and

its yields are slightly lower than with conventional

groundwood pulp, but the very important property of pulp strength is nearly that of semichemical pulp. Moreover, the process can use residual

chips from sawmills and plywood plants as its raw

material.

Full chemical pulping employs chemicals to

separate cellulose fibers from other wood components. Wood chips are cooked with chemicals

in an aqueous solution, usually at elevated temperatures (1 70° C or 350° F) and pressures, to
Ch. 4—The Pulp and Paper Industry . 69

dissolve Iignin and other compounds and leave

the cellulose intact and in fibrous form. Dry pulp

yields are in the range of 40 to 60 percent of

wood dry weight. The kraft, or sulfate, process

is the chemical puIping process most extensively employed. It uses sodium hydroxide (NaOH)

and sodium suIfide (Na2S) to solubilize the Iigni n.

Almost any wood species can be pulped by this

process.

Semichemical pulping is relatively new. It involves softening the wood with mild chemical action and then mechanically grinding it into pulp.

Semichemical pulping is employed largely, but

not exclusively, on deciduous wood species.

Significant processes in pulping include TMP,

alkaline-oxygen pulping, and continuous digesters. Although TMP requires more energy to produce a ton of pulp than does the conventional

groundwood method, it is likely to be used by

the industry because it produces higher product

quality and lower overall cost. On the other hand,

alkaline-oxygen pulping uses only about half the

energy as the conventional pulping and bleaching

process and has the advantage of less sewage

waste and the potential to recover more of the

chemicals used. Unfortunately, it produces a

weaker pulp than does the standard kraft process.

The continuous digester uses approximately 60

percent of the steam required by batch digesting

systems. Because it also produces a higher quality, uniform pulp, its adoption within the industry

is spreading. Its only disadvantage is its high cost

of maintenance.

Bleaching

Pulp must be bleached if it is used to make

white paper. The object of bleaching is to render

the pulp white without degrading the cellulose,

Some grades of paper need not be bleached at

all (such as corrugated cardboard boxes), while

others (newsprint) are given only light bleaching.

Better grades of printing and writing papers require bleaching.12

Almost all bleaching is carried out with chlorine

or chlorine compounds, leaving an effluent containing high levels of chemicals that must be

12Ibid

99-109 0 - 83 - 6

Photo credit International Paper Co.

Wood chips and chemicals are cooked in continuous

digesters which break down the wood fiber so that it can

be made into pulp and paper

biologically degraded at a sewage treatmen t

plant. In addition, bleaching is an energy -

intensive step that requires 5 MMBtu/ton of paper

and increases the energy intensity of papermaking by 20 percent. Accordingly, mills have become attentive to ways to reduce energy and

chemical losses in the bleach plant.

A number of new bleaching technologies are

available to the industry, and some others are

under development. Again, as with pulping, these

new technologies have both advantages and disadvantages that have to be weighed before their

adoption. Most of the new bleaching methods

(e.g., the Rapson process, displacement bleaching, and compact bleaching) all appear to have

the advantages of reduced energy consumption,

and some have the added advantage of using less

chemicals. On the other hand, some of these

technologies suffer from deficiencies such as extremely high maintenance costs and corrosion.

Some have not yet been proven in the American

marketplace.
70 . Industrial Energy Use

Refining and Repulping

The refining process is the stage of stock preparation that occurs after bleaching but before

papermaking. During this stage the proper mixture of pulp types is blended. Recycled wastepaper also enters the paper stream at this stage

for repulping. During refining, the unmodified

cellulose fibers (obtained from pulping) are

separated, crushed, frayed, fibrillated, and cut.

They imbibe water and swell, becoming more

flexible and more pliable.

The major energy source in the refining and

repulping operations is electricity, which is used

to operate motors. The primary way to conserve

energy would therefore be to install newer and

more highly efficient electrical motors.

Papermaking

In forming paper, up to 95 percent of the water

has to be removed from the cellulose mixture.

This process is the single most energy-intensive

process in the entire papermaking operation, requiring up to 40 percent of the total energy used.

Paper sheets are made by depositing a cellulose

mixture, with a consistency of less than 1 percent cellulose solids suspended in water, on a

continuously moving screen and subjecting it to

one of the following three methods for removing the water: the Fourdrinier process, the cylinder machine, and the twin-wire former. 13

In the Fourdrinier process, a dilute (water content of 99 percent or higher) suspension of cellulose fibers is sprayed under pressure onto a moving wire screen. As the slurry travels away from

the spraying point, it passes over several suction

devices that cause water to drain through the

screen. As water is removed, a wet sheet is

formed. The wet sheet is transferred to a supporting felt, which carries it through a series of press

rolls. There, water is squeezed out and the sheet

progresses to the dryer section. The remaining

water is removed by evaporation as the sheet

passes over a series of steam-heated cylindrical

dryers which expose alternate sides of the sheet

to hot dryer surfaces.

‘ ‘I bid,, p. 610.

A second papermaking technique involves use

of a cylinder machine to make multilayer paperboard. It differs from the Fourdrinier process only

in the forming. I n place of the moving screen are

one or more rotary cylindrical filters. Each screencovered cylinder is mounted in a vat where it operates partially submerged in the dilute papermaking slurry being supplied to it. As the cylinder

revolves, water drains through the screen to the

interior of the cylinder and a wet sheet is formed.

The sheet is removed at the top of the cylinder

and may be joined to other wet sheets from adjacent cylinders to form a thicker, laminated sheet

or board. The press section and dryer processes

are essentially the same as those following the

Fourdrinier process.

The third major sheet-forming device is the

twin-wire former, which is an outgrowth of the

Fourdrinier process. Here the sheet travels vertically between wire screens that contact both

sides of the sheet, forcing water out in both

directions.

It is far more expensive to remove water thermally in the dryer section than physically in the

press section or screen, because evaporation is

much more energy-intensive. New techniques to

increase moisture removal include such items as

twin-wire forming and extended nip presses,

where savings of up to 0.5 MMBtu/ton, or more,

are possible. However, in some instances, it is

possible to damage the cellulose fibers by excessive squeezing.

Another technology being developed is the

high-consistency forming of paper, where the

cellulose content is raised from below 1 percent

to 3 or 4 percent, consequently reducing the

water that has to be evaporated. Several other

technologies have been developed for facilitating

the removal of moisture on the machine, including drying hoods, fans, and other devices designed to remove the evaporated moisture from

the proximity of the paper so that further moisture

can be evaporated. These developments notwithstanding, the basic design of the papermaking

machine itself has changed little over the last 100

years.
Ch. 4—The Pulp and Paper Industry “ 71

Recovery Operations

Chemical pulping processes also entail a recovery cycle in which valuable chemicals are reduced and returned to the digester. After digestion of pulp, a black liquor is drained off that consists of Iignin, spent chemicals, and water. In a

device (unique to the paper industry) called a recovery boiler, Iignin carried within the spent pulping liquor is burned as fuel to generate steam

while the sodium compounds used in pulping

and beaching are recovered and reused. The considerable amount of energy produced in a recovery boiler and used in the recovery cycle has motivated some new conservation technologies.

The recovery cycle of a papermill may be as

simple as a bark boiler at a groundwood mill or

as complex as the Rapson process in a kraft mill.

In the conventional kraft mill, the centerpiece of

the recovery activity is the recovery boiler, which

burns the organics (mostly Iignin) as a black liquor, whi Ie recovering the valuable sodium chemicals.

Unfortunately, the black liquor, with its high

water content (85 percent), will not burn. In order

to reduce the water content in the black liquor,

multieffect evaporation systems, with their high

inherent coefficients of performance, have been

adopted. Vapor recompression is starting to make

inroads, although this technology is highly dependent on the cost of the electricity required

to drive the system.

Process Control

Process control is a computerized monitoring

and control of process variables that can save

energy and materials and improve efficiency in

almost every aspect of the paper industry. For example, either batch or continuous digesters are

installed with a computerized process control system as standard equipment, and in the bleach

plant, a process control system can increase uniformity of the bleached pulp. Moreover, process

controls improve the throughput of the papermaking machine and have saved 1 to 2 percent

of the total drying energy as well.

However, process control applications in paper

are Iimited because the most important measurement points are often in harsh or inaccessible environments. For this reason, cooking rates in the

digester (which contains a mixture of wood chips,

chemicals, and steam) have been very difficult

to measure, but research among instrument manufacturers continues to focus on this. optimum

cooking rates would produce higher quality pulp

with minimum expenditure of energy and time.

For other control tasks where the necessary measurements have been achieved, productivity has

risen in every case.

Unified control, which coordinates and schedu Ies component processes, is now catching the

attention of the paper industry. Its chief advantage is the reduction of overall production costs.

Although this system is now available from control system vendors, the introduction of full mill

control is progressing only gradually because of

its large cost.

Energy Consumption

Energy consumption in the paper industry varies from year to year and from region to region.

The total energy consumed in any given year is

determined by a variety of factors, including availability and price of fuel, product mix, and capacity utilization. In 1981, the pulp and paper industry consumed 2.15 Quads of energy, one-half

of which was internally generated from wood residues.

According to the American Paper Industry

(API), during the period 1972-81 the paper industry’s percentage of internally generated energy

rose from 40.5 to 50 percent. Figure 14 shows

this improvement clearly. As fossil fuel prices continue to escalate, more waste recovery programs

will be introduced or expanded, and the industry

will likely become even more self-sufficient.

Already, many paper companies now find it economical to use the bark of the logs at the mill for

fuel. Likewise, more and more sawdust is used

as fuel,

The amount of energy purchases from utilities

or other fuel suppliers is down by 6 MM Btu/ton

from the 1972 levels, also shown in figure 14.

Total purchased energy for 1981 was about 1.06

Quads. The latest API figures show that natural

gas is the leading purchased fuel, followed by

coal and residual oil (see fig. 15). The fuel used
—-—— ——

60

o 

.- i d -

1

. I

1,000

900

800

700

SOURCE: American Paper Institute

I-i-’ .- -

‘end in the foreground i s

Ction ‘ y Stem” ‘ehind’ ‘ooms ‘he ‘ecovew

boiler, which can meet a significant

burning ‘aste ‘rem ‘he ‘“’ ping ‘reces s
Ch. 4—The Pulp and Paper Industry • 73

in a particular mill is determined by the availability and cost of energy in a region.

Fuels are used by pulpmills and papermills to

generate steam or electricity, large quantities of

which are used to produce paper. The amount

of energy needed to produce a ton of paper from

be broken down more precisely by process and

by product. The most energy-intensive step in

papermaking is the drying process, followed by

pulping and bleaching.

Not surprisingly, many mills have the capacity

to cogenerate electricity. The paper industry has

in place approximately 3.5 billion watts of cogeneration capacity, virtually all of which is in the

form of steam turbine generators.14

Energy Conservation

As part of the Department of Energy’s Office

of Industrial Programs effort, the paper industry

adopted a VOlUntary goal of 20-percent reduction

in energy consumed per ton of product by 1980.

According to API, by 1981, the industry was using

23.3 percent less purchased energy, while at the

same time, productivity had increased by almost

20 percent. This is shown clearly in figure 16.

Many of the new pulp and papermaking processes and their associated equipment offer great

potential for saving even more energy. Because

new processes and equipment require large capital outlays, the rate at which conservation technologies are deployed will be largely dependent

on the paper industry’s ability to raise capital.

Given the steep fuel price rises of the 1970’s,

and their maintenance or escalation in the 1980’s,

it is safe to assume that energy conservation will

continue to play a major role in the paper industry. Perhaps the greatest potential for reducing

14Ibid., p. 609.

Figure 16.—Comparison of Paper Industry Energy

Use and Production Output, 1972 and 1981

200 ‘

180 —

1972 1981 g

-

—

-

— —

Energy Production Energy Production

use use

Coal Petroleum Natural

gas

Electricity and Self-generated Production

steam energy index

I 1

SOURCE: American Paper Institute

oil and gas consumption in the paper industry

lies in increasing the industry’s use of wood residue as fuel for the integrated producers. For

those firms that produce paper from purchased

pulp, such fuel sources do not exist. Instead, their

improvements will come from more efficient production.

INVESTMENT CHOICES FOR THE PAPER INDUSTRY

In general business operations, the paper in- and maintain or improve its profitability to its

dustry is similar to other industries. It strives to shareholders. It attempts to preserve its asset

maintain reasonable cash flow, and its investment values, maintain creditworthy balance sheets,

strategies are designed to preserve the company and, of course, produce profits. However, al-
74 . Industrial Energy Use

though the individual paper companies are basically dependent on the same raw material inputs, their end products and markets are extremely diverse. These products can range from heavy

linerboards to fine writing papers to tissue paper.

This diversity further increases divergent subjective and objective opinions of management, for

the marketplace of one major forest products

company could be completely different from the

marketplace of another.

In one respect, the paper industry could be

considered slightly different from other industries.

The major pieces of equipment used in this industry have exceedingly long lifetimes. Fifty years

is considered a reasonable retirement age for a

lime kiln, and some parts of paper machines running now are over 100 years old. Therefore, investment decisions in the paper industry are often

viewed over much larger horizons of time than

in other industries.

There are a number of possible investment opportunities in energy conservation and other

areas for the paper industry that appear financially

attractive (see table 16). OTA reviewed eight such

investments, ranging from those made specifically

to save energy, to those with the secondary benefit of saving energy, and finally to those that do

not save energy and, in fact, compete with energy-saving technology for corporate investment

dollars. Furthermore, the opportunities examined

provide examples of discretionary expenditures

to satisfy very short-term problems and to remove

bottlenecks, as well as capital expenditures to install new machinery or to initiate a research and

development project to increase market share.

Table 16.—Pulp and Paper Industry Projects To Be Analyzed for Internal Rate of Return (lRR) Values

1,

2.

3.

4.

Inventory control-A computerized system can keep track

of product item availability, location, age, and the like. In

addition, these systems can be used to forecast product

demand on a seasonal basis. The overall effect is to lower

inventory, yet maintain the ability to ship products to

customers with little or no delay. In typical installations,

working capital costs are dramatically reduced.

Project life—5 years.

Capital and installation cost–$560,000.

Energy savings—O directly, but working capital could be

reduced by $1.2 million.

Electrlc motors. —The primary use of electric motors i n the

paper industry is in paper machine operations. In this

analysis, OTA has assumed that five aging electric motors

will be replaced with newer, high efficiency ones.

Project life—10 years.

Capital cost and installation cost–$35,000.

Energy savings–$16,000 per year at 4¢/kWh.

Lime kiln replacement —Replacement of an aging unit

which thermally converts calcium carbonate waste

chemical back to chemical oxide (lime) suitable for further

chemical processing of pulping liquors.

Project life—20 years.

Capital and installation cost—$11 million.

Energy saving—$1 million in first year.

R&D project. -A hypothetical research effort to develop

a new paper-coating process.

Project life—3 years.

R&D costs—$1.4 million.

Plant construction cost at end of 3 years of development—

$57 million.

Energy savings—O directly but new market could generate

$50 million per year in increased profits.

5. Pulpmill cogeneration pro]ect.—lnstallation of a

6.

7.

8.

—

turbogenerator unit to recover electrical power from steam

production facility. Superheated steam is produced at 600

psi and then passed through a mechanical turbine to

generate electricity. The turbine exhaust, which is 175 psi

steam, is used then for normal plant production.

Project life—10 years.

Capital and installation cost–$231,000.

Energy savings—$72,300 per year,

Continuous digester. —Equipment for new, innovative

process for generating pulp.

Project life—20 years.

Capital and installation cost—$27 million.

Energy savings—$3.7 million in first year.

Computerized process control —The most common retrofit

purchases being made for industrial systems are

measuring gauges, controlling activators and computer

processors. The main accomplishment of such a process

control system is to enhance the throughput and quality

of a chemical production plant with only materials and

small energy inputs.

Project life—7 years.

Capital and installation costs–$500,000.

Profit savings—$150,000 per year.

New papermaking machine.—A new pulp processing,

papermaking facility including buildings, machinery, and

installation.

Project life—20 years.

Capital and installation costs—$350 million.

Energy savings—O directly, but profits could be

increased by $60 million per year.

NOTE: All projects are assumed to be financed from equity. Fuel is assumed to rise in cost slightly faster than inflation. Depreciation follows the ACRS schedule,

and there is a 10 percent general investment tax credit, but no energy tax credit.

SOURCE: Office of Technology Assessment.
—

Ch. 4— The Pulp and Paper Industry • 75

These projects can be ranked according to several criteria, among which are the internal rates

of return (IRRs). As shown in the reference case

column of table 17, the project with the highest

rate of return, 90 percent, is inventory control.

Project IRR values descend thereafter to a low

of 13 percent with the new papermaking machine. Thus, if one were to invest purely on the

basis of maximizing returned moneys to a corporation and its shareholders, the inventory control project would be the first one undertaken.

However, there are other criteria by which projects can be ranked. For instance, the project that

saves the greatest amount of energy per dollar

invested is the replacement of the electric motors.

And if one were to rank the projects based on

the total energy saved, the continuous digester

would come out on top, with a savings in energy

equivalent to over 80,000 barrels of oil per year.

However, its $11 million cost is by no means insignificant and illustrates the point that those projects that save large amounts of energy have large

costs associated with them as well.

Table 17.—Effects of Policy Options on IRR Values of Paper Industry Projects

IRR with policy option

Reference ACRS 10-percent $1/MMBtu tax on natural gas

Project case removed EITC and petroleum products

Inventory control . . . . . . . . 90

Electric motors . . . . . . . . . 47

Lime kiln . . . . . . . . . . . . . . 31

R&D (no R&D credit) . . . . 28

Continuous digester. . . . . 21

Process control . . . . . . . . . 20

Cogeneration . . . . . . . . . . . 15

Paper machine ... , . . . . . 13

90

47

28

26

20

20

13

12

90

52

34

28

21

25

18

15

90

50

32

28

25

22

15

-r. 13

NOTE: All projects are assumed to be financed from equity.

SOURCE: Office of Technology Assessment

IMPACT OF POLICY OPTIONS ON THE PAPER INDUSTRY

This section of the report describes the projected impact of each of the legislative options

described in chapter 1. Although the projections

for total fuel use and overall energy efficiency in

the pulp and paper industry are included, the

goal of this section is to present comparisons of

each policy option with a reference case. The reference case projections are predicated on a series

of product growth-rate assumptions and energy

price assumptions, previously shown in tables 2

and 3 of chapter 1. The basic premise is that industrial electricity prices will remain constant for

the last 15 years of this century, while petroleum

and natural gas prices will rise at an overall rate

of approximately 2.1 percent per year.

The Reference Case

OTA’s model projection of the volume of shipments and energy demand in the puIp and paper

industry is shown in table 18. There are several

interesting points to be noted on the table. First,

total energy is projected to rise at about 1 percent per year from its 1980 level of 2,180 trillion

Btu to approximately 2,620 trillion Btu in the year

2000. Purchased energy will decline slightly from

52 to 47 percent, owing primarily to the increased

use of coal and electricity. However, purchased

fuel use per ton of paper will likely decline from

its 1980 level of 20 MMBtu/ton to a level of 11.6

MMBtu/ton by 2000, as shown in the last column

of table 18.

Within the paper industry the three major

means of pulping wood (i.e., chemical, semichemical, and mechanical) were projected to

maintain the approximate pulping percentages

they now enjoy. However, recycled pulp is expected to grow from its 1980 level of 23 percent

of total pulp production to 25 percent by 2000,
76 ● Industrial Energy U s e

Table 18.—Overall Production and Energy Demand Trends in the Paper Industry (Reference Case)

Paper Total Purchased Purchased/ Total Purchased

shipments energy energy total energy MMBtu/ton MMBtu/ton

Year (million tons) (trillion Btu) (trillion Btu) (percent) of output of output

1980 . . . . . . . . . . . . . . . . . . . . 63.8 2,180 1,130 52 34.2 20.1

1985 . . . . . . . . . . . . . . . . . . . . 71.2 2,150 1,100 51 30.2 15.4

1990 . . . . . . . . . . . . . . . . . . . . 82.0 2,280 1,140 50 27.8 13.9

2000. . . . . . . . . . . . . . . . . . . . 106.1 2,620 1,230 47 24.7 11.6

Average growth rate,

1980-2000 percent

per year . . . . . . . . . . . . . . . 2.54 0.92 0.42

SOURCE: Office of Technology Assessment

since the supply of virgin pulpwood appears to

be unconstrained.

The mix of products produced in 1980 in the

paper industry is shown in table 19, along with

the products’ anticipated growth rates. Comparing the 1980 (actual) and 2000 (projected) product slates indicates that printing and writing

papers will increase their percentage, while construction, paperboard, and packaging percentages will decline. This is a trend seen in other industries that have a higher growth in the more

value-added products and a fall-off in production

of basic commodity products.

OTA analysis of the impact of each legislative

option is illustrated with the data on IRR calculations shown in the legislative option columns

of table 17. In this exercise, IRR calculations are

initially made for each project in the series, assuming reference case conditions of equity financing, accelerated cost recovery system (ACRS)

depreciation, etc. Then IRR values are recalculated under the conditions of the legislative options. Several points should be noted about the

projects listed and the numbers calculated.

First of all, the IRR fails to consider the other

questions that go into making a decision about

each project. For instance, notwithstanding the

tremendous savings in energy efficiency that

would come about in the lime kiln replacement,

there is no way in which an energy saving of $1

million a year can, by itself, justify a $11 million

expenditure. However, in this instance (based on

a real case), the firm was faced with expenditures

of $4. o million to overcome pollution problems

and a cost of $1.0 million necessary for repair of

the existing kiln facility. While energy savings certainly increased the attractiveness of the new kiln,

the about-to-be-imposed Federal environmental

restrictions on the existing facility were felt by

management to be the main motivating factors.

IRR calculations also fail to show the magnitude of the risk associated with the new papermaking machine. A new facility costing $350 million, no matter how high its IRR value, would be

closely scrutinized from a strategic standpoint.

The economics of this type of project depends

highly on such factors as the perception of market

demand and product competition. The cost of

energy plays a secondary role.

Table 19.—Projected Product Mix Changes in the Paper Industry

1980 Relative

product ion growth rate Product mix (O/O\

(million tons) (0/0 per annum) 1980 2000

Newsprint a 

. . . . . . . . . . . . . . . . . . . . . . 4.67 –0.5 7 7

Printing and writingb . . . . . . . . . . . . . 15.60 1.3 24 31

Packaging . . . . . . . . . . . . . . . . . . . . . . 5.54 – 1.4 9 7

Tissue . . . . . . . . . . . . . . . . . . . . . . . . . . 4.30 –0.2 7 7

Paperboard. . . . . . . . . . . . . . . . . . . . . . 30.95 –0.3 49 45

Total . . . . . . . . . . . . . . . . . . . . . . . . . 63.62 100 100

a

The growth in domestic production incorporates a correction for relatively declining imports.

bCoated papers are about 30 percent of this category.

SOURCE: Office of Technology Assessment.
Ch. 4—The Pulp and Paper Industry ● 7 7

Strictly speaking, cogeneration falls in the category of discretionary investment and can be

viewed as a technology installed entirely to

reduce energy costs, although if the electricity

network is poor in an area, it could also carry

some economic value in security of supply. Compared to a discretionary investment with a lower

rate of return (e.g., the continuous digester), it

does not necessarily follow that the cogeneration

facility would take preference. Much depends on

the marketplace and whether bottlenecks in production are more important to management than

is a reduction in energy costs. Here again, the

highest return on investment may not necessarily attract the corporate dollar.

In the case of the process controller on a paper

machine, different functions are involved. Process controllers may be designed either to increase

machine speeds and therefore output or to produce a uniform quality, saleable product, thereby

reducing waste and increasing output. A reduction in energy use inevitably occurs when a process control system is installed—e. g., if less waste

were produced, the energy input per ton of saleable output would also be reduced,

The case of the electric motors illustrate an important point concerning replacement of existing

equipment. If a motor must be purchased, and

the choice is between a standard model or a highefficiency one, the investment in the latter produces an IRR of 46.6 percent. However, if the

existing motors need not be scrapped, and replacement is to be justified purely on energy savings, the return on investment would drop to 14.6

percent, which includes the targeted tax credit

favoring the high-efficiency motors. Even if the

existing motors were to be replaced in 5 years,

the IRR would reach only 18 percent, which includes the investment tax credit of 10 percent.

All economic justification for this type of project

must thus be realized from the savings in electrical energy.

It is obvious from this example that energy savings alone cannot overcome the financial realities

associated with prematurely scrapping equipment. Therefore, even though the energy savings

per dollar invested are the highest of all the

technologies discussed in this section of this

report, it is unlikely that replacement of existing

motors would be high on the list of any paper

company’s discretionary spending investments.

The point here is not to discount IRR calculations, but to illustrate that other factors besides

the return can enter into the decision whether

or not to undertake a project.

Projected Effects of Policy Options

The following sections illustrate the projected

effects of the four policy options in comparison

with changes in energy demand and energy intensity in the reference case. Figures 17 and 18

present a graphical overview of the impact of

these policies.

Two things are immediately apparent in the diagrams. First, as shown in figure 17, the average

energy intensity for the paper industry (in million

Btu per ton) is projected to decline from its present level of about 35 to a level of 26 in 2000. And,

as shown in figure 18, the amount of fuel used

is expected to increase to 2,620 trillion Btu over

the same time period. That is, the trend of the

industry, assuming the fuel prices originally

shown in table 2, will be toward more efficient

production of paper.

Option 1: Removal of Accelerated

Depreciation

The passage of Public Law 97-34 in August 1981

brought several significant benefits to industry.

Figure 17.—Paper Industry Energy Intensity

Projection, 1970-2000

1970 1975 1980 1985 1990 1995 2000

Year

SOURCE. Office of Technology Assessment
78 • Industrial Energy Use

Figure 18.—Paper Industry Projections of Fuel Use

and Energy Savings, 1990 and 2000

Fuel Use Projections

Natural

3.0

Oil Coal Purchased

electricity

I 1990

2.5

t

2.0

1.5

1.0

0.5

0.0 1

Ref No EITC Btu Cap

case ACRS tax avail

Self-generated

energy

I 1

2000

Ref No Btu EITC Cap

case ACRS tax avail

Fuel Savings Projections

1.0 I

Recovered Cogenerated

0.9 energy energy

0.8

0.7

0.6

I

1990

0.4 L

[ I

2000

Ref No EITC Btu Cap Ref No Btu EITC Cap

case ACRS tax avail case ACRS tax avai I

SOURCE. Office of Technology Assessment.
.

Ch. 4— The Pulp and Paper Industry ● 7 9

For the paper industry, the new rules put buildings into a 10-year depreciation lifetime category,

and all pulping and papermaking equipment into

a 5-year category. This is in contrast to the

previous situation wherein this equipment would

be in the 15- to 20-year lifetime.

If the ACRS were removed, OTA analysis indicates that the effect on energy use would be minimal. Total energy use wouId increase from a projected level of 2,820 trillion to 2,840 trillion Btu,

an overall change of 0.7 percent. This would occur because ACRS allows a corporation to defer

its tax liability, but does not remove the obligation.

Table 17 illustrates the effect of this policy option on the IRR of the eight paper industry projects described previously. OTA analysis using

these IRR calculations indicates that none of the

eight projects shifted their positions relative to the

other projects. Each project changed the I RR value only 1 to 3 percentage points. Overall, removal of ACRS would make slightly less money

available for corporate use, but that the effect on

paper industry energy intensity would be negligible.

Option 2: Energy Investment Tax Credits

The second policy option, a targeted energy

investment tax credit (EITC), would be used by

corporations to offset a part of their Federal income tax. In the paper industry, the items benefiting most from such tax credits would be cogeneration systems and computer control systems

for either steam boilers or paper production.

Large units such as digesters, whose primary purpose is other than to save energy, will not, in all

likelihood, qualify for a tax credit, The existing

list of qualified equipment will also include heat

recovery equipment, evaporators, and black liquor preparation systems.

In conducting its analysis, OTA found that all

corporations take advantage of tax credits that

are available to them, but in no instance was a

tax credit found to be the deciding influence in

whether or not to undertake an energy efficiencyimproving project.

As illustrated in table 17, when this option is

applied to the reference case, only one of the

projects moves up in position. The process controller moved ahead of the continuous digester

by 4 points. Investing in the continuous digester

undoubtedly results in a significant increase in

capacity, whereas a process controller most likely

results in an increase in the efficiency with which

existing equipment is used, One means making

more pulp, while the other means making better pulp. The influences on the first project reflect

management’s perception of the demand of the

market for more product, or, in the second case,

for a better product. A tax credit, while not without impact, is only one factor influencing the

choice between the two projects.

Previously in figure 18, OTA presented its analysis of the impact of a tax credit on total paper

industry fuel use and overall energy efficiency.

As shown in the EITC case compared to the reference case, there is projected a slight drop in

total energy demand from 2,819 trillion to 2,809

trillion Btu in 2000. Most of that would come from

decreases in natural gas use. Energy intensity of

the paper industry is projected to be virtually unchanged, i.e., 24.7 MMBtu/ton in both the

reference and EITC cases.

Overall, OTA analysis indicates that the influence of a small EITC on the paper industry would

not be significant.

Option 3: Tax on Premium Fuels

Of the four industries examined in this study,

paper uses by far the most self-generated energy.

Wood residue produced 50 percent of the energy

used in pulp and paper production in 1981. This

trend toward self-generation of energy has been

in existence for at least the past decade, which

means that purchased energy now used by this

industry cannot be easily supplanted by selfgenerated energy.

Thus, the premium fuels tax option does not

have much impact on fuel use patterns. As shown

in figure 18, the impact would be greatest on

natural gas, where consumption is forecasted to

decrease 7 to 8 percentage points. However,
80 ● Industrial Energy Use

since natural gas accounts for only 20 percent of

the fuel used by the paper industry, the impact

of the natural gas decrease on total energy use

is small. OTA analysis does indicate a slight decrease in cogenerated electricity production with

a Btu tax, since much of the commercially available cogeneration equipment is based on natural

gas use.

The use of TMP processes would be influenced

by a premium fuels tax to the extent that utilities

are dependent on these fuels to produce electricity, since electricity is the main source of

energy for TMP processes. The Pacific Northwest

has seen a dramatic rise in the price of its hydroelectricity, from $0.005 to $0.03 per kilowatthour. The initial impact of this energy price rise

has been to make Canadian pulp more attractive.

A Btu tax on gas and oil would cost the paper

industry approximately $600 million annually,

which would translate to an approximately $7/

ton increase. Much of this would be passed on

to customers of the industry, but it is not clear

that all can be.

The effect on the IRR of a fuel tax of $1 .00/

MMBtu is shown in table 17. Comparison of the

case with the Btu tax case shows that the largest

gain was with the continuous digester, where the

IRR value increased from 21 to 25 percent. However, as noted previously, many factors enter into

the decision to build a continuous digester facility. The fact that the energy consumed by an existing batch digester is subject to a tax will not

by itself motivate a company’s managers to invest in a new continuous digester. But, if the

batch system must be replaced, a tax may contribute to the decision to upgrade the system.

The overall result is that the fuel tax is not

enough to reorder the priorities of this collection

of projects. Although the fuel-intensive projects

advanced in the I RR with a sudden increment in

price, they did not advance enough to displace

higher ranked projects. Of course, it would be

possible to pick a different slate of projects that

shows more motion, The conclusion by OTA for

the paper industry is that a fuel tax of $1 .00/

MMBtu will not solely be effective in motivating

energy conservation investments.

Option 4: Low Cost of Capital

OTA analysis indicates that capital is constrained in the paper industry not so much by the

interest rates charged by commercial institutions

for loans, as by the overall economy and the ability of firms to sell their products. As discussed in

chapter 2, capital for investment in energy projects or any other project comes from a combination of borrowing and net profits. There are many

things that can decrease a company’s capital pool

size if that pool is derived mainly from internal

funds. To the extent that internal funds are used

for capital investment, interest rates will have no

effect on whether a project is undertaken. However, in many companies the interest rate is used

as the discount rate in IRR calculations, and so

interest rates may affect IRR values.

In many firms, the capital pool is comprised of

a combination of internal and borrowed funds.

In these cases, there is the opportunity for interest

rates to influence the decision of whether to invest in a project or not. However, OTA has found

that even here, the decision is comprised of many

factors besides energy conservation and the cost.

The eight paper industry projects illustrate quite

well the small change that would be exhibited

by the IRR calculations for this policy option. For

these calculations, OTA assumed that the projects were financed by one-third equity moneys,

and two-thirds debt funding (see table 20). The

first column shows what the IRR value is when

Table 20.—Effect of Lower Interest Rates on

IRR Values of Paper Industry Projectsa

10% inflation, ACRS, 10°/0 ITC)

IRR with

Reference case policy options:

IRR with interest rate

Proiect 16°/0 interest rate of 80/0

Inventory control . . . . . . 389 373

Electric motors . . . . . . . . 75 79

Lime kiln . . . . . . . . . . . . . 47 52

Process control . . . . . . . 33 41

R&D (with 25°/0 credit). . 34 35

Continuous digester . . . 22 23

Cogeneration. . . . . . . . . . 17 20

Paper machine . . . . . . . . 13 17

aProjects are assumed to be two-thirds debt financed and one-third equity

financed,

SOURCE: Office of Technology Assessment,
Ch. 4—The Pulp and Paper Industry ● 8 1

the interest rate is 16 percent, while the second

presents these same calculations with an 8 percent interest rate. I RR values rise by 4 to 5 points

in each case, * which is in the range of uncertainty

for these projects. And, not only do the projects

rise only a small amount, but also none of the

projects changes place.

Figure 18 shows the OTA projections on fuel

use under the terms of this legislative option. Of

the four options, this one is projected to have the

greatest effect. Energy use would drop from 2,81

*Except for inventory control, which goes down because the computer control saves working capital. When interest rates drop, the

carrying charges on the working capital also drop, and therefore

profitability drops slightly as well.

Quads in 2000 to 2.67. Much of that would result

from increases in the recovered energy now being sent up stack gas flues and sent to thermal

waste streams, and in cogenerated energy derived from waste fuel sources. This improved

energy use comes from increased market penetration of relatively capital-intensive conservation

and cogeneration technologies and is projected

to cause a 15-percent drop in natural gas and

petroleum use. Additionally, the growth in total

electricity demand, owing to increased penetration of electrical technologies at the expense

of generally less efficient, fossil fuel technologies,

and the increased penetration of conservation devices cause overall energy consumption to decline while the product slate remains the same.
Chapter 5

The Petroleum Refining Industry

Photo credit American Petroleum Institute and Exxon Corp.
———— -

-.— — . —

. . 4

~ . ‘ .

- Contents . . ,

Page

Industry Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Industry structure........,. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85

Product Mix . . .... .... . . . . . . . . ..... ● ... ...... . . . . . . . . . . 86

Economics of Refining .. ....,. . . . . . . . . . . ● .... . . ... . . 88

imports and Exports ....... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

Trends and Uncertainties.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..... 90

Energy and Technology.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

Production Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

. . . . . . .

Kinds of Refineries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

Energy Use . . . . . . . . . . . .; . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95

Energy Conservation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

Potential for Energy Saving . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

Technologies for lncreased Energy Efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

Proven Technologies for Energy Conservation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

New Concepts in Refinery Energy Use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

Investment Choices for the Refining industry . . . . . . . . . . . . . . . . . . . . . ......... . . . . 104

Capital Expenditures in the oil lndustry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104

Other Investment opportunities ● P. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105

impacts of Policy Options on the Petroleum Refining Industry . . . . . . . . . . . . . . . . . . . . 107

The Reference Case . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107

Projected Effects of Policy Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 110

TABLES

Table No.

21. Definition of SIC 29-The Petroleum Refining and Related Industries . . . . . . . . . . . . 85

22. Petroleum Refining Corporations Earning More Than $16 Billion in 1981 . . . . . . . . 86

23. Products Manufactured in SIC 29, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87

24. Process Plant Construction Cost,1972 and 1982. . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

25. Comparison of 1972 and 1981 Energy Consumption in Petroleum Refining

Industry. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

26. Petroleum Refining industry Projects To Be Analyzed for lnternal Rate of Return

(lRR) Values . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108

27. Projected Changes in Petroleum Refining Production Between 1985 and 2000.... 110

28. Effects of Policy Options on lRR Values of Petroleum Refining Industry Projects.. . 111

29. Effect of Lower interest Rates on lRR Values of Petroleum Refinery Industry

Projects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

FIGURES

Figure No. Page

19. Employment Trends in Petroleum Refining lndustry,1970-82 . . . . . . . . . . . . . . . . . . 89

20. Topping Refinery Model Configuration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

21

22

23

24

25

26

27

Hydroskimming-Refinery Model Configuration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

Complex Refinery Model Configuration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

Alliance Refinery Energy Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

Comparison of Petroleum Refining Industry Energy Use and Production Output

1972 and 1981 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

Diagram of Atmospheric Fluidized-Bed Combustion Boiler/Combustor

Arrangements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103

Petroleum Refining Industry Projections of Fuel Use and Energy Savings by

Policy Options 1990 and 2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109

Petroleum Refining Industry Energy Intensity Projection, 1970X)00. . . . . . . . . . . . . 110
Chapter 5

The Petroleum Refining Industry

INDUSTRY OVERVIEW

The petroleum refining industry uses the largest

quantity of premium fuels in the industrial sector, amounting to 2,7 Quads in 1981. ’ It is second only to the chemicals industry in the total

amount of energy it consumes. Classified under

SIC 29, the petroleum refining industry is defined

as the group of establishments engaged in refining petroleum, producing paving materials, and

manufacturing lubricating oils. Its official description is shown in table 21.

This industry faces a future that bears little resemblance to its past. Previously, the firms that

made transportation fuels for the United States

had access to large quantities of high-quality

crude oil. Now, they must use less desirable highsuIfur crude oils as feedstocks. The petroleum

product market is changing as well. Environmental considerations require production of highoctane, unleaded gasoline, instead of gasoline

with lead added to improve fuel quality.

In addition, the costs of fuel have risen to such

levels that overall demand for refining products

is projected to decline over the next two decades.

Thus, the management of firms in SIC 29 finds

itself in the unenviable position of having to make

sizable capital investments in an industry whose

product will be in less demand.

1 American Petroleum I nstltute, Energy Et’t’/c/ency /rnpro~’emenl

and Recot ered ,W]tcr\al L’tlllzatlon Report to U.S. Department ot

Energ}, June 10, 1982, p 2.

Table 21 .—Definition of SIC 29—The Petroleum

Refining and Related Industries

This major group includes establishments primarily engaged in refining petroleum, manufacturing of paving and

roofing materials, and compounding lubricating oils and

greases from purchased materials. This SIC group contains

the following subcategories:

SlC Title

291 . . . . . . . . Petroleum refining

295. , . . . Paving and roofing materials

299. . . . . . . . Miscellaneous products of petroleum and oil

SOURCE Office of Management and Budget, Standard Indusfrlal Classification

Manual, 1972

Finally, the refining process is becoming more

complex as demand increases for high octane,

unleaded gasoline. Crude petroleum, as found

in nature, must be processed (refined) to remove

impurities and to manufacture such usefuI materials as gasoline, jet fuel (kerosene), and fuel

oil. In the early days of the petroleum refining

industry, simple distillations were used to produce desired gasoline and kerosene products,

with up to so percent of the crude oil feedstock

being discarded. In recent years, this industry has

made a great deal of effort to increase the yield

of high octane products, minimize waste, and improve the overall quality of the product produced.

Industry Structure

The U.S. petroleum refining industry now consists of approximately 270 refineries owned by

162 companies.2 Refineries are located in 40 of

the sO States. Refining capacity is located in areas

known as Petroleum Administration for Defense

(PAD) districts. Major concentrations of refining

capacity exist in PAD districts 2 (Great Lakes and

Midwestern States), 3 (Gulf Coast), and 5 (Pacific

Coast). PAD district 1 (East Coast) has less refining capacity, a deficiency made up for by pipeline

and tanker shipments from the Gulf Coast and

by imports, primarily of residual fuel oil, from

foreign Western Hemisphere refineries,3

.

As of January 1, 1982, the operating refineries

in the United States had a total crude-running

capacity* of about 17.7 million barrels per day

(bpd), representing about 27 percent of the refining capacity of the non-Communist world.4 Processing from around 1,000 bpd to over 600,000

bpd, refineries range from “fully integrated” comZlbld., p. 6.

J/nrernatjona/ ~etro/eum Encyclopedia, J. C. McCasli n (cd. ) (Tulsa,

Okla.: The Petroleum Publishing Co., 1981).

*The size of a refinery IS normally expressed as Its “crude capacity, ” meaning the number of barrels that can be “run” each day

through its atmospheric distillation units.

‘Amercian Petroleum Institute, Basic Petro/eum Data Book, January 1983.

85
86 • Industrial Energy Use

plex plants, capable of producing a complete

range of petroleum products, to small, simple

refineries that can produce only straight-run distillates, heavy fuel oils, and sometimes asphalt.

Small (less than 75,000 bpd) refineries make up

about 60 percent of the total number of refining

units, but their combined capacity is only about

24 percent of the total throughput. * In terms of

ownership, the four largest companies have

about 38 percent of the total refining capacity,

and 20 companies have about 77 percent of the

total refining capacity. 5 The top 10 firms are

shown in table 22.

There is no single, accepted method of categorizing the structure of the U.S. petroleum refining industry that captures the similarities and differences in refineries related to processing capabilities, access to feedstock supplies, ability to

market, and the like. One grouping is:

1. Large, integrated, multinational companies

typically have worldwide production, refining, and marketing operations in addition to

their activities in the United States. A number

of these firms are descendants of the Standard Oil companies created when Rockefeller’s Standard Oil trust was dissolved in

1911.6 These major oil producers have typically had access to assured supplies of crude

oil from the Middle East and other producing areas of the world. Such guaranteed sup-

*Throughput–the total amount of crude oil initially processed.

‘Oil and Gas Journal, “Refining Capacity Dips on Broad Front, ”

vol. 81, No. 12, Mar. 21, 1983, p. 84.

6U.S. House of Representatives, Committee on Energy and Commerce, U.S. Refineries: A Background Study, July 1980.

2.

3.

A

plies of crude oil are diminishing as governments of the producing countries increasingly take over responsibility for disposing of

their crude production. As a consequence,

many of the U.S. multinational oil producers

find that their domestic activities–including

refining—are becoming more important to

their financial health. These companies, with

their sophisticated high-volume refineries,

provide the bulk of the products manufactured through complex processing steps.

Large- and medium-sized domestic refiners

make up a diverse group of companies.

Some are fortunate in being largely self-sufficient in domestic production of crude oil.

Others depend for their crude supply on

some combination of long-term contracts

and “spot” purchases. * They have much

less total refining capacity than do the major firms, but a number of them are significant marketers in their own regions.

Independent refiners form the most diverse

group of all. Most independent refiners are

small, domestic companies. Refining is their

principal operation; most do not produce

crude oil and do not market their products

under their own names.

Product Mix

petroleum refinery is a complex assembly of

individual process plants interconnected with piping and tanks. Each plant has a specific function,

*Spot purchases are those made by refiners on the open market

and without benefit of a contract.

Table 22.—Petroleum Refining Corporations Earning More Than $16 Billion in 1981

Revenues

Corporation (in billions) Employees

Exxon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $110.06 137,000

Mobil Oil. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60.33 82,000

Texaco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57.63 66,728

Standard Oil of California (Chevron) . . . . . . . . . . . . . . . . . . . . . 46.61 43,000

Standard Oil (Indiana) (Amoco) . . . . . . . . . . . . . . . . . . . . . . . . . . 31.73 58,700

Atlantic Richfield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28.75 54,200

Gulf Oil Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.17 53,300

Shell Oil Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.60 37,273

Conoco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.29 34,500

Phillips Petroleum Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.29 34,500

SOURCE” Standard and Poor’s Register of Corporations, Directors and Executives, vol. 1, 1983
Ch. 5— The Petroleum Refining Industry . 87

and each refinery has been built to process a certain type of crude oil (or “slate” of crudes) to produce the products required for a defined market.7

Markets for specific products change constantly, and existing refineries are modified or new

refineries are built to accommodate such

changes. In recent years, Government regulations, subsidies, and other influences (to be

described later) have greatly affected both refinery operations and the construction of new

refineries.

Refineries convert crude oils into a broad spectrum of products, most of which are fuels. A simple grouping of refinery fuels would include liquefied petroleum gases, gasolines, jet fuels, diesel

fuels, distillate heating oils, and residual fuel oils.

Refineries processing heavy crude oils may also

produce asphalt and coke (see table 23). Refineries vary greatly in their size, processing complexity, and abiIity to use crude oiIs of differing characteristics.

The Mellon Institute, The /ndustrla/ Sector Technology Uw

,\k)de/, Ilnal report, \ol. ‘3, The f’etro/eurn Refi”n/ng /ndustry, April

1982

An important aspect of the U.S. refining industry is its ability to produce basic petrochemicals—

feedstocks for the manufacture of a wide variety

of plastics, synthetic fibers, paints and coatings,

adhesives, piping, and other products of modern

society. Basic petrochemical materials manufactured by the U.S. refining industry from

petroleum fractions and natural gas include such

large-volume commodities as ethylene, methanol, and benzene and other aromatics. Until recently, it appeared that U.S. refineries couId look

forward to increasing markets for these materials. Now, however, the picture seems much less

bright because the industry appears to be “overbuilt” for current market demands.8 Recent studies have concluded that current worldwide ethylene capacity is adequate to meet demands at

least through 1985.9

8

0il and Gas journal Mar. 21, 1983, op. cit., p. 85.

‘Chemical and Engineering News, “Saudi Arabia Set To Emerge

as Factor in World Marketplace for Chemicals, ” Dec. 20, 1982,

p. 65.

Residual fuel oil

Aviation jet fuel

Petrochemical feedstocks

15

6

5

Table 23.—Products Manufactured in SIC 29

Percentage of total

Product manufactured 1980 production Definition of product and uses

Gasoline 39 A refined petroleum distillate, normally boiling within the ranges of

30 to 300 C, suitable as a fuel in spark-ignited internal combustion

Distillate fuel oils

engines.

18 A general term meaning those intermediate hydrocarbon liquid

mixtures of lower volatility than that of kerosene, but still able to be

distilled from an atmospheric or vacuum distillation petroleum

refining unit. Used as boiler fuel in industrial applications, and as

home heating fuel.

The material remaining as unevaporated liquid from distillation or

cracking processes. Used mainly as boiler fuel in powerplants,

oceangoing ships, and so forth.

Specially blended grades of petroleum distillate suitable for use in jet

engines, These fuels have high stability, low freezing points, and

overall high volatility.

A broad term encompassing those refinery products, having typically

low molecular weight and high purity (ethylene, propylene, and

acetylene, which are used as feedstocks in chemical production of

everything from food additives to textile fibers.

Liquefied petroleum gases 4 Light hydrocarbon material, gaseous at atmospheric pressure and

room temperature, held in liquid state by pressure to facilitate

storage, transport, and handling. consists primarily of propane and

butane. Used in home heating.

Kerosene 2 A refined petroleum distillate, intermediate in volatility between

gasoline and heavier gas oils used as fuels in some diesel engines.

Often used as home heating fuel.

Other products 11 Includes items such as petroleum coke, petroleum solvents,

lubricating oils and greases, asphalt, and the like.

SOURCE American Petroleum Institute Data Book, published 1979, and National Petroleurn News, December 1980
88 . Industrial Energy Use

Economics of Refining

The economics of refining is now undergoing

major changes. Existing refineries were built and

expanded during a period of steady increase in

market demand, accompanied by continuous,

but moderately paced developments in refinery

technology. The large integrated companies profited by the total price spread between their lowpriced crude oil and the sales of refined products.

Non integrated companies with access to crude

oil supplies profited by refining this crude oil and

disposing of the products in largely “unbranded”

bulk markets. Others, without crude oil supplies

of their own, but able to purchase crude oil on

favorable terms, developed specialized refineries

to supply regional markets, such as an Air Force

base or commercial airport.

During these years of expansion, refinery operating costs were not considered critically important. Many in the industry were content to

look at the “big picture” of the total spread between cheap crude costs and income from finished product sales. The cost of the refining operation, although certainly not insignificant, was

only one of many costs in the series of steps between crude oil exploration and production and

the delivery of products to the final consumer.

The industry’s profits came from high volumes

of oil moved through the entire system, and refineries did what was necessary to keep this flow

going.

Now the picture is changing. Some essential

features of these changes can be summarized:

1.

2.

3.

As product demand has leveled off or even

decreased, the refining industry finds itself

with more capacity than it can use. Many

predict that this decrease in demand reflects

a long-term trend.

Existing refineries, faced with the recent escalation in energy costs and the increasing

need to break even or show an operating

profit, are being forced to look much harder

at ways to decrease operating costs, such as

the more effective use of energy in refining

processes.

“Margin a]” refineries, those that are expensive to operate or are poorly located with

4.

5.

respect to crude oil or markets, are being

shut down—some temporarily, others for

good. Although some employees will be

transferred, most will be permanently laid

off when a refinery closes.

Even if an individual company’s market prospects or improvements in technology suggested that major new refinery process plants

should be built, construction costs have escalated to the point that such new facilities

i n the United States would face capital carrying charges that would make it difficult to

compete with existing refineries having surplus capacity. The increase in construction

costs in the past 10 years for the three types

of refineries are illustrated in table 24.

As a final deterrent to new “grass-roots” construction, siting problems—including the inevitable vigorous local environmental concerns—when coupled with increased costs,

make it unlikely that a new refinery could

be built in marketing areas where the capacity is needed (such as the Northeastern

United States).

From the foregoing it appears safe to conclude

that construction of a major new U.S. refinery

is unlikely in the foreseeable future. Instead, the

emphasis will largely be on adapting existing refineries to the changing patterns of crude supply

and product markets (described in a subsequent

section).

Employment

Employment in SIC 29 as a whole, or in SIC

2911, the petroleum refining industry itself, has

been remarkably stable over the past decade. The

trend, as shown in figure 19, exhibits the slight

decrease during the 1972 and 1979 oil disruptions, but overall employment has been maintained at approximately 150,000 jobs.

Table 24.—Process Plant Construction Costs,

1972 and 1982 (thousands of dollars/bpd)

1972 1982

Topping refineries . . . . . . . . . . . . . . . . . . . . . . 540 1,60 0

Hydroskimming refineries. . . . . . . . . . . . . . . . 940 2,80 0

Complex refineries. . . . . . . . . . . . . . . . . . . . . . 1,600 4,800

SOURCE Refinery Flexibility—An Inferim Report of the National Petroleum Council, VOI 1, December 1979
Ch. 5—The Petroleum Refining Industry • 89

1970 1972 1974 1976 1978 1980 1982

Year

SOURCE Annual Survey of Manufacture and Census of Manufacture.

Production Costs

The operating costs of refineries are generally

closely held figures. These costs depend greatly

on the size and complexity of a specific refinery.

They are normally expressed in terms of dollars

per barrel of crude unit throughput. Such figures

can be misleading, however, because larger,

more complex refineries will incorporate process

plants used for the relatively expensive processing required to make a few specialty or highly

refined products. Simple topping refineries—and

especially those of medium to large size—will

have relatively low processing costs per barrel,

but the value of their products will be correspondingly low in comparison to the much

broader range of products from a more complex

refinery. 10

Capital Investment

For a further perspective on the economics of

the oil industry, it is important to recognize that

about 70 percent of capital spending in a typical

SIC 29 firm goes for exploration and production

activities. ” Petroleum refining capital budgets

must compete for the remaining 30 percent of

available funds with petrochemicals manufacturing, marketing, oil and gas pipelines, and other

activities.

In considering the ability of the refining industry

to raise funds for new capital expenditures, including those for energy conservation, it should

also be recognized that the profitability of the

refining industry appears to be very questionable

in the immediate future.12 Because U.S. refineries

are operating well below capacity, there is a

downward pressure on refined product prices

that will prevent many refiners from passing on

to their customers all their costs, including crude

cost .

As a final observation on the subject of oil refining economics, it should be recalled that since

the early 1960’s, the industry has been under various types of controls intended to aid—i e., subsidize—small refiners. Under the original crude

import control system of the 1960’s, small refiners

were given special allocations of “import tickets”

that they could sell to large refiners who import

their own foreign crude. In August 1971 additional subsidies for small refiners were put into

effect.13 These included price controls on domestic crude oil, crude entitlement biases, small refinery set-asides for military businesses, guaranteed small business loans, U.S. royalty crude preference sales, naval petroleum reserve set-asides,

mandatory crude allocations, and exemptions of

small refiners from the scheduled phasedown of

lead-octane additives.

As one result, this subsidy program established

extremely attractive investment opportunities for

very small, simple refineries, and many were

quickly built. Very few of them could produce

gasoline, and many used high-quality crude in

the simple production of fuel oil instead of producing higher quality products. However, as of

January 1981, all price and allocation controls

were removed from crude oil and petroleum

products.

Imports and Exports

Prior to the removal of price and allocation

controls in January 1981, U.S. refiners were largely protected from foreign competition by a system

of crude oil and product price controls.14 This

10Natlona I petroleum Cou nci 1, Refinery F/exibi/ity, prepared for

the U.S. Department of Energy, Washington, D. C., 1980, p. 18.

I I standard 01 I CO, of California, 1980 Annual ~eport.

120;/andGas]ourna/, Mar. 21, 1983, OP. cit., P. 85.

I jNational Petroleum Cou nci [, op. cit., p. 24.

14U .s. House of Representatives, Committee on Energy and Commerce, U.S. Refineries: A Background Study, July 1980.
90 • Industrial Energy Use

program resulted in an average raw material cost

for U.S. refiners that was below the price foreign

refiners had to pay for their crude. As domestic

crude oil price controls were phased out, the raw

material cost advantage of the U.S. refiners began

to disappear. The decontrol action eliminated the

remaining advantage.

With its access to crude oil at worldwide competitive prices and an efficient domestic product

distribution system, a vigorous U.S. refining industry should have little reason to fear foreign

competition. All that seems to be required at this

point is close monitoring by both Government

and industry of the expansion of export refineries

around the world, together with a continuing

evaluation of how they might affect the U.S. refining industry if no control were exercised.

Refineries in Venezuela and the Caribbean

area, for example, now supply somewhat over

1 million bpd of product to the U.S. market.15

However, residual fuel oil makes up most of these

imports. These refineries have relatively little

capacity to make gasoline and other light products, and it seems unlikely that they will invest

in the very considerable conversion programs

necessary for producing significant amounts of

gasoline, jet, and diesel fuel to be marketed in

competition with underutilized U.S. refineries.

Existing European refineries have considerable

unused processing capacity, but to reach the U.S.

market they must face the expensive transportation of refined products in small tankers. (The

vessels of “supertanker” and larger size cannot

practically be used to transport the mixed cargoes

of light products that would be required in such

movements.) Another major disadvantage faced

by European refiners is the growing predominance of unleaded gasoline in the U.S. markets.

Unleaded gasoline of high octane is manufactured only in the United States. It appears most

unlikely that European refiners could afford to invest in the additional catalytic reforming and

other processes necessary to provide unleaded

gasoline just for their share of the U.S. market.

In the long run, a more serious threat is production from very large petrochemical plants be15National Petroleum Council, op. cit., P. 223.

ing built in areas where the basic raw materials

are less costly (or will be made available by local

governments at prices well below U.S. costs).

Such plants are being built in Canada, Mexico,

and—most significantly—the Middle East. 16 Several such plants are being built at Jubail and Yanbu, in Saudi Arabia, by Saudi Government agencies and by joint ventures between these agencies and large foreign firms. These plants have

been promised feedstocks and fuel at costs of

only a fraction of world market prices. Although

the plants are remote from current world markets,

the industry anticipates that their low manufacturing costs will permit them to enter such markets, to the detriment of current producers. An

analysis of transportation costs and potential

markets indicates that finished products from

newly constructed Middle East refineries will go

primarily to Western Europe, presenting additional problems to the already depressed European refining industry. Another possibility is that

the Middle East governments (notably Saudi

Arabia) may require their crude oil purchasers

to buy some refined products in order to be allowed access to crude oil.

Trends and Uncertainties

Refineries in the United States are experiencing drastic changes in the business atmosphere

in which they operate. Available crude oil supplies are deteriorating in quality, motor gasoline

use has been dropping sharply from historic

highs, markets for many products are leveling

out or declining, and Government-mandated

changes (e.g., requirements for low-sulfur fuel oil,

increasing use of unleaded gasoline, and the ultimate phaseout of leaded gasolines) require increasingly sophisticated and costly refining operations.

Refining capacity has probably peaked for the

foreseeable future. Investment in refinery process

plants will continue to be made, as necessary,

to handle the growing amounts of heavy crude

oil and the greater relative demand for unleaded

gasoline of (perhaps) steadily rising octane number. The additional energy requirements of these

16Chemical and Engineering News, Op. cit.
Ch. 5—The Petroleum Refining Industry • 91

new processes may affect the industry’s ability

to continue the recent trend toward more energyefficient processing.

Details of these trends are discussed under the

following topics and in subsequent sections of this

analysis.

Crude Supply Uncertainties.– If the volumes

of foreign crude oil imported into the United

States continue to decrease, the industry and the

Nation may become unjustifiably complacent

about the perceived dim in ishing dependence on

foreign crude oil. Short-term or even longer interruptions in the availability of Middle Eastern

crude always remain a possibility.

Crude Oil Prices.–Crude oil prices quadrupled

during the Arab oil embargo of 1973-74 and more

than doubled again during the Iranian crises of

1978-80, in the early 1980’s, worldwide crude

oil prices declined as a result of production overcapacity and lowered demand. ’ 7 It is not clear

what will happen to crude oil prices. Political

upsets in the Middle East could result in crude

oil embargoes or physical interruptions in crude

oil availability, with consequent skyrocketing of

prices worldwide. Also, reductions in crude oil

prices, if unaccompanied by significant increases

in production, couId have a shattering effect on

the economies and possibly on the internal stability of several of the highly populated, oilproducing nations.

Changing Crude Mix.–Much of the older refining capacity in the United States was designed

to process crude oil of low sulfur content and medium-to-high quality. Available supplies of these

crude oils are dwindling, both in the United States

and elsewhere. Those OPEC countries having reserves of both light and heavy crudes are requiring their customers to take quantities of both

types, instead of merely “lifting” predominantly

the more desirable light crudes.18

As a consequence of this changing crude oil

mix, U.S. refiners are being forced to make major investments in additional processes and new

I TU ,s. Depar(rnent of Energy, Energy Information Ad m i n istratlon,

Short-Term .Ertergy Out/ook, Washington, D. C., February 1983, p. 5.

18.;/ and ~a5 )ourna/, “surviving the Shakeout: Refining and Marketing In the Elghtles,” Oct. 26, 1981.

facilities. These facilities involve heavy fuel oil

desulfurization and coking, together with processes to recover the light ends given off in the

coking operation. Modifications to permit processing heavy crude oil can be quite costly and

energy-intensive. One U.S. refiner, for example,

has announced a $1 billion program to modify

its Gulf Coast refinery so that it can process the

Arabian heavy crude oil that it will be required

to take as part of its share of ARAMCO* production.20

Changing Product Demand.–The declining

demand for refined products in the United States

since 1978 seems permanent and is primarily a

response to higher prices, the current lower level

of economic activity, and the gradual introduction of more fuel-efficient small cars.21 Also, the

trend of the refinery process mix will probably

be away from motor gasolines and toward middle-distillate fuels. Yet it is not at all clear how

much the U.S. demand for refined product will

decline before it rises again (if it does). One major

uncertainty is the response of the American motorist to the belief (not necessarily valid) that the

days of skyrocketing motor fuel prices are over.

It has been suggested that: 1) a period of level

motor fuel prices will result in an increase in driving, with a correspondingly greater demand for

fuel; and 2) motorists will not accept the small,

fuel-efficient automobiles predicted for the next

decade, but will instead turn back to larger, more

comfortable and more powerful vehicles.

Residual Fuel Oil Demand.–Since residual

fuel oil, as normally produced, is high in sulfur,

environmental restrictions have reduced its use

by utilities and industry. Its place has been taken

by natural gas, distillate fuel oil, and coal. Thus,

the demand for residual fuel oil is now declining. Current demands are for about 1.8 million

bpd, resulting in increased needs for refinery fuel

oil desulfurization and coking.22 The rate at which

~~oj[ and Gas ]ourna( “Petrochem Units Benefit From integration, Flexibility, ” Apr. 11, 1983, p. 100.

*Arabian American Oil Co-consortium of American and Saudi

Arabian oil companies, formed in the 1920’s to ftnd and process

crude oil In the Middle East.

Zostanda rd Oil CO. of California, 1981 Arrnua/ Report.

z I u s Depa ~rnent of Energy, Energy I nformatlon Administration, ,.

Short-Term Energy Outlook, Washington, D. C., February 1983, p.

24,

221 bid., p. 26.
92 • Industrial Energy u se

the demand for residual fuel oil decreases will

be affected by natural gas usage policy and prices

and by the rate at which major users of residual

fuel oil can convert to coal in environmentally

acceptable ways.

Motor Gasoline Upgrading.–Regardless o f

how the demand for motor gasoline changes, it

is expected that unleaded gasoline—now over 50

percent of the refinery gasoline output—will comprise 100 percent of the market within 10 years.23

it is also possible that gasoline octane numbers

will continue to inch up in response to requirements for more efficient automobile engines, as

well as to motorists’ desires for better performance. The production of high-octane, unleaded

23National Petroleum Council, op. cit., p. 52.

gasoline requires more complex and energyintensive refinery processing. These complex facilities often require significant investments, while

contributing nothing to the crude throughput of

a refinery. In fact, the gasoline yield per barrel

of crude oil may be lowered as a result,

Environmental Constraints.–Environmental

restrictions designed to control gaseous emissions

and the release of liquid pollutants have greatly

affected refinery investments and operating costs,

as well as the ability of refiners to install new process units or modify existing facilities. Although it

seems unlikely that environmental regulations

and emission controls affecting refineries will be

stricter in the next few years, the present regulatory framework can make it very difficult to modify or replace existing facilities.

ENERGY AND TECHNOLOGY

Production Processes

To understand how refineries use energy and

what the possibilities are for more efficient use

of such energy, it is useful to review the principal

processes of a modern refinery.24

Atmospheric Distillation

Incoming crude oil is first treated to remove inorganic salts and then dehydrated. Under slight

pressure it is then heated to a boil in a column

where the various components of the crude oil

are separated according to their boiling temperatures. Distillation, sometimes called “fractionation, “ is carried out continuously over a range

of boiling temperatures, and at several points hydrocarbon streams within specific boiling ranges

are withdrawn for further processing.

Vacuum Distillation

Some crude oil components are too heat-sensitive or have boiling points that are too high to

be distilled at atmospheric pressure. In such cases

the so-called “topped crude” (material from the

ZAPrWeSS descriptions are adapted from Argonne National Laboratory publication Energy and Materia/ Flows in Petro/eum Refining, AN L/CN5V-l O, February 1981. Available from National Technical Information Service, Springfield, Virginia.

bottom of the atmospheric column) must be further distilled in a column operating under a

vacuum. This operation lowers the boiling point

of the material and thereby allows distillation of

the heavier fractions without excessive thermal

decomposition.

Fluid Catalytic Cracking

Through fluid catalytic cracking, crude petroleum whose lighter fractions were removed by

atmospheric or vacuum distillation is entrained

in a hot, moving catalyst and chemically converted to lighter materials. The catalyst is then

separated and regenerated, while the reaction

products are fractionated into their various components by distillation. This is one of the most

widely used refinery conversion techniques.

Catalytic Reforming

Reforming is a catalytic process that takes Iowoctane materials and raises the octane number

to approximately 100. Although several chemical

reactions take place, the predominant reaction

is the removal of hydrogen from naphthenes (hydrogen-saturated, ring-like compounds) and the

conversion of naphthenes to aromatics (benzenering compounds). In addition to markedly in-
101—

Ch. 5—The Petroleum Refining Industry ● 9 3

creasing the octane number, the process produces hydrogen that can be used in other refinery

operations.

Alkylation

In the alkylation process, isobutane, a Iowmolecular-weight gas is chemically added to the

carbon-to-carbon double bonds that occur in certain hydrocarbons. The resulting product, now

containing many isobutyl side groups, has a much

higher octane number compared to the original

straight-chained substance, and is therefore a better motor fuel. Branched-chain hydrocarbons,

such as those with isobutyl side groups, are able

to have their octane rating increased even further with lead additives, but with the increasing

consumer need for unleaded gasolines, this type

of alkylation will be less and less used.

Hydrocracking

Hydrocracking is a catalytic, high-pressure

process that converts a wide range of hydrocarbons to lighter, cleaner, and more valuable products. By catalytically adding hydrogen under very

high pressure, the process increases the ratio of

hydrogen to carbon in the feed and produces

low-boiling material. Hydrocracking is especially adapted to the processing of low-value stocks

that are not suitable for catalytic cracking or reforming because of their high content of trace

metals, nitrogen, or sulfur, Such feedstocks are

used to produce gasoline, kerosene, middle-distillate fuels, and feedstocks for other refining and

petrochemical processes.

Hydrotreating

A number of hydrotreating processes use the

catalytic addition of hydrogen to remove sulfur

compounds from naphthas and distillates (light

and heavy gas oils). Removal of sulfur is essential for protecting the catalyst in subsequent processes (such as catalytic reforming) and for meeting

product specifications on certain “mid-barrel”

distillate fuels. Hydrotreating is the most widely

used treating process in today’s refineries. In addition to removing sulfur, it can eliminate other

undesirable impurities (e.g., nitrogen and oxygen), decolonize and stabilize products, correct

Photo credit: Phillips Petroleum Co. and American Petroleum Institute

A portion of Phillips Petroleum Co.’s refinery near Borger,

Tex. In the background is one of two huge catalytic

cracking units at this refinery. A large part of the refinery

output is moved by four long-distance product pipelines,

radiating in all directions from the refinery and serving

markets as far away as Denver and Chicago

odor problems, and improve many other deficiencies. Fuel products so treated range from

naphthas to heavy burner fuels.

Residuum Desulfurizing

With the increasing need to use the heavier,

higher boiling components of crude oils (the

“bottom of the barrel”), a number of processes

are being offered for the desulfurization of

residuum, the material remaining after atmospheric and vacuum column distillation. These

processes operate at pressures and temperatures

between low-severity hydrotreating and the

much more severe hydrocracking previously described. Depending on the market, the desulfurized “resid” can be used as a blending component of low-sulfur fuel oils or as a feedstock to

a coke producing unit (if a low-sulfur coke were

to be made).
94 ● Industrial Energy Use —

Coking

In the past, the residual bottoms from the crude

unit have been blended with lighter oils and marketed as fuel oils of low-quality and often high

sulfur content. These residues do, however, contain lighter fractions (naphthas and gas oils) that

can be recovered if the residual oil is “coked”

at high temperatures. It is becoming economically

worthwhile to recover these remaining light ends

for further processing. Petroleum coke is used

principally as a fuel. Coke derived from untreated

residues may have a high sulfur content and

hence be of limited commercial value.

Kinds of Refineries

Refineries can be considered under the following three broad classifications:

Topping Refineries.—A topping refinery (fig.

20) is usually small, often having less than 15,000

bpd capacity (although some are much larger).

It relies entirely on crude oil distillation to provide various product components, primarily

liquefied petroleum gases, gasoline blending

stocks, and distillate fuels (jet and diesel fuel and

heating oils). Residuum would be sold as a heavy

fuel oil or, if vacuum distillation were incorFigure 20.—Topping Refinery Model Configuration

LPG (liquefied

Naphtha Gasoline or

,

blending

Raw materials

w (crude Unit) Distillates Jet fuels

 distillate

1 J fuels

I

porated, would be partly made into asphalt. Since

a topping refinery, as described, has no cracking, hydrotreating, or reforming processes, its

range of products is almost entirely dependent

on the characteristics of the crude oil feedstock.

Hydroskimming Refineries.–Hydroskimming

refineries (fig. 21) make extensive use of hydrogen

treating processes for cleaning up naphthas and

distillate streams. Thus, a refinery of this type is

less dependent on the quality of the crude oil run,

but it is still limited in its ability to produce highoctane, unleaded gasoline, and its product

streams are heavily weighted toward fuel oils.

Such a refinery would normally include catalytic

reforming to increase its yield of high-octane finished gasoline.

Complex Refineries.–Most of the refining capacity (but not the number of refineries) falls into

the category of complex refineries (fig. 22) A typical complex refinery uses most of the processes

previously described. By virtue of its cracking

Figure 21 .–Hydroskimming Refinery Model

Configuration

LPG

(liquefied

Light ends Light- ~ natural gas)

\ * ends

processing ~ Refinery

fuel

- Naphtha 1 P Gasoline or

blending gasoline

Hydro

treating

Catalytic

reforming Gasoline

1

Reduced

crude Heavy

gas

oil 1

Vacuum

distillation vacuum residuum

Visbreaking

- (thermal

cracking)

Jet fuels

distillate

fuels

Residual

fuel oil

, Asphalt

SOURCE’ California Oil Scenario (Houston, Tex : Bonner & Moore Associates,

Mar 29, 1980) SOURCE California 0il Scenario Bonner and Moore Associates, Mar 29, 1980
Ch. 5— The Petroleum Refining Industry . 95

Photo credit Marathon Oil Co. and American Petroleum Institute

A portion of Marathon Oil Co. ’s refinery near Robinson,

Ill. In the background is the crude distillation unit which

has a charging capacity of 110,000 barrels of crude oil

per day

capacity, the refinery can convert high-boiling

crude oil fractions (otherwise suitable only for

heavy fuels) into lower boiling fractions suitable

for gasoline and distillate fuels. By alkylation and

other processes it can convert materials that are

too light for gasoline into stocks that can be

blended into gasoline. A typical complex refinery

would thus be able to run a wider range of crude

oils than would either a topping or a hydroskimming refinery. In addition, many—but not all—

of the larger complex refineries will have distillation units designed to permit running crude oil

of moderately high suIfur content (e. g., from the

Alaskan North Slope).

Energy Use

The petroleum refinery has not traditionally

been looked on as a major “profit center. ” profits in the oil industry come instead from producing crude oil and from marketing the products

or, in the large, integrated companies, from the

total operation of getting crude oil out of the

ground and products into the hands of the consumer. Refineries themselves were (and continue

to be) expensive to build and operate. Refiners

sought efficiency improvements primarily to obtain a greater output of more uniform products

from existing equipment. They studied and improved processes and installed expensive instrumentation and control systems to eliminate

as much as possible of the uncertain “human element.” As a result, oil refining now has one of

the highest capital costs per employee of any U.S.

industry.

Although refinery managements and their technical staffs had other priorities, they have taken

measures to use energy efficiently. I n many refineries, periodic efforts were made to improve

the steam balance and eliminate obviously wasteful plumes of exhaust steam. Where large volumes of surplus low-pressure steam were available, consideration was given to investing in a

condensing turbine driving a continuously operating pump or blower. Many refineries at one

time supplied their electrical energy needs by

“topping” turbines exhausting to the refinery

steam system, a highly efficient use of fuel energy.

However, as refinery electrical loads increased

and the cost of electrical energy available from

local utilities continued to decrease, investments

in additional refinery electrical generating capacity appeared less attractive when viewed by the

standards applied to other investments in the oil

industry. In time, purchased electrical energy

came to supply most of the refinery load.

At a few locations, a refinery and a local utility

were able to collaborate on a large powerplant

in or adjacent to the refinery. Typically, the

powerplant would obtain heavy fuel oil from the

refinery. The utility, in turn, might supply steam

to the refinery. However, many utilities were reluctant to lose their expensively treated boiler
96 • Industrial Energy Use

Figure 22.—Complex Refinery Model Configuration

Natural gas

Iiquids fuel gas

All processe

Iight ends

Reduced

crude

Residual

 fuel oil

SOURCE: Callifornla Oil Scenario (Houston, Tex.: Bonnar & Moore Associates, Mar. 29, 1980.

feedwater in the form of steam that would not topping refineries use less energy per barrel, and

be returned (or would come back contaminated).

These early attempts at cogeneration were not

very successful because to be of interest to the

utility, the electrical capacity of the refinery had

to be much greater than the refinery’s demand.

Also, the utility’s need for fuel and the refinery’s

for steam were normally not in thermal balance,

and the overall economics of the joint venture

were usually not attractive.

A rule of thumb used by some refiners is that

it takes 1 barrel of oil-equivalent energy to process 10 barrels of crude oil. In other words, using

an average heating value for crude oil, processing a barrel of crude through a typical refinery

results in the use of about 580,000 Btu of energy.

This is a good approximation of energy use. Small

complex refineries with a wide spectrum of finished products probably use more.

In typical refining processes, feed streams are

normally heated, either to effect a physical separation (crude unit fractionation) or to provide

energy for a heat-absorbing reaction (e. g., catalytic reforming). Although heat exchange is used

to preheat feed streams to the highest economically feasible temperatures, additional heat is

usually needed. Specifically, petroleum refining

processes use energy in the form of fuel, steam,

or electrical energy for the following functions:

● To heat crude units and other process feed

streams.

• To make steam for mechanical-drive turbines

to power major compressors and some large
Ch. 5—The Petroleum Refining Industry ● 9 7

pumps; for process heating, steam-stripping,

and steam-jet vacuum ejectors.

● To heat reboilers (steam-fired or fuel-fired).

. To power most pumps and the fans i n air

coolers (usually with electric motors.)

Energy losses from petroleum refining operations are primarily the result of the following:

●

●

●

●

Heat rejected by (lost to) air- and watercooled heat exchangers used to cool recycle and product streams. (This equipment is

estimated to account for up to 50 percent

of refinery heat losses.)

Unrecovered heat in flue gases from furnaces

and steam boilers (perhaps 25 percent of refinery energy losses).

Convection and radiation losses from hot

equipment and piping.

Steam system losses.

Although most refineries maintain summary

records of energy use by their process plants and

of energy purchased from utilities or sold offsite

to other energy users, the only complete public,

nonproprietary analysis of a “refinery energy profile” is the study of Gulf Oil Co.’s Alliance refinery

carried out by Gulf Research & Development Co.

under contract to the Department of Energy’s

(DOE’s) Office of Industrial Programs.25 Alliance

is a typical complex refinery incorporating all the

principal refining processes described earlier,

with the exception of hydrocracking. Figure 23,

reproduced from the Gulf Research repot-t, illustrates the flow of energy into the total refinery,

as well as the form and amount of energy losses

from the system.

Energy Conservation

For this report, the basis for reviewing the energy conservation record of the petroleum refin25GuIf Research & Development Co., Refinery Energy profile—

Final Report, prepared for DOE, report No. ORO-5262-5, January

1979,

Figure 23.—Alliance Refinery Energy Profile

(M Btu/bbl of oil charge to refinery and percent)a

Energy input to plant Energy output as losses

Heater and boiler stacks

Fuel gasb

:

372 (66°/0) 105 (19%)

174 (31 %)

Electric power Water coolers 137 (240/o)

Petroleum coke

Feed streams

Exothermic reaction

Oil charge Iossc

1 

117 (21 %)

12( 2%)

14( 2°/0)

32( 6°/0)

Total 560 (lOOO/o)

Steam system 18( 3°/0)

Electrical system 5( 1%)

Radiation and convection 21 ( 4°/0)

Products and wastes 10( 2%)

Endothermic reactions 38( 7°/0)

Oil and gas losses 36( 6°/0)

Subtotal 545 (97%)

Imbalance 15( 3%)

Total 560 (loo%)

aBa~ed ~n period 9126177. 1016177 at 214,636 bpd oil charge to refl~~.

blnclude~ 2713 (487. ) of refining gas and 102 (18

0

/0) of natural 9as.

CEnergy value of combustible portion of stock loss

SOURCE: Deparment of Energy, Refinery Energy Profile-Final Report, prepared for DOE by Gulf Research & Development Co., Report No. ORO-5262-5, January 1979.
98 • Industrial Energy Use

ing industry is the energy efficiency report made

by the American Petroleum Institute (API) to

DOE’s Office of industrial Programs. Table 25

presents the petroleum refining industry’s report

to DOE on energy consumption for the year

1981.

As part of DOE’s energy efficiency program, the

petroleum industry adopted a voluntary goal of

improving efficiency by 20 percent by 1980. A

measure of industry progress toward this goal is

shown in figure 24. Electricity and petroleum use

remained approximately constant over the time

period. However, natural gas use is now less than

two-thirds of what it was in 1972. Production decreased by less than 1/2 percent over the same

time period.

Potential for Energy Saving

It is to be expected that refinery managements

and their technical staffs will continue to look for

energy-saving opportunities and to implement

those that appear to be economically justified.

However, in evaluating progress the refining industry has made in energy conservation, as well

as the potential for further savings, it is essential

to keep several considerations in mind.

First, competition for capital funds in the petroleum industry is intense and likely to remain so.

Table 25.–Comparison of 1972 and 1981 Energy

Consumption in Petroleum Refining Industry

1972 1981

Energy type consumption consumption

1. Electricity . . . . . . . . . . . . . . 200,525 250,193

2. Natural gas . . . . . . . . . . . . . 1,034,006 686,277

3. Propane . . . . . . . . . . . . . . . . 9,850 6,979

4. LPG . . . . . . . . . . . . . . . . . . . . 28,438 24,852

5. Bituminous coal . . . . . . . . . 4,850 4,823

6. Anthracite coal . . . . . . . . . . 38 0

7. Coke . . . . . . . . . . . . . . . . . . . 0 0

8. Gasoline. . . . . . . . . . . . . . . . 107 112

9. Distillate fuel oil . . . . . . . . . 22,183 8,425

10. Residual fuel oil . . . . . . . . . 257,606 177,028

11. Petroleum coke. . . . . . . . . . 441,512 427,569

12. Purchased steam . . . . . . . . 37,128 27,629

13. Refinery gas . . . . . . . . . . . . 1,030,162 1,162,453

14. Other liquids . . . . . . . . . . . . 6,692 2,487

15. Other (specify) . . . . . . . . . .

16. Total energy consumption 3,073,098 2,778,827

SOURCE: American Petroleum Institute, 1981 Report to the U.S. Department of

Energy, “Energy Efficiency Improvement and Recovered Material

Utilization Report.”

Figure 24.–Comparison of Petroleum Refining

Industry Energy Use and Production Output

1972 and 1981

200

-180 -

-

1972 1981

Energy Production Energy Production

use use

Coal Petroleum

Natural Electricity and Production

gas steam index

- - t [

SOURCE American Petroleum Institute and Federal Reserve Board

Thus, corporate management may see currently

underused refineries as less desirable for investment than are the exploration and production activities that are rightly considered to be essential

for the future well-being of the industry.

Second, many of the easy and obvious opportunities for energy savings have been taken. Additional opportunities, although certainly present,

will be more difficult to identify and justify

economically. In part, these energy savings will

be difficult to make because environmental regulations have affected the industry’s energy use in

terms of the need for energy-consuming pollution abatement equipment and also in terms of

the mandate to produce unleaded gasoline.
Ch. 5—The Petroleum Refining Industry • 99

Technologies for Increased

Energy Efficiency

Numerous energy conservation opportunities

have been identified in the petroleum refining

industry. 26 The most productive energy-conserving measures appear to be in the areas of improved combustion, the recovery of low-grade

heat, and the use of process modifications.

However, there are several barriers to improving the efficiency of energy use in refineries. First,

there are operational limits. Energy efficiency

measures to achieve energy savings cannot often

be put into effect just by a plant’s operating organization when it is primarily concerned with

running the equipment, maintaining safe conditions, and producing the desired amounts of

specification products. An effective energy conservation program requires a sustained technical

effort having the consistent support of the company’s management.

Second, there are thermodynamic limits to the

amount by which heat input into the processing

“system” can be reduced. Many of the chemical

reactions in refining processes require heat (i. e.,

they are endothermic). Other operations, such

as fractionation, require that fluid streams be

heated to high temperatures. It is not possible to

obtain all this heat by exchange with other

streams. Even more fundamentally, the great

amounts of heat present in refinery lines, vessels,

and tanks at low or moderate temperatures cannot be upgraded to higher temperatures by any

techniques now available. Fired furnaces must

usually provide such heat.

Finally, there are economic limits to the investments that can be justified to achieve specific

energy savings. The amount of energy saved does

26 The potent\a/for Energy Conservation in Nine Selected lndustrles: The Data Base, Vol. 2, Petroleum f?efining, Gordlan

Associates, Inc., for the Federal Energy Admlnlstration, NTIS order

No, PB-243-613, June 1974; Energy Eficlency /rnprovement Targets,

Vo/. 1, Petro/eurn and Coa/ Products, Gordian Associates, Inc., for

the Federal Energy Admlnlstratlon, contract No. FEA/D-77/244, June

25, 1976

not justify the capital required. Some of these

limits will be apparent in the following discussion.

Proven Technologies for

Energy Conservation

Considering only proven technologies, the

most significant opportunities for energy savings

in refineries are likely to be found in the following operations and systems.

Air and Water Cooling of Process Streams

As indicated previously in figure 23, the final

cooling of process streams in air- and watercooled heat exchangers can represent the greatest single loss of heat in the refinery. Where feasible, heated streams can first be used to heat other

process streams and thus minimize the amount

of heat rejected to air or water. Cold streams

suitable for this exchange must be available. The

Gulf Research study showed that the total energy

input requirements of the refinery could be reduced by about 18.7 percent if all such streams

could be brought down to a temperature of 2000

F by process heat exchange before being cooled

further. Such an extreme reduction is unlikely to

be feasible, but the Gulf study showed that reductions to 250° or 300° F would reduce energy requirements by 8.6 and 3.7 percent, respectively. (Recovery of low-grade heat as mechanical

energy is discussed under “New Concepts” in

the next section.)

Process Heaters and Steam Boilers

These direct-fired units offer many opportunities for energy savings. With fired heaters, some

of the options are: 1 ) reducing excess air and improving combustion by using stack gas analyzers

and combustion control instrumentation, 2) reducing stack gas temperatures by using air preheater to heat incoming combustion air, and

3) installing convection sections at the heater

outlets to heat incoming feed or to generate

steam. (A constraint on the last two options is the

need to keep stack gas temperatures above the

sulfur content “dew point, ” below which serious

corrosion of carbon steels can be anticipated.)

Steam boilers, although many commonly incorporate such heat-conserving devices as air pre-
100 ● Industrial Energy Use

—

heaters and “economizers,” can also often benefit by improved combustion controls and perhaps by boiler blowdown heat recovery.

Steam System Improvements

In most refineries, steam is generated and then

distributed at moderately high pressure (often 600

psi), as well as at medium or low pressures, such

as 150 and 50 psi. The steam is used for heating

and for mechanical drives (usually turbines) at

many locations in the refinery. Ideally, the steam

generated and distributed at these pressure levels

is used at such levels, and is reduced or “let

down” to a lower level only while doing useful

work. At the lowest pressure level, all steam is

ideally used for heating (or perhaps driving a condensing steam turbine) so that no steam is wasted

by being vented to the atmosphere. Such a system represents the ideal goal of being “in balance. ”

Inevitably, though, process plants are modified,

and their uses of steam change. Steam systems

get out of balance, and frequently no juggling of

steam turbine and motor drivers can prevent

wasteful let-downs of high-pressure steam or

venting to the atmosphere of excess low-pressure

steam. When steam systems become acutely imbalance, many refineries achieve significant savings by changing major drivers; installing large,

low-pressure, condensing turbines; and using

other means to minimize loss in the system. Since

it is almost never economical to generate steam

for a turbine driver if its exhaust steam will be

wasted, replacement of such turbines by motors

often represents an attractive investment.

Improved Process Heat Exchange

A refinery will contain many heat exchangers

for transferring heat from one process to another.

A great number of heat exchanger arrangements

are usually possible, and the optimization of heat

exchange—especially in the crude preheat train—

is an important aspect of plant design. in the

design of many U.S. refineries, low fuel prices

(and hence low energy costs) resulted in a minimum amount of heat exchange being installed

originally. Although a major revamp of heat exchange systems can be quite expensive, and

sometimes impossible because of space limitations, such an investment will often show a very

good return.

Improved Instrumentation and Controls

Most refiners have steadily improved their instrumentation and control systems, even to the

extent of using closed-loop computer controls.

The economic benefits from such systems are primarily in improved performance of the process

units, but consistently higher outputs and closer

product specification tolerances can also result

in significant energy savings per barrel of finished

product.

Improved Insulation

As with heat exchange systems, insulation

standards in many refineries were developed during the earlier era of cheap energy. Substantial

heat losses from lines, vessels, and other equipment were anticipated. Many engineering design

practice standards called for no insulation of surfaces at temperatures below 200° F unless a surface represented a hazard to operating and maintenance personnel who could inadvertently

touch it from grade or operating platforms. In

such cases, the hot surface was often insulated

only as far as a person could reach. With increased energy costs, insulation of surfaces at

much lower temperatures can now be justified.

This justification is especially apparent for large,

bare storage tanks operating at temperatures well

above that of their surrounding environments.

Energy Recovery From Process Streams

Many high-pressure, gaseous, and liquid process streams are “throttled” by control valves, with

significant energy loss. In some applications, hydraulic turbines and power recovery turbines (turboexpanders) can be used to extract considerable

energy from such streams.

Pump Efficiency Improvement

Since refinery motors (and most mechanicaldrive steam turbines) operate at constant speed,

control of output from the pumps they drive must

be achieved by throttling through a control valve.

If the characteristic curve of the pump essentially matches that of the piping system, this throt-
Ch. 5—The Petroleum Refining Industry ● 101

tling dissipates only moderate amounts of energy

and can usually be ignored. Unfortunately, mismatches of pump and system are all too common, and often intentional. Design engineers

have been encouraged to specify pump impellers

of greater diameter (which often need larger

motors) than the hydraulic design actually requires. Thus, the engineer is protected against

charges of having “underdesigned, ” and the operator is assured of immediately available extra

capacity in case he ever wishes to operate the

plant above the original design limits. As a result,

during its entire lifetime the pump wastes energy

by discharging against a partially closed control

valve, while the unnecessarily large motor driver,

operating below its rated output, wastes even

more energy because it is well below its point

of maximum efficiency. Although the principal

savings in this area can be achieved by proper

selection of pumps and drivers initially, simply

changing pump impellers can often achieve significant savings in an operating plant.

Fractionation Efficiency Improvements

The operating characteristics of a fractionating

column are largely established in initial plant designs. Or-ice the column has been installed, relatively little modification is feasible, and specific

opportunities for energy savings are limited. However, many columns are operated at considerably

higher reflux rates than necessary for proper fractionation. Reducing these reflux rates to the minimum required for proper functioning of the column can result in significant savings.

Refinery Loss Control

Many potential types of refinery losses include

losses from flares, relief valve leaks, tank filling,

evaporation from tanks and from oil-water separators, other leaks of all types, tank cleaning and

vessel draining, and spillages from all forms of

loading operations.

Housekeeping Measures

Potential savings by vigilance in policing and

correcting such energy wasters as faulty steam

traps, damaged insulation, careless steam depressurizing and venting, and the like. The possible

energy-saving measures discussed to this point

involve well-understood technologies and operating and maintenance practices. The challenge

to refineries comes from the need to identify such

opportunities in specific plants, evaluate them to

determine what corrective measures can be justified, and then proceed to take the necessary

action.

New Concepts in Refinery Energy Use

Beyond the existing technologies discussed

above there appear to be some significant, longterm opportunities for improving in energy efficiency by the use of certain new—or at least unproven–technologies. Refineries may be able to

use other sources of energy, and otherwise

wasted heat, to reduce the combustion of gaseous and liquid fuels. OTA considers that fuel

substitution (such as the use of coal in refineries)

is an important goal, even though the calculated

efficiency of fuel energy use may not be improved

or may even be lowered as a result of such a

change in fuel.

The majority of refinery process heaters now

burn only gaseous and liquid fuels derived from

petroleum. in some heaters, tube configurations

and the need for close control of process reactions permit only gas to be burned. Since it is

perhaps not entirely clear why coal-burning refinery process heaters have not been developed,

it may be useful to summarize the principal demands made on refinery process heaters:

1.

2.

3.

In many heaters, the fluids undergo process

reactions in the tubes, often at high pressure

and temperature. Careful monitoring and

precise control of such reactions are essential, since the process fluid will decompose

if heated above the intended temperature.

Precise firing control is necessary for rapid,

even instantaneous, control response necessary because of the need to shut down firing immediately if the instrumentation or operators detect tube failures, dangerously

reduced flow rates in any tubes, or a power

failure.

In addition to the required, precise control

of temperature of the process streams being

heated, measurement and control of tube

99-109 0 - 83 - 8
102 ● Industrial Energy Use

wall temperature in many furnaces is necessary to prevent overheating and rupture

of the tube, with the resulting prospect of

a serious fire.

Coal as a Refinery Fuel

Coal-fired furnaces are perceived by refiners

as unable to meet any of the above requirements

because they have considerable “thermal mass”

and respond relatively slowly to control changes.

Also, coal firing results in molten ash deposition

on tubes at some temperatures. Lower heat-release rates for coal burning require larger (and

hence more expensive) furnaces. Large volumes

of ash must be dealt with and—as always with

conventional coal burning—the stack gases must

be cleaned of particulate and perhaps even

scrubbed to remove sulfur acid compounds. In

view of the historically small differential between

the costs of coal energy and those of petroleum,

it is understandable that little pressure has existed

for the development of coal-fired refinery process

heaters. Now, however, with increasing energy

costs and potential restrictions on the use of

petroleum-derived fuels, renewed emphasis is being placed on coal as a potential refinery fuel.

Some of these developments are discussed in the

following paragraphs.

CONVENTIONAL FIRING

Several attempts have been made to design

process heaters in which coal would be fired

directly. Furnace “geometry” would of course

be different; provisions for ash collection and

removal wouId be provided; and other changes

would be made to use the electric utilities’ experience with burning coal. Pulverized coal

(rather than stoker firing) would be necessary to

permit faster response to combustion controls.

Although some progress reports have appeared

in the technical press, the refining industry’s apparent conclusion is that no coal-fired heater

designs are yet available to meet the exacting

demands of process heater service.

FLUIDIZED-BED COMBUSTION

Fluidized-bed combustion is a process by

which a fuel is burned in a bed of small particles

that are suspended, or “fluidized, ” in a stream

of air blown upward from below the bed. Almost

any type of properly dispersed fuel can be burned

in a fluidized bed, but most of the technology

of interest re!ates to the combustion of coal in

a “clean” manner that eliminates the need for

stack gas scrubbing devices to remove sulfur oxides. This result can be achieved by feeding

crushed limestone or dolomite into the fluidized

bed along with the coal. The sulfur in the coal

combines with the calcium in the crushed rock

to form calcium sulfate. Sometimes identified as

“spent sorbent, ” this material is removed with

the ash, and the combined solid waste is disposed

of as landfill or used in some other manner.

The concept of a fluidized bed is not new.

Since the 1940’s, various forms of catalytic crackers, using fluidized beds, have evolved. The fluid

catalytic cracking process is the result of this

development. The petroleum refining industry

has been following the development of fluidizedbed combustion with great interest. Although it

was originally thought to be just a clean method

of burning coal for refinery steam generation,

fluidized-bed combustion could ultimately develop into a technology for providing a large part

of the total heat required by a refinery. As an illustration, figure 25 shows, in elementary form,

a conceptual comparison between steam boilers

and process heaters using atmospheric, fluidizedbed combustion (AFBC) techniques. In this concept (diagram C), the process fluid to be heated

would be immersed in the fluidized bed.

Since coal-burning equipment of any type requires large areas for coal storage and handling,

as well as for ash disposal, it would not be feasible to replace individual process heaters throughout a refinery with coal-burning, fluidized-bed

units. Instead, it is possible to visualize large fluidized-bed process heaters made up of several cells.

Steam would be generated from. coils in some

parts of the bed, and process heat could be generated in coils in other parts of the bed. Because

of the distances involved and the characteristics

of process fluids, it seems unlikely that many

process steams would be heated directly by

means of coils in fluidized beds. Instead, heat

might be transferred to the process areas by hotoil systems and heat exchangers, and perhaps

also by high-temperature, pressurized water sys-
Ch. 5— The Petroleum Refining Industry ● 103

Figure 25.— Diagram of Atmospheric Fluidized-Bed Combustion (AFBC) Boiler/Combustor Arrangements

A. Saturated steam boiler B. Superheated steam generator

Saturated

steam outlet

Off gas

Economizer Feed water

Feed water inlet —

inlet

Off gas

Fuel and

Fuel an Superheating

sorben Superheated

inlet steam outlet

idizing

Ash disposal

—.. . -

Ash disposal

C. Indirect process heater

Off gas

●

Working

fluid sorbent inlet

inlet

Ash disposal

SOURCE U S Department of Energy 1977 Annual Report

terns. Since some process streams must be heated

to temperatures higher than a hot-oil system

couId feasibly deliver, some process heaters

would still be required.

In view of the foregoing, it seems necessary to

conclude that fluidized-bed combustion of coal,

although perhaps an eventual means of reducing the combustion of petroleum-derived fuels

in refineries, will not be a significant process

D. Direct process heater

Hot gases

for process

 need s

I I

d

t

s)

Ash disposal

energy option in the immediate future. It very

likely will, however, find increasing application

for steam generation in refineries.

COAL GASIFICATION

It has been suggested that refineries might install coal gasification units to obtain energy from

coal. Coal gasification couId most logically produce a medium-Btu industrial “syngas” com-
—

104 . Industrial Energy Use

posed primarily of hydrogen and carbon monoxide. However, it seems unlikely that such an installation would now be attractive to refiners. The

gasifiers being offered are in various stages of

development, and none can be considered reliable. Likewise, the relatively low conversion efficiency of the process, the problems of handling

coal and ash, the need to build and operate an

adjacent oxygen plant, and the complications of

converting refining furnaces to use a fuel of much

lower Btu than now used all argue against considering coal gasification a reasonable option. If

done at all, it seems most likely that coal gasification will be undertaken by a major utility serving refineries along with its many other industrial

customers.

Thermal Recovery of Low-Level Heat

As might be expected from the magnitude of

losses to air- and water-cooled heat exchangers,

refinery management and its technical staff see

thermal recovery of low-level heat as a prime opportunity to save energy. They are also aware that

opportunities for recovering significant amounts

of this wasted heat are unlikely to be found in

existing operating plants, but must await instead

the design of new facilities where heat balances

can be developed with consideration for the true

values of heat at all temperatures and pressure

levels.

one major refining company is designing a new

lubricating-oil manufacturing plant to take advantage of low-level heat recovery. In this plant, the

process streams being “run down” for final cooling first generate 45-lb steam and then provide

heat to a pressurized, “tempered” water system

operating at about 2850 F. The tempered water

is used for process reboilers and also as the heat

source for the aqua-ammonia absorption refrigeration system, a key part of the plant. Finally,

the process streams are cooled in the conventional manner. Although these streams are still

at temperatures of approximately 300° F when

finally cooled, considerable energy that would

otherwise be wasted is recovered.

Most of the many opportunities for using lowIevel heat from rundown streams will appear in

the design of new facilities whose energy requirements are not circumscribed by existing systems.

Mechanical Recovery of Low= Level Heat

Low-1evel waste heat might be used to vaporize

a fluid, use the vapor to operate a mechanicaldrive turbine, and then condense the vapor for

recycling to the heat source. Although the concept is straightforward, its practical application

is not. Organic fluids must be used instead of

water because of the size of the required equipment and the complexity of operating under a

vacuum. * Selection of a working fluid involves

considerations of toxicity, environmental acceptability, cost, and the thermodynamic properties

needed for the cycle. Although the various fluorocarbons are leading contenders, increasing restrictions may make their use inappropriate.

other typical refrigerants have been considered,

and one, toluene, is used in one experimental

application reported in the literature. Finally, in

addition to other limitations of this method, the

low level of heat involved limits energy recovery

to perhaps 10 percent, making this form of energy

conservation generally unattractive economically.

*The term ‘‘organic rankine cycle” is used to refer to this lowIevel heat recovery technology.

INVESTMENT CHOICES FOR THE REFINING INDUSTRY

In this section OTA examines certain broader native investments discussed to those for energyaspects of the petroleum industry, including: saving options in refineries.

1 ) competition for capital investment dollars

within the industry as it is now structured, and Capital Expenditures in the Oil Industry

2) possible investment opportunities in largely In considering investment opportunities and innonoil operations. OTA then relates the alter- centives for energy-saving measures in refineries,
Ch. 5—The Petroleum Refining Industry ● 105

it is essential to keep in mind the magnitude of

other demands for capital in the entire industry.

For example, the 0il & Gas Journal summarizes

the 1982 budget for the U.S. oil industry as:

Exploration and production ... ... ... .$66,8 billion

Refining . . . . . . . . . ., . ...............6.4 billion

Other . . . . . . . . . . . . . . . . . ........22.1 billion

Total 1982 budget ... ... ... ... ... .$95.3 billion

The Standard Oil Co. of California capital expenditure record (shown below) for 4 years is

consistent with the Journal’s report and is believed to be representative of similar expenditures

by other major U.S. oil companies.

Capital and Exploratory Expenditures (millions of dollars)

1977 1978 1979 1980

Producing and exploration .,$ 891 $1,163 $1,603 $2,230

Manufacturing: Chemicals 60 2 6 57 91

Refining . 168 149 187 328

Marketin g 76 92 102 272

Transportation 84 50 96 134

Othe r 150 212 213 544 ——. .

Total expenditures ... ... .$1,429 $1,692 $2,258 $3,599

A very significant aspect of the foregoing figures

is the magnitude of the financial resources

needed to discover and produce crude oil and

natural gas. These expenditures have increased

rapidly in recent years, partly because of the anticipated (and then actual) decontrol of oil prices

and because of the urgent need seen by the industry to reduce its dependence on foreign

sources of crude oil. In addition, even though

geophysical techniques are constantly improving,

exploration operations produce many more “dry

holes” than wells promising commercial production. As the potentially hydrocarbon-bearing geologic structures now being explored are at increasingly greater depths, the exploratory wells

and those drilled for production of commercial

discoveries are becoming increasingly expensive.

Another drain on the capital resources of the

industry is the previously mentioned restructuring of processing systems to permit running

heavy, high-sulfur crude oil and producing the

increasing share of unleaded gasoline that must

be provided for the motor fuels market.

Other Investment Opportunities

Corporate planners in the oil industry work in

an atmosphere of great uncertainty. They know

that supplies of crude oil and natural gas will

become increasingly scarce, but they do not

know whether a serious availability “crisis” will

occur within a decade, a generation, or at some

time in the next century. More immediately, they

cannot assess political conditions in the troubled

areas of the oil-producing world accurately

enough to forecast either worldwide price trends

or the amounts of imported crude oil the Western

world can safely count on. They can be certain,

however, that their past world of steadily increasing crude runs and product sales has come to an

end; they must now do the best they can to plan

for an uncertain future. Two options–not mutually exclusive–seem open to the industry:

●

●

Concentrate on employing the resources and

special skills they now have available, including searching out long-term investment opportunities in areas of technology that can

be developed without major shifts in corporate structure, personnel, or markets.

Use their great financial resources and presumed managerial and technical expertise

to enter any field of endeavor that promises

financial rewards, regardless of its relation

to existing operations.

In considering options of the second type, oil

industry corporate management may find itself

confronted with what might be termed an “identity crisis.” As repeated public opinion polls

demonstrate, the industry is now held in low

esteem by much of the U.S. public. In spite of

clear factual evidence to the contrary, a large segment of the public seems to believe that the much

publicized oil shortages and the gasoline lines of

the recent past—and for many, perhaps, even

high gasoline prices–have been contrived by the

major oil companies for their own financial benefit. Although legislative proposals for break Up

or nationalization of the industry appear to have

subsided, such proposals are very much in the

background and would probably be reintroduced

if their sponsors felt the political climate were

right.

The public can likewise be expected to recall

that much of the industry vigorously campaigned

for decontrol of oil prices, giving as a principal

justification the need for more revenue to increase oil and gas exploration in the United
—

106 ● Industrial Energy Use

States. Now that oil price decontrol has been

achieved, public opinion and editorial comment

could be most unfavorable to announcements by

major oil companies of large investments in activities unrelated to the oil business or to takeover

attempts within the industry by companies already perceived to be “big enough. ”

Given this background, corporate management

might seek several types of investments to guide

their companies during the uncertain transition

period.

Energy Investments

The most obvious area of oil industry expansion involves investments in other forms of

energy. Although not all investment decisions use

oil industry expertise directly, most do follow the

sequence, “research -development-marketing,”

to which the industry is accustomed. Examples

would include the following:

Synfuels: Liquefaction of Coal.–Liquefaction

of coal is perceived by many industry analysts to

be one of the best long-term opportunities for

major refiners. In direct liquefaction processes,

liquids are obtained directly by hydrogenation of

coal. Liquefaction processes are being developed

in many of the major oil industry process laboratories, and several processes are felt to be approaching commercial development–examples

are SRC-11, Exxon Donor Solvent, and H-Oil. Unfortunately, all these processes still appear to be

plagued by mechanical problems as well as by

process uncertainties. Moreover, recent declines

in crude oil prices, together with the great reduction in Federal subsidization of demonstration

energy projects, make it unlikely that direct

liquefaction plants of commercial size will be built

in the near future. Nevertheless, these processes

represent a long-term source of liquid fuels that

could supplement and perhaps ultimately supplant crude oil in the manufacture of liquid fuels

and a wide range of other products. It is to be

expected that the industry will continue to work

on their development.

Indirect processes of coal liquefaction are those

in which coal is first gasified to produce a medium-Btu syngas. This gas can be converted to liquid fuels or to chemical feedstocks, as done in

the South African Government’s large “SasoI”

plants. Alternatively, the syngas can be converted

to methanol and then to gasoline, using Mobil’s

proprietary process. Although the indirect liquefaction technologies are considerably further

along in development than are the direct processes, they seem to be less attractive to the oil

industry. Their conversion efficiency is significantly lower, and they do not produce the wide range

of products required by oil industry markets. Oil

industry R&D appears to be concentrated on direct liquefaction processes, but considerable effort is also being devoted to the indirect approaches.

Geothermal Energy production.–Some geothermal energy resources (steam and hot water)

can be identified by surface geologic conditions,

others by exploratory drilling for oil and gas.

Typically, an oil company exploiting a geothermal resource will top the steam or hot water and

then sell it to a utility for power generation.

Cooled water may be returned for injection into

the formation. In spite of many optimistic assessments, use of geothermal energy resources presents many technological and environmental

problems that can be expected to slow development. Nevertheless, geothermal energy resources

in the United States are of very great magnitude.

It is expected that oil industry participation in

their use will continue.

Petrochemicals.–Most U.S. manufacture of

petrochemicals (including basic feedstocks) is not

especially profitable at present. Although it is a

basic activity of the refining industry, petrochemical manufacture would not appear to be an attractive investment area until the potential problems of foreign competition are resolved and the

U.S. market improves.

Alternative Energy Sources.–Many oil industry

laboratories conduct intensive research programs

in such fields as fuel cells, solar photovoltaics,

and other forms of solar energy utilization. Most

of these activities are considered to be very long

range. It is hoped that some will result in new

and economical sources of energy, but none is

believed to be at a point where a major capital

investment in the technology would be considered.
Ch. 5—The Petroleum Refining Industry ● 107

Oil Shale Mining and Processing.–Many of the

major oil companies are undertaking oil shale

projects, and others have been preparing to do

so. Some acquired their own oil shale properties

many years ago. Others operate under Federal

leases. The hydrocarbon reserves in Colorado

and other oil shale deposits are of very great size,

and much informed opinion in the oil industry

holds that oil from shale will be developed and

on the market long before synfuels from coal can

be produced. Nevertheless, billion-dollar investments will be required for shale production

and retorting, and few companies appear to be

willing (or able) to proceed with such developments without Federal product purchase contracts or loan guarantees. As with many other

energy proposals, softening prices of crude oil are

dampening the recent enthusiasm for shale oil,

and several cutbacks and postponements of these

developments have already been announced. Although ultimate use of these shale oil resources

seems certain, the firms making investments now

are doing so because of the long-range potential, and not in expectation of immediate profits.

Nonoil-Related Investments

Although many nonoil-related investments are

initially profitable—and others may prove so after

initial difficulties—several have already caused

unfavorable comment in the financial press.

Among the best known examples of investments

that apparently have not been profitable are

Mobil’s acquisition of Marcor (including Montgomery Ward), Exxon’s Office Systems Co., and

Exxon’s acquisition of Reliance Electric. It would

appear that such investments are appropriate

only when oil industry management is confident

that no reasonably equivalent opportunities can

be found in its own industry–including the often

overlooked possibilities of investments to achieve

more efficient refinery operations.

IMPACTS OF POLICY OPTIONS ON THE PETROLEUM

REFINING INDUSTRY

Having examined the energy use characteristics

of the petroleum refining industry, including the

specific unit operations where energy is used and

the technological opportunities that can improve

the efficiency of energy use, the rest of this chapter will be devoted to an examination of the effect of a series of policy options as they would

influence energy use.

This analysis is based on a trio of analytical

methodologies. In each policy option case, OTA

has projected fuel use between 1980 and 2000

using the Industrial Sector Technology Use Model

(ISTUM). Second, OTA has assembled a list of

eight typical projects in which a petroleum

refinery management could invest its capital

funds. The projects are ranked according to their

internal rate of return (1 RR) under both the

reference case and the policy option. Any

changes in the ranking are then examined and

discussed. Finally, the observations and analyses

of OTA’s consultants, advisory panelists, and

workshop participants are noted.

The projects used to illustrate the IRR calculations are described in table 26. Four of the projects are specifically oriented toward the petroleum refining industry. The remaining four are

generic—i. e., they are applicable throughout the

industrial sector.

A graphical illustration of the impact of each

policy option on energy use in the industry is

presented in figure 26. The analysis begins with

a discussion of the reference case.

The Reference Case

The reference case is predicated on the economic and legislative environment that exists

today. It includes the following several general

trends that can be identified at present and which

should continue over the next two decades:

● A general decline in the total amount of refined product produced between 1980 and

2000.
. —

108 ● Industrial Energy Use

Table 26.—Petroleum Refining Industry Projects To Be Analyzed for Internal Rate of Return (lRR) Values

1.

2.

3.

4

—

Inventory control. —A computerized system that keeps

track of product item availability, location, age, and so

forth. In addition, these systems can be used to forecast

product demand on a seasonal basis. The overall effect is

to lower inventory yet maintain the availability to ship

products to customers with little or no delay. In typical

installations, working capital costs are dramatically

reduced.

Project life—5 years.

Capital and installation costs–$560,000.

Energy savings—O directly, but working capital could be

reduced by $1.2 million.

Electric motors. -The petroleum refining industry uses

electrical motors for everything from vapor recompression

to mixing, pumping, and extruding. In this analysis, OTA

has assumed that five aging electric motors will be

replaced with newer, high-efficiency ones.

Project life—10 years.

Capital and installation costs–$35,000.

Energy savings–$16,000 per year at 4¢/kWh.

Catalytic reformer air preheater #1.—A typical energy

conservation project in the petroleum refining industry

wherein hydrogen is removed from certain organic

compounds, thereby increasing the octane rating of the

remaining aromatic material.

Project life—10 years.

Capital and installation costs—$2 million.

Energy savings—$894,000 at 30 million Btu saved per hour.

Catalytic reformer air preheater #2.—Same as above,

except that major structural changes are necessary in the

furnace configuration, thereby increasing installation cost.

Project life—10 years.

Capital and installation costs—$3 million.

SOURCE: Office of Technology Assessment

● A shift in product mix produced by the petroleum refining industry.

● A deterioration in the quality of crude oil

feedstock available to the petroleum refining industry.

As mentioned before, these trends place SIC 29

corporations in the unenviable position of having to make substantial investments to accommodate changing feedstocks and product markets

in an industry whose overall growth will be

negative.

These trends can be clearly seen in the modeling analyses carried out under OTA direction.

Table 27 presents the OTA projection for total

production in SIC 29. As shown, it decreases from

a high of 14.2 million bpd in 1980 to 13.9 million

bpd in 2000. At the same time, the product mix

is forecast to change from a preponderance of

5.

6.

7.

Energy savings—$t394,000 at 30 million Btu saved per hour

of operation.

Computerized process contro/.—One of the most

ubiquitous retrofit purchases being made for industrial

systems is to add measuring gauges, controlling activators,

and computer processors to existing machinery. The main

accomplishment of such a process control system is to

enhance the throughput and quality of a refinery with only

materials and small energy inputs.

Project life—7 years.

Capital and installation costs–$500,000.

Energy savings—$150,000 per year.

Crude oil atmospheric distillation unit.—lt is assumed that

two major crude oil distillation furnaces have been in

operation for many years. While relatively inefficient in

energy use, the two furnaces are nevertheless still

serviceable, Can their replacement be justified in energy

savings alone?

Project life—10 years,

Capital and installation costs—$12 million.

Energy savings— $3.2 million per year.

Counterflow heat exchanger. —Installation of a counterflow

heat exchanger to preheat air entering a furnace with the

exhaust stack gases from the same kiln.

Project life—10 years.

Capital and installation costs–$200,000.

Energy savings—$53,000 per year.

8. Refinery boiler control system. —Installation of a computer

control system to optimize burner efficiency in a boiler

furnace.

Project life—10 years.

Capital and installation costs—$3.75 million.

Energy savings—$820,000 per year.

gasoline to an equality between gasoline and

middle distillates.

The decline in energy intensity will be most

rapid in the 1980-90 decade owing to projected

improvements in operations and retrofit additions

to enhance heat recovery (see fig. 27). Computer

controls and process units, heat exchangers, regenerators, waste heat boilers, and the like are

expected to improve the efficiency of existing

units and fired heaters. I n the following 10 years

(1990-2000), new, more efficient processes

should be added to refinery operations to help

reduce energy intensity. These should be processes such as fluid coking with gasification, polymerization, and so forth. It is interesting to note

that, given the projected decline in consumption

of refined petroleum products, 80 percent of the

expected improvement in energy efficiency in SIC
Ch. 5—The Petroleum Refining Industry ● 109

4.0

3.5

3.0

2.5

2.0

1.5

1.0

0.5

0.0

Figure 26.—Petroleum Refining Industry Projections of Fuel Use and

Energy Savings by Policy Options,-

1990 and 2000

Fuel Use Projections

Natural

gas

1990

Oil Coal Purchased

electricity

2000

Ref No EITC Btu Cap Ref No EITC Btu Cap

case ACRS tax avail case ACRS tax avaiI

Fuel Savings Projections

1.0 

1990

0.3

0.2

0.1

0.0

2000

Ref No EITC Btu Cap Ref No EITC Btu Cap

case ACRS tax avaiI case ACRS tax avaiI

SOURCE Office of Technology Assessment
110 ● Industrial Energy Use

Table 27.—Projected Changes in Petroleum Refining Production

Between 1985 and 2000a

1980 1985 1990 2000

Gasoline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4 6.4 (42%) 5.7 (380/.) 4.9 (350/o)

Middle distillates . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.0 4.4 (290/o) 4.7 (32%) 4.7 (34°/0)

Naphtha . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.5 0.6 0.7 0.9

Petrochemical feedstocksb . . . . . . . . . . . . . . . . . . . . 0.6 1.0 1.2 1.3

Residual oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4 1.5 1.4 1.0

Others C . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3 1.2 — — 1.2 1.1

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.2 15.1 14.9 13,9

a

ln million barrels of oil refined per day and percent,

bOther than naphtha.

clnclude~=phalt paving matedals, Petroleum coke, Iubricatingoiis,~d the ‘ike.

SOURCES: Department of Energy, Petroleum Supply Annual Report, 1901; and Office of Technology Assessment projection

using ISTUM.

r

1970 1975 1980 1985 1990 1995 2000

Year

SOURCE Office of Technology Assessment

29 will be attributable to add-on energy conservation units over the next two decades. Only 20

percent will be attributable to new processes.

Projected Effects of Policy Options

Option 1: Removal of Accelerated

Depreciation

OTA projects very little change in petroleum

refining energy use patterns if the ACRS is removed, as shown in figure 26. There should be

a slight increase in natural gas used (1 percentage point or less) and a slight increase in coal

used. Cogenerated electrical energy production

would be down because the depreciation in newly installed equipment would not be as rapid and

would therefore be less attractive. overall energy

use is projected to increase less than 1 percentage

point above that of the reference case.

This analysis is corroborated by an examination of table 28. There are no changes in any of

the IRR values that are greater than 1 percentage

point, nor are there any changes in the ranking

of any project.

The top three projects are obviously attractive

investments. They represent the type of projects

corporations readily take on when energy costs

begin to approach 1981 levels. And these projects maintain their attractiveness even without

the added incentive of ACRS depreciation. These

projects will be done, assuming capital is available, because energy, along with materials and

labor, is expensive, and each of the top three

projects represents a means of reducing costs

without changing the nature of the products produced.

Option 2: Energy Investment Tax Credits

OTA analysis suggests a less than l-percent

change in overall energy use as a result of a

10-percent targeted energy investment tax credit

(EITC). And, perhaps surprisingly, the change is

projected to be a slight increase, as shown in

figure 26. This result arises from a projected increase in cogeneration, which comes about primarily from using natural gas to produce both

steam and mechanical or electrical energy. Coal

use is also projected to increase by several percentage points as coal-fired boilers are used to

raise steam, and coal is used for process heat.

Table 28 shows the impact of an EITC on the

IRR values of representative petroleum refining
Ch. 5—The Petroleum Refining Industry . 111

Table 28.—Effects of Policy Options on IRR Values of

Petroleum Refining Industry Projects

IRR with policy option

$1/MMBtu tax on

Reference ACRS 10-percent natural gas and

Project case removed EITC petroleum products

1. Inventory control . . . . . . . . . . . . . . 87 87 87 87

2. Electric motors . . . . . . . . . . . . . . . 43 43 48 51 3. Catalytic air preheater #1 . . . . . . . 30 30 34 37

4. Catalytic air preheater #2 . . . . . . . 20 20 23 25

5. Crude unit furnace

replacement . . . . . . . . . . . . . . . . . . 17 17 21 24

6. Computerized process

control . . . . . . . . . . . . . . . . . . . . . . . 16 16 22 19

7. Counterflow heat exchanger . . . . 15 15 18 19

8. Boiler plant control system . . . . . 14 14 17 18

SOURCE: Office of Technology Assessment.

industry projects. As shown, the impact on the

project was modest. Most IRR values increased

by 3 to 5 percentage points, and only one project, the computerized process controller, moved

up in ranking, but only by 1 point. It is unlikely

that this change in ranking would affect management’s decision to take on, for example, the

crude unit funace replacement. Such factors as

total cost, age of the furnace, perceived reliability

of the computer process controller, and the like,

would have more impact on the decision.

In evaluating the potential effect of energy tax

credits, it is necessary to recognize that applicability of such credits is not guaranteed. In

order to avoid having such credits treated as just

one more general investment tax credit, the Internal Revenue Service (IRS) can be expected to

examine proposed applications of an energy tax

credit closely. To judge from experience, IRS examinations and rulings may be expected to delay

the application of such credits and to limit their

use to a perceived energy-saving portion of an

investment, even though the entire investment

must be made in order to achieve the energy savings.

Option 3: Tax on Premium Fuel

OTA analysis suggests that a fuel price increase

of $1/MMBtu, whether in the form of a tax or

market-dictated increase, would have the effect

of slowing the penetration of cogeneration technology into SIC 29 relative to what is projected

to occur in the reference case. And because cogeneration is slowed, natural gas use will be less

and purchased electricity will be greater than that

in the reference case.

However, the greatest effect would be to promote fuel switching away from premium fuels

and toward coal for both coal boilers and for

hydrogen production. The combined effect of the

use of more coal technologies with the decrease

in cogeneration and increased purchase of electricity from utilities leads to a slight increase in

total energy demand.

Table 28 presents the projected impact on IRR

values of the petroleum refining projects. The fuel

price increase does increase IRR values by 5 to

7 points, except for the inventory control option,

which is a project with no premium fuel use.

However, none of the projects changed its relative ranking. While the list of projects may not

be all inclusive of those available to a refinery’s

management, it does illustrate that other factors

besides IRR would be needed to change the ranking of a project.

An energy tax can have undesirable effects on

the refining industry. Refining costs would increase, and product prices would necessarily follow. imported products would become more

competitive, perhaps necessitating specific tariffs

or other measures to protect U.S. refiners and

their industrial customers. And refiners would

have less ability to invest in energy-saving equip-
112 ● Industrial Energy Use

ment to the extent that they couldn’t pass on their

increased costs.

Option 4: Low Cost of Capital

OTA analysis suggests that of all the legislative

options examined, the low cost of capital would

cause the greatest change in energy use compared to the reference case. The low cost of

capital would promote the use of cogeneration

and retrofit conservation technologies, thereby

producing more self-generated electricity and a

reduction in waste energy. The most significant

shift in fuel mix would occur in steam methane

reforming, where partial oxidation of coal to produce hydrogen displaces the use of natural gas.

Table 29 presents the OTA analysis of the impact of a decrease in interest rate on moneys borrowed to undertake the representative petroleum

refining projects. In this instance, the reference

case figures have been changed to reflect a situation where two-thirds of the money needed to

finance the project is borrowed at a 16-percent

interest rate. One-third of the cost wouId come

from funds already in hand in the firm. When the

interest rate is lowered to 8 percent, two of the

projects move up in ranking. Although the catalytic air preheater # 1 project would advance to

the second place, it was already very attractive.

Even without borrowing, the IRR value was above

30 percent with borrowing, it soars to 83 percent.

The shift to above 100 percent will not significantly increase the attractiveness of an already desirable project,

Because of the decline in interest rates, all the

projects have become more attractive, at least as

measured by I RR values. Other factors such as

total cost, plant downtime, and the like, however,

would also affect the decision about whether to

invest in these projects. It must again be emphasized that investments for energy savings have

no special priority over the petroleum industry’s

need to spend vast amounts of capital in essential exploration and producing activities and to

adapt refineries to the changes in available crude

types and to the changing demands of the products market. Many such investments will be considered necessary by industry management and

thus will take priority in discretionary capital expenditures.

Table 29.—Effect of Lower Interest Rates on IRR Values of

Petroleum Refinery industry Projectsa

Reference case IRR IRR with policy

with 16 percent options: interest

Project interest rate rate of 8 percent

1. Inventory control . . . . . . . . . . . . . . . . . . . . . . . . . . .

2. Electric motors . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3. Catalytic air preheater #1 . . . . . . . . . . . . . . . . . . . .

4. Crude unit furnace replacement . . . . . . . . . . . . . .

5. Catalytic air preheater #2. . . . . . . . . . . . . . . . . . . .

6. Computerized process controller . . . . . . . . . . . . .

7. Counterflow heat exchanger . . . . . . . . . . . . . . . . .

8. Boiler plant control system . . . . . . . . . . . . . . . . . .

385

93

83

76

70

36

33

413

370

97

107

90

89

44

38

59

aAll projects are assumed to be two-thirds debt financed and one-third equity financed

SOURCE: Office of Technology Assessment.

Contents

Page

Industry Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115

Product Mix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115

Economics of Chemicals Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116

Energy and Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119

Production Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119

Energy Use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120

Energy Conservation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . + . . . . . . . . . . . . . . . . . . 121

Energy Conservation Through Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126

Investment Choices for the Chemicals industry. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128

impacts of Policy Options on the Chemicals Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

investment Strategy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130

The Reference Case . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130

Projected Effects of Policy Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

TABLES

Table No. Page

30. Definition of SIC 28-The Chemicals and Allied Products Industry.. . . . . . . . . . . . . 115

31. Top Ten Chemicals Produced by Chemical lndustry,1981 . . . . . . . . . . . . . . . . . . . . 116

32. Energy-intensive Processes in Chemical Manufacturing . . . . . . . . . . . . . . . . . . . . . . . 119

33. Comparison of 1981 and 1972 Energy Consumption in the Chemicals industry . . . 122

34. Operational and Design ProblemsinEnergy-intensive Equipment . . . . . . . . . . . . . . . 125

35. Operational and Design Problems in Heat-Transfer Equipment . . . . . . . . . . . . . . . . . 126

36. Funding Sources and Funding Uses of Cash Flow of Fifteen Largest Chemical

Companies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128

37. Types of Energy Efficiency-Improving Projects Undertaken by Chemical

Manufacturing Association Companies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

38. Chemical industry Projects To Be Analyzed for lnternal Rate of Return (lRR)

Values . . . . . . . . . . . . . . . . . . . . . . . . . . 0 . . . . . . . . ........0 . . . . . . . . . . ........0 131

39. Historical and Assumed Growth Rates in SlC 28 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132

40. Reference Case Energy Use Projection, by Fuel 1980-2000 . . . . . . . . . . . . . . . . . . . 132

41. Reference Case Energy Use Projection, by End Use: 1985-2000 . . . . . . . . . . . . . . . . 132

42. Reference Case Energy Use Projection, by Process Heat Fuel 1985-2000 . . . . . . . . 132

43. Reference Case Energy Use Projection, Steam and Power Fuel 1985-2000 . . . . . . 132

44. Effects of Policy Options on IRR Values of Chemical Industry Projects.. . ........’ 134

45. Effect of Lower interest Rates on IRR Values of Chemical industry projects. . . . . . . 136

FIGURES

Figure No. Page

28. Structure of Organic Chemicals Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

29. Capital Spent in the Chemicals industry, 1971-81 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118

30. Comparison of Chemicals Industry Energy Use and Production Output,

1972 and 1981.. . . . . . . . 122

31. Chemicals industry Energy Intensity Projection, 1970-2000 . . . . . . . . . . . . . . . . . . . . 132

32. Chemical Industry Projections of Fuel Use and Energy Savings by Policy Options,

1990 and 2000... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133
Chapter 6

The Chemicals Industry

INDUSTRY OVERVIEW

Of the four industries chosen for study for this

report, the chemicals industry is by far the most

complex. First, it produces several thousand

products, in contrast to steel, paper, and petroleum refining corporations, which produce a relatively limited set of commodity products in large

quantities. Second, it is more diverse—i. e., it has

more capital investment choices and a less cohesive market. Within its SIC 28 classification are

eight three-digit subcategories, as shown in table

30. Finally, the chemicals industry has the distinction of using the most energy of the four industries. 1 The 1980 Annual Survey of Manufactures

shows its energy use to be 2.7 Quads, that is, 22

percent of all energy purchased by the industrial

sector.

Industry Structure

More than 100 companies in the chemicals industry report energy use data. Interestingly, over

‘ U.S. Department of Commerce, Bureau of the Census, 1980 Annual Survey of Manufactures: Fuels and Electric Energy Consummed,

M80(AS)-4, 1, Washington, D. C., 1982,

Table 30.— Definition of SIC 28—The Chemicals and

Allied Products Industry

This major group includes establishments that produce

basic chemicals and establishments that manufacture products by predominantly chemical processes. Establishments

classified in this major group manufacture three general

classes of products: 1) basic chemicals, such as acids,

alkalies, salts, and organic chemicals; 2) chemical products

to be used in further manufacture, such as synthetic fibers,

plastics materials, dry colors, and pigments; and 3) finished

chemical products for use by other industries, for example,

paints, fertilizers, and explosives.

SIC 28 is broken down into the following eight subgroups:

SIC Title

281 . . . . . . . . . Industrial inorganic chemicals

282. ....... , Plastics and manmade fibers

283. . . . . . . . . Drugs

284 . . . . . . . . . Soap, detergent, and cleaning preparations

285. . . . . . . . . Paints and varnishes

286. . . . . . . . . Industrial organic chemicals

287. ...., . . . Agricultural chemicals

288. ...., . . . Miscellaneous chemical products

SOURCE Office of Management and Budget, Standard Industrial Classification

Manual, 1972.

half of the top SO chemical producers are not primarily chemicals companies. z Many are petroleum producers and refiners, such as Exxon and

Mobil. others produce chemicals only as part of

their business enterprise; e.g., Eastman Kodak,

Borden, and B. F. Goodrich.

OTA undertook an analysis of a number of

smaller firms that produce chemical products, to

determine if they exist in a different environment

and behave differently than do larger firms.3 I n

general, they do not. Small chemical firms tend

to be the developers of new products, rather than

new processes. They appear to gain competitive

advantage not by producing standard products

at lower cost, but by conducting research and

development (R&D) that produces new products

or new formulations for existing products.

Product Mix

The top 10 chemicals produced by chemical

companies are shown in table 31. Many of the

top 25 chemicals produced by chemical companies are used in agriculture, which accounts

for their large production volume; among these

are sulfuric acid, ammonia, and phosphoric acid.

Other chemicals are used as feedstocks in the

production of rubber and plastic materials, such

as polyethylene and synthetic fabrics. Within SIC

286 alone, products such as plastics, synthetic

rubber, nylon, and antifreeze are produced from

just three material feedstocks (see fig, 28).

In the past, chemicals production depended on

the large-scale production of acetylene manufactured from coal and on the development of a

number of processes and products using acetylene as a feedstock. Acetone and acetaldehyde,

originally made from acetylene, were used as raw

materials for pharmaceuticals, synthetic rubber,

‘Chem\cal and Engirreer/ng News, ‘‘Facts and Flgu res for the

Chemical Industry, ” June 14, 1982,

‘Technology and Economies, Inc., The /mpact of Se/ected Federa/

Polic{es on the Energy Use Patterns of Smaller Industrial Corporations, final report, OTA contract No. 233-4680.0, August 1982,

115
116 . Industrial Energy Use

Table 31.–Top Ten Chemicals Produced by Chemical Industry, 1981

1981 1981 1971-81

production production value annual

Rank Name (lb X 10’) ($ x 10’). -growth rate (%) . , Produced from Maior end use

1. Sulfuric acid 81.35 $3,250 3.4 % Sulfuric dioxide from sulfur or

(H2SO.)

2. Ammonia (N H,)

3. Nitrogen (N2)

38.07 2,500 2.7

37.31 550 11.2

4. Lime (CaO) 35.99

5. Oxygen (02)

6. Ethylene

(H2C=CH2)

7. Caustic soda

(NaOH)

8. Chlorine (Cl2)

9. Phosphoric acid

(NH3N03)

10. Nitric acid

(HNO3)

800 –0.4

34.93 525 2.9

28.87 7,000 4.6

21.30 2,500 1.0

21.12 1,500 1.2

19.83 4,000 5.2

18.08 2,300 1.7

SOURCE. Chemical and Engineering News, June 14, 1982, p. 40

textiles, and the like. Now petroleum refining is

used to produce a large number of petrochemical

feedstocks.4 For the majority of modern organic

materials, acetylene has been replaced as a feedstock by other intermediates, notably ethylene

and propylene, which are derived from ethane

and propane, now readily available from petrochemical sources. Acetaldehyde, now also declining in importance, is currently made from

ethylene rather than from acetylene. Ethanol,

once derived entirely from fermentation (before

1930), is now manufactured commercially by hydration from ethylene. Acrylonitrile is now made

4Mellon Institute, Final Report on the Industrial Energy Productivity Project, Vol. 3, The Petroleum Refining industry, DOE contract No. DE-ACO1 -79CS-40151, September 1982.

smelter gases: reacted with

water.

Catalytic reaction of nitrogen

(from air) and hydrogen (from

natural gas).

Separated by distillation from

air at cryogenic temperatures.

Limestone (CaCO3) heated to

remove CO2, then hydrated to

make Ca(OH)2; CaO.

Separated from air at cryogenic

temperatures.

Thermal and catalytic cracking

of hydrocarbons.

Electrolysis of salt brine.

Electrolysis of salt brine. Recovery from hydrochloric acid,

coproduction in making metals,

caustic potash, or potassium

nitrate.

Reaction of phosphate rock and

sulfuric acid: burning elemental

phosphorus and subsequent

reaction with water,

Reaction of ammonia with air,

or sulfuric acid with sodium

nitrate.

Fertilizers-700/O; chemical

manufacture—150/o; metals

recovery and petroleum

refining.

Fertilizers-80%; plastics and

textile fibers—lOO

/O; explosives

—5%.

Inert blanketing atmospheres:

chemical processing— 14%

electronics—1 5%; metals—

5%; freezing agent—21%;

aerospace—8°A.

Metallurgy (in steel flux) —45%;

chemical manufacture— 1OO

/O;

potable water treatment—10%;

sewage and pollution control—

50/o; pulp and paper manufacture—5%.

Primary metal manufacture—

300/o; health services-130/o;

metal fabricating—330/0.

Fabricated plastics—650/O; antifreeze—lOO

/O; fibers—50/O;

solvents—50/o.

Chemical manufacture—500/O;

pulp and paper—150/.;

aluminum—50/o; petroleum

refining—50/0; soap and detergents—5°/0.

Chemical manufacture—500/O;

plastics— 1 5°/0; solvents—

1 50/0.

Fertilizers—850/o; animal feed

—5% .

As ammonium nitrate fertilizers

—950/o.

from propylene. Benzene and xylene, once largely obtained from coal tar, are now primarily derived from petroleum refining. Principally in response to demands for synthetic substitutes for

naturally occurring industrial raw materials, especially those strategic materials whose access

is controlled by foreign powers, the chemicals industry has developed new processes and technologies.

Economics of Chemicals Production

The overall economic health of the chemicals

industry, compared to that of steel and petroleum

refining, is good. As determined by a Chemical
Ch. 6—The Chemicals Industry ● 117

99-109 0 - 83 - 9
118 ● Industrial Energy Use

and Engineering News survey, s 1981 revenue was

$182 billion, with a net income of $12.6 billion,

or a 6.8-percent return, down slightly from the

1979 figure. Over the past decade, profit margins

within the industry have averaged between 8 and

9 percent.

Their high profitability has allowed chemical

companies to make investments in capital equipment and in research at levels much higher than

those made by the other three industries studied

by OTA. In 1981, the chemicals industry invested

over $13 billion in new plant and equipment, up

from a 1980 level of $12.6 billion.6 Figure 29 presents the capital investment trend for 1971-81.

Capital Investment

The chemicals industry spends approximately

one-third as much money on research as on its

entire inventory of capital projects. In 1981, this

amount was estimated to be $4.7 billion for

R&D.7 For comparison, the proportion of funds

spent on research, development, and demonstration (RD&D) by the other industries studied was

6 percent for steel, 4 percent for petroleum refining, and 5.5 percent for paper.

SChemica/ and Engineering News, “Facts and Figures for the

Chemical Industry,” June 14, 1982.

15U. S. Department of Commerce, Bureau of Economic Analysis,

1980 Annual Survey of Manufactures: Statistics for Industry Groups

and /ndustries, A80(AS)-1, 1982.

‘Chemical and Engineering News, op. cit.

Figure 29.—Capital Spent in the Chemicals Industry,

1971-81

J

u 1970 1972 1974 1976 1978 1980 1982

Year

SOURCE: Bureau of Economics, Department of Commerce.

Imports and Exports

Both exports and imports increased substantially over the past decade. From 1971 to 1981,

exports increased by 450 percent and imports increased by 513 percent. The U.S. chemicals industry exported products in 1981 valued at

$21.19 billion, accounting for about 10 percent

of the total U.S. exports that year. With imports

valued at $9.88 billion in 1981, a total positive

trade balance resulted of over $11 billion.8 Because of its extensive international trade, the U.S.

chemicals industry is concerned about the implementation of tariffs and other barriers to trade

in foreign countries.

In the next decade, it is predicted that the U.S.

chemicals industry will export less organic chemicals and plastics and more of the specialized

chemical products. It will also import more of the

basic primary chemicals, process the chemicals

in domestic plants, and export the final products.

U.S. producers of industrial organic chemicals

are expected to have serious competition from

foreign, state-owned petrochemicals complexes

in Latin America and the Mideast. (However,

state-operated organic chemicals plants in the

persian Gulf are not expected to be a major competitor in world markets in the near future.) Such

plants, whose operations are based in part on political objectives such as job creation and foreign

currency earnings, and not on the profit motive,

are able to undercut the prices of U.S. suppliers.

Domestic producers may thus be unable to compete in foreign markets. Unless substantial import

restrictions are applied, they may have difficulty

maintaining their domestic market.

producers of the two major chemicals (ammonia and phosphoric acid) used by the agricultural sector have completely different outlooks

for the future in world trade. In 1985, the United

States is expected to account for 25 percent of

world phosphoric acid production.9 Exports,

which have been high, should remain high for

at least the next decade. Phosphate fertilizer production plants are clustered near the large sea-

‘ibid.

9Mellon Institute, Final Report on the /ndustria/ Energy Productivity Project, Vo/. 5: The Chemicals /ndustry, DOE contract No.

DE-ACO1-79CS-401 51, September 1982.
Ch. 6—The Chemicals Industry ● 119

ports in this country, reducing the necessity for

more expensive rail transport. 1 n fact, exports of

phosphoric acid may be limited not by the world

market competition, but by the availability of U.S.

port facilities.

Ammonia producers will face a tightening foreign market in the next decade.10 Imports from

‘“I bid.

relatively unreliable sources (e.g., Mexico and

Russia) have increased substantially. In 1970, ammonia imports amounted to only 3.5 percent of

U.S production. By 1978, imports were nearly 9

percent of total domestic production and have

been increasing since. This situation typifies some

of the complex connections between the domestic and the international concerns of the chemicals industry.

ENERGY AND TECHNOLOGY

Production Processes

For the purposes of energy accounting, it is economical to classify the many unit operations that

occur in the chemicals industry into a small number of groups. One way to identify these groups

is on the basis of the equipment used to effect

the chemical transformation. Table 32 presents

the six most energy-intensive processes.

Table 32.—Energy-lntensive Processes in

Chemical Manufacturing

Electrolysis.—Electrolysis includes all industrial electrolytic

processes in which electricity is used in direct chemical

conversion.

Fuel-heated reaction. —Processes that require some type of

heat to force a chemical reaction to take place can be subdivided into low- and high-temperature operations. Energy

sources include steam (except for high-temperature reaction), natural gas, residual oil, distillate oil, and even

fluidized-bed coal combustion. Where precise temperature

regulation is required, natural gas and distillate fuel oil are

used.

Distillation. —Distillation processes include those that require physical separation of end products from both feedstocks and byproducts by evaporation and condensation.

Refrigeration. —Refrigeration includes processes that compress and expand a refrigerant, such as ammonia or a

fluorocarbon, for the purpose of cooling feed stocks or products below ambient temperatures.

Evaporation.-Evaporation includes those processes that use

passive-evaporation cooling. In general, the evaporated

water is lost to the atmosphere, and the heat energy is unrecoverable.

Machine drive.—Many chemical industry processes use

machine drive to pump, compress, or move feedstock and

end product materials. Machine drive arises from electric

motors, steam turbines, or gas turbines. A subcategory of

machine drive processes—mixing and blending (especially

in polymerization processes)—can be very energy intensive due to the high viscosity of the materials.

SOURCE” Adapted by OTA from Roberl Ayres, Final Report on Future Energy Consumption by Industrial Chemicals Industry, DOE contract No

DE-AC01-79CS40151 , Oct 7, 1981.

As an example of how these unit processes are

used to produce particular chemicals, consider

the production of ethylene and ammonia. 11 12

Both are produced in large quantities, 27 million

and 38 million lb, respectively in 1980. Both consume large amounts of energy. Together, they illustrate how a typical chemical commodity is produced, when the energy is consumed, and what

particular opportunities exist to use energy more

efficient I y.

Ethylene is used as an intermediate in the production of plastics, rubber, and synthetic fibers,

which are, in turn, used in industrial and consumer products. With its byproducts and derivatives, ethylene is a cornerstone in the petrochemical industry. It is produced by the reaction

of steam and hydrocarbon feedstock, followed

by thermal cracking. The resulting product mixture is cryogenically cooled to – 150° F and compressed to 450 to 600 psi, after which the ethylene is distilled from its feedstock and byproduct

materials. The combination of heated reaction,

compression, and cryogenic cooling make ethylene production very energy-intensive.

Ammonia is used as a major agricultural fertilizer, either directly or in combination with nitric

acid as ammonium nitrate. It is synthesized by

the reversible reaction of nitrogen and hydrogen,

a reaction carried out under elevated pressures

of between 80 and 1,000 atmospheres, depend-

‘‘S. D. Lyon, “Development of the Modern Ammonia Industry, ”

10th Brotherton Memorial Lecture, Chemistry and /ncfustry, vol.

6, September 1975.

12L. L. Gaines and s. Y. Chen, Energy and Materia/ F/OWS in r~e

Production otO/efins and Their Derwatives, Argonne National Laboratories AN L/CNSV-9, August 1980.
.

120 . Industrial Energy Use

L

\

* I 9 .

.\

,

1

.

‘

-

/ v

Photo credit: PPG Industries, Inc

Major plant for the production of ethylene glycols is being readied for late 1983 operation at PPG Industries’ Beaumont,

Tex., complex. Pittsburgh-based PPG is a supplier of glycol for making polyester fibers, photo film, and plastic bottles

ing on the specifics of the process, and in elevated

temperatures of 750° to 1,000° F. Nitrogen used

in ammonia production comes from the atmosphere. Hydrogen comes from the partial oxidation and steam reforming of natural gas (i.e., producing carbon monoxide and hydrogen by partially burning natural gas hydrocarbon feedstock).

The resulting product mixture must be cryogenically cooled and partially distilled to remove

argon, urethane, and unreacted nitrogen byproducts. This production process is similar to that

used in ethylene production in that high-temperature reaction is followed by low-temperature

purification processes.

Energy Use

According to 1977 Census of Manufactures

data for the chemicals industry, nearly 57 percent of the energy from purchased fuels and electricity came from natural gas, over 16 percent

from electricity, 11 percent from coal, and 11 percent from fuel oil.13 Within the Industrial inorganic Chemicals subgroup, the fuel energy

breakdown in 1976 was roughly as follows: natural gas, 40 percent; electricity, 40 percent; coal,

1 J(J .S. Depa~rnent Of Commerce, Bureau of Cen SUS, 1977 cf2nsus of Marrufacturers, Statistics for Industry Groups and industries,

Vo/ume //: /ndustry Statistics, Part 2 SIC Major Groups 27-34, 1977.
Ch. 6—The Chemicals Industry • 121

12 percent; and fuel oil, 8 percent. In the event

of fuel shortages, manufacturers indicated that

only 38 percent of natural gas needs could be

met by substitute fuels (mainly fuel oil), and less

than 60 percent of fuel oil needs could be met

by substitute fuels (mainly natural gas).

Within the Industrial Organic Chemicals subgroup, the fuel energy breakdown in 1976 was

roughly as follows: natural gas, 70 percent; coal,

8 percent; and electricity, 7 percent. Fuel oil

usage was not shown for this industry. Manufacturers indicated that only 27 percent of natural

gas needs could be met quickly by substitute

fuels; 32 percent of coal needs could be met by

other fuels (mainly natural gas).

Many of the generating processes in the chemicals industry are energy-intensive. Generation of

the number two chemical, ammonia, is one example. Most of the energy in that process is used

to generate hydrogen, as well as to break the extraordinarily tight nitrogen triple bonds.

In another example, sodium hydroxide (NaOH)

and chlorine (CI2) are produced by passing a

strong electric current through an aqueous brine

solution, again a very energy-intensive process.

In contrast, sulfuric acid is made via processes

which, when summed, are energy producing.

Output from the chemicals industry, as measured by the Federal Reserve Board index, rose

50 percent from 1972 to 1981 .14 Energy use fell

4.6 percent in 1980 to below the 1972 level. The

decrease (1 972-81) could be seen as even larger

if electricity were counted at net heat value (3,412

Btu/kWh) because part of the decrease is masked

by a fairly sharp (30 percent) increase in the use

of purchased electricity. The major savings from

1972 to 1981 occurred in the use of natural gas,

which was down by 244 trillion Btu from 1972

to 1979 and by another 75 trillion Btu from 1979

to 1980. Use of coal and purchased steam were

down slightly, while use of residual fuel oil and

“other gases” was up moderately.

One trend that has strongly affected fuel use

patterns was the switch from oil to coal as a fuel

for steam generation. After 1965, use of coal

lqFederal ReSerVe Board, /ndustrja/ Production, Publication LC77-

93930, December 1977.

declined sharply so that in 1973, coal provided

22 percent of boiler fuel. Since then, this trend

has reversed; and in 1981, coal provided almost

half of the fossil fuel used for steam generation.15

Some companies have forecast their use of coal

for steam to increase to 70 or 75 percent by the

turn of the century. Vendors state that with new

packaged boiler designs (including economizers)

thermal efficiencies as high as 83 percent can be

obtained from coal-fired boilers—efficiencies are

significantly better than with older technology.

Some custom-designed units can exceed even

these efficiencies by optimizing systems for particular plants.

Energy Conservation

Over the last decade, the chemicals industry

has increased the efficiency of nearly all its

energy-consuming processes. The efficiency of

processes using natural gas, distillate oil, and

residual oil has increased dramatically, while the

efficiency of those processes using electricity has

not changed, According to the Chemical Manufacturers Association (CMA) aggregate trade association reports, the 110 chemicals industry firms

reporting in 1981 had improved their energy efficiency 24.2 percent per unit of product compared to their 1972 production (see fig. 30 and

table 33).

Most improvement resulted from reduced petroleum product use; distillate fuel oil and residual

fuel use dropped from a combined 211 billion

to 122 billion Btu. Moreover, since 1976 there

has been a 5-percent decrease in Btu consumed,

most of it occurring in decreased premium fuel

consumption. Du Pont, for example, improved

its energy efficiency dramatically in the 1970’s

and early 1980’s to the point where in 1981 it

used only 97 percent of the energy used in 1972,

while units of production—measu red in constant

dollar sales of product–increased by 36 percent.16 Du Pont’s achievement may be slightly

better than that of the chemicals industry as a

whole but is probably fairly representative.

I su. s Depaflment of Commerce, Bureau of the Census, Annua/

Survey of Manufactures: Fuels and Electric Energy Consummed,

A(72)AS-4.1 through A80(AS)-4.1 .

16 James Borden, Ecorlornics and Policy Manager, Energy and ‘aterials Department, E. 1. du Pent de Nemours, Inc., Wilmington, Del.
122 ● Industrial Energy Use

Figure 30.—Comparison of Chemicals Industry

Energy Use and Production Output, 1972 and 1981

SOURCE.

.

1972 1981

.

- 1

.

—

Energy Production Energy Production

use use

Coal Petroleum

Natural Electricity and Production

gas steam index

Chemical Manufacturing Association and Federal Reserve Board.

OTA analysis indicates that among the factors

that have brought about this energy efficiency improvement are the following:17

Much of the energy savings have come from

improvements in energy management techniques. This is especially true in the area of steam

generation and distribution. Among the specific

items identified by OTA are improved maintenance of steam lines, thermostat setbacks, and

lighting.

Significant energy savings have resulted from

improvements in the operating practices of fueled

reactors and fired heaters. Many of these improvements have come through the use of computerized burner controls, which is a part of the

overall trend in many industrial processes toward

computer control with feedback optimization.

Improvements in energy efficiency over the

past 8 years have not, for the most part, resulted

from major process substitution. There are some

exceptions including the continued phasing out

of synthetic soda ash production in favor of extraction from natural sodium sesquicarbonate,

and the continued substitution of the wet process for phosphoric acid production for the electric arc furnace. Overall, though, the chemical

manufacturing processes that were placed in the

17Adapted from Mellon Institute, Fina/ Report on the /ndustrial

Energy Project, Vo/. 5: The Chernica/s /ndustry, DOE contract No.

DE-AC01-79CS-401 51, September 1982, pp. 14-17.

Table 33.—Comparison of 1981 and 1972 Energy Consumption

in the Chemicals Industry

1981 1972

consumption consumption

Energy source (billion Btu) (billion Btu)

Electricity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 930,519.7 773,004.7

Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,272,211.9 1,680,160.5

Propane . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,415.1 3,130.1

LPG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33,234.5 1,580.5

Bituminous coal . . . . . . . . . . . . . . . . . . . . . . . . . . . 316,848.6 327,086.5

Anthracite coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,409.9 5,210.8

Coke. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,854,6 7,456.0

Gasoline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 905.3 745.4

Distillate fuel oil . . . . . . . . . . . . . . . . . . . . . . . . . . 17,644.6 32,777.0

Residual fuel oil . . . . . . . . . . . . . . . . . . . . . . . . . . . 104,227.3 178,746.1

Petroleum coke . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,118.1 —

Purchased steam . . . . . . . . . . . . . . . . . . . . . . . . . . 97,868.8 127,143.4

Other gases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 346,224.2 358,256.5

Other liquids. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44,691.2 50,120.7

Other solids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,170.9 18,206.9

Total energy consumption . . . . . . . . . . . . . . . . 3,167,334.7 3,563,625.1

SOURCE: “Energy Efficiency Improvement and Recovered Materials Utilization Report,” prepared for DOE by the Chemical

Manufacturing Association, June 1, 1982.
Ch. 6—The Chemicals Industry ● 123

—

early 1970’s have been supplanted by few new record of improvement. Consider the following

processes that account for any sizable portion of examples in energy efficiency improvements from

the chemicals industry’s energy efficiency im- plants throughout the world:

provement,

New and larger plants have saved energy without changing overall process characteristics found

in older plants. Very dramatic results can often

be achieved without process change when the

various energy-saving options are put together in

a new plant, as compared to using the same options by retrofitting an older plant. The fact that

newer plants are usually larger contributes to this

Ammonia (Haber-Bosch Process)

Btu)

Energy used per ton

Year produced (106

1917, . . . . . . . . . . . . . . . . . 800

1923-50 . . . . . . . . . . . . . . . 700

1965, . . . . . . . . . . . . . . . . . 450

1972 . . . . . . . . . . . . . . . . . . 400

1978 . . . . . . . . . . . . . . . . . . 354

Source S D Lyon, “Development of the Modern Ammonia Industry. " 10th

Brotherton Memorial Lecture, Chemistry and Industry, vol. 6, September 1975,

IR&T, Industrial Energy Study of the Industrial Chemicals Group, VOI 1, Executive

Summary vol. 2, Data Base, IRT-352-R, Arlington, Va. 1974

r -- ‘

-

Photo credit: PPG Industries, Inc.

Bigger and better.—A workman inspects new giant-sized chlorine production units (left) similar to those that will replace

outmoded units (right) at PPG Industries’ Lake Charles, La., chemicals complex. New production units using PPGdeveloped technology will reduce by about 25 percent the amount of energy required to produce chlorine and caustic

soda. Chlorine is used in making plastics and solvents, and in water purification. Caustic soda is used in chemical

processing and making pulp and paper
124 • Industrial Energy Use

Chlorine Cells (Diaphragm)

Electricity used per ton

Year produced (103 kWh/ton)

1916 . . . . . . . . . . . . . . . . . . 4,000

1947-73 . . . . . . . . . . . . . . . 3,000

1980 . . . . . . . . . . . . . . . . . . 2,200

Source The Conference Board, “Energy Consumption in Manufacturing’’ (Cam.

bridge, Mass Ballinger Publishing Co., 1974), Mellon Institute, Final Report Industrial Energy Productivity Project, vo/ 5 The Chemicals Industry, September

1982

Cyclohexane (Institute Francais du Petroles Process)

Energy used per ton produced

Year Steam (103 Ibs) Electricity (kWh)

1963 . . . . . . . . . 568 23.76

1965 . . . . . . . . . 358 15.00

1971 . . . . . . . . . 403 9.63

Source The Conference Board “Energy Consumption in Manufacturing” (Cambridge, Mass Ballinger Publishing Co , 1974)

The recovery of heat from exothermic or energyproducing reactions has improved. The use of

heat exchangers and heat economizing is more

widespread now than in 1972.

Significant improvements have been made in

the design of distillation columns for physical

separation. Improvements in physical separation

can have salutory effects for a chemical firm. First,

they can reduce fuel requirements. Second, they

can often decrease feedstock requirements.

While use of premium petroleum fuels has decreased since 1972, use of electricity has increased markedly. The ammonia subsector probably accounts for part of the recent increase in

purchased electricity. After 1965, most new ammonia plants incorporated single-train, centrifugal compressors, which are more economical

(though less efficient) than reciprocal compressors for capacities above 600 tons per day.

After 1970, there was also a brief trend toward

higher compression (5,000 psi compared to 2,000

psi in earlier plants) to increase the capacity of

the synthesis loop and reduce refrigeration equipment requirements. In both cases, lower capital

costs were achieved at the expense of higher

energy costs.

Recently, increased fuel prices (and natural gas

shortages) have resulted in reversals of some of

the above trends. Substantial investments in heat

recovery equipment and expander turbines (to

regain energy from ammonia as its pressure is

reduced) have been made in response to higher

energy prices in effect since 1973. Other types

of add-on units have been developed—e.g., cryogenic processes to recover hydrogen and nitrogen for recycle to the synthesis loop. In addition,

most of the low-cost, high-return, housekeeping

investments have been made.

Changing Feedstock Availability

A major concern of the primary chemical producers is the availability of feedstock materials.

Certainly, the industry’s susceptibility to a curtailment of feedstock supply was made evident

during the 1973 oil embargo. The United States

imports an ever-increasing amount of both organic and inorganic raw materials as it depletes its

domestic resources. The chemicals industry must

rely on relatively unstable countries for its supply of feedstocks.

To reduce their susceptibility to potential feedstock supply curtailments, chemical companies

are increasing their flexibility in the type of raw

materials they require. Olefin plants, for example, are shifting away from natural gas, ethane,

and propane toward the liquid feeds (naphtha,

gas oil, and eventually crude oil). Since plants that

process liquid feeds are more complex, because

of the initial gasification process required they are

equipped to shift feedstock mixes with relative

ease, although the plants are still constrained to

the same general area of operations.

Shortages of natural gas in the United States

have caused some feedstock shifts that are not

justified on energy efficiency grounds. Most

notably, natural gas is no longer the major feedstock for the production of hydrogen and acetylene. Naphtha and heavy gas oil are now the

major sources of cracking feedstock, and by 1990

it would not be surprising if crude oil were

cracked directly. Increased demand for byproducts such as propylene and butadiene is one of

the driving forces behind this shift. The cost and

scarcity of natural gas, the major feedstock for

ammonia, have removed domestic producers of

ammonia from the world market and made it difficult for them to compete with ammonia imports

from Russia and Mexico. As a result, domestic

firms have invested in researching methods for

producing ammonia from coal.
Ch. 6—The Chemicals Industry ● 125

Changing Feedstock Requirements

Chemical companies can reduce their total

feedstock requirements by increasing conversion

efficiencies. * This reduction can be done by

carefully monitoring present production processes or by switching to new, more efficient production processes. Substantial increases in useful

product-to-feedstock ratios can be achieved by

improving product separation techniques. By

carefully controlling the distillation process, a

manufacturer may reduce both his feedstock and

his fuel requirements. Ethylene plants have increased their production without increasing their

feedstock requirements, simply by routing the byproduct, propylene, through the ethylene production process.

Changing Processes

New processes that maximize conversion fractions or minimize the length of production chains

have also become important in the past several

years. For example, the accepted procedure for

the production of acetaldehyde was from ethane,

to ethylene, to ethanol, and finally to acetaldehyde. By 1980, most of the production of

acetaldehyde was directly from ethylene, resulting in a 15-percent improvement in the acetaldehyde-to-ethane ratio.

“Conversion efficiency is the percentage of feedstock material

that is successfully converted into a desired product.

In examining the processes for efficiently making industrial chemicals, four generalized ruIes

become apparent:

1.

2.

3.

4.

In

case

High-energy feedstocks (typically hydrocarbons) lead to highly efficient (i.e., minimum

number of process steps) processes for making a given chemical.

High-yield reactions that require only one

pass through a reaction chamber or vessel

are the most highly efficient means of chemical synthesis because they minimize feedstock and separation energy.

Energy efficiency is maximized when the

need for product separations is minimized.

High conversion reactions recycle energy

and minimize recovery.

the course of the workshop meetings and

study visits carried out as part of this analysis,

a number of energy-related problems were found

to be generic throughout the chemicals industry

—i. e., the problems were not specific to a particular chemical production facility. In tables 34

and 35, these problems are listed, along with the

typical approaches that have been used to circumvent or eliminate them.

Table 34 describes the problems associated

with the three largest energy-consuming activities

in the chemicals industry—furnace operation,

vapor compression, and distillation. A number

of the problems involve careful attention to

Table 34.—Operational and Design Problems in Energy-Intensive Equipment

Common problems Measures to overcome problems

Furnace combustion

Improper air/fuel ratio Provide instrumentation to measure oxygen content in flue

gas (automatic controls)

Leaks in furnace stacks Maintenance repair

Vapor compassion

Leaky compressor bypass valves Maintenance repair

Excess capacity in motor or turbine Replace with equipment matched to need

Improper suction pressure Replace with equipment matched to need

Increasing clearance to lower output Reduce compressor speed to lower output

Use of less expensive and less efficient turbines and Replace with high-efficiency equipment

compressors

Distillation

Erratic control of columns Provide automatic control

Excessive reflux, resulting in excessive component Produce minimum quality material

separation

Improper feed tray Change process operation

Nonoptimum distillation scheme Consider energy-saving possibilities such as multifeeds,

side product draw, or cascade distillation schemes

SOURCE Office of Technology Assessment.
126 ● Industrial Energy Use

Table 35.—Operational and Design Problems in Heat-Transfer Equipment

Common problems Measures to overcome problems

Steam traps

Faulty operation Monitor

Leaking traps Maintenance repair

Mismatch between steam line pressure and trap operating Use proper application and sizing

range

Steam tracing

Leaks Maintenance repair

Unnecessarily high steam temperature Substitute another fluid for steam

Heat exchangers

Fouling Maintenance repair

Higher than necessary temperature separation between Design for low-temperature differences by increasing heatfluid streams transfer surface area

SOURCE: Office of Technology Assessment.

maintenance and repair; others involve a more

precise matching between the pieces of equipment used in a process— i.e., matching electric

motors or gas turbines to mechanical drive requirements.

Table 35 describes the general problems found

by OTA to be associated with heat-transfer equipment. Again, many of the solutions involve maintenance and more precise equipment matching.

Energy Conservation Through

Technology

In considering the chemicals industry as a

whole, OTA finds that there are three main areas

for improving energy use: physical separation,

energy recovery, and product integration.

Physical Separation Technologies

Dramatic improvements in energy use can result from changes in the physical principles embodied in certain unit operations, especially in

physical separation.18 By far, the most widespread

technique of chemical separation used today for

mixtures of liquids is distillation. This is an energyintensive process, especially as practiced in the

former days of cheap fuel. Already, incremental

improvements in the process, retrofitted to existing installations, have achieved significant (e.g.,

25 percent) savings in many plants. Further improvements of comparable magnitude can be expected during the next few years through redesign and add-on units, though generally at higher

18Ibid., p. A-92.

costs. Steam distillation columns provide opportunities for heat recovery in larger, integrated

systems.

Alternative approaches to liquid separation include vacuum distillation, freeze crystallization,

and liquid-liquid (solvent) extraction. Dramatic

increases in the cost effectiveness of turbocompressors and advances in vacuum pumps and

cryogenic technology since the 1950’s have vastly

increased the relative attractiveness of both

vacuum distillation and crystallization relative to

steam distillation. However, the most promising

technique seems to be liquid-liquid extraction,

a process using a solvent with high affinity for one

component of the mixture but immiscible with

the remaining components. With this technique,

separation involves two steps: decanting and

closed-loop evaporation/condensation of the solvent. One company has already used the technique in a synthetic fiber plant, saving an

estimated 40,000 bbl of oil equivalent annually.

Other applications are being actively considered.

Dehydration (“drying”) using steam heat is

another energy-intensive separation operation

that can be dramatically improved in many cases.

A technique of squeeze-drying wet solids or fabrics (prior to steam drying) can be adapted from

technologies already developed in the paper industry, Separation (prior to disposal by incineration) of oily wastes or oil-soluble contaminants

from water mixtures can be accomplished by

using specially treated cellulose* that has an affinity for oil. The oil-soaked cellulose can subse-

*A technique developed for oil-spill containment.
Ch. 6—The Chemicals Industry • 127

quently be burned, or squeeze-dried and then

recycled.

Technologies for Energy Recovery and

Conservation

This category includes both heat recovery per

se and improved utilization of energy embodied

in high-pressure gases or steam .19 For example,

expansion turbines that recover kinetic energy

from ammonia as it comes off the high-pressure

synthesis loop are being increasingly used.

A variety of engineering schemes are available

to recover waste heat from boilers and exothermic reactors. A “bare burner” boiler, operating

with excess air to ensure complete fuel combustion, will typically produce stack gases at 600°

F with 6.2 percent oxygen, a stack gas heat loss

of 19 percent, and an overall thermal efficiency

of 78 percent. Modest improvements in efficiency

could be achieved by more precise monitoring

of stack temperatures, fuel and air intake, and

closed-loop process control. More significant improvements could result from using the heat of

the stack gases either to preheat intake air or intake water via an “economizer.” Overall efficiency of 85 percent, with stack gas temperatures reduced to 3500 F, is readily achievable by either

technique.

Many older plants used steam-driven vacuum

jets instead of electric-or turbine-driven vacuum

pumps because of lower capital costs. However,

in a typical application, the vacuum pump is up

to four times more efficient. For example, 80,000

Btu per hour are typically used for the electric

pump versus 300,000 Btu per hour for the steam

jet. Most existing steam jet-driven vacuum systems will probably be replaced by 199o, except

in those situations of low pressure and low flow

where they will continue to have an economic

advantage.

Production Integration Technologies

Integration is a strategy for justifying energy and

waste recovery that would not otherwise be economically justified .20 The simplest example is

cogeneration of electricity and steam. Most firms

‘

9

1 bid., p. A-94.

20lbid., p. A-97.

in the chemicals industry have several applications of cogeneration under active consideration—in some cases, based on the use of process wastes as fuel. One company, perhaps further along than most, produced 25 percent of its

1980 electricity requirements from onsite cogeneration, a proportion expected to increase to 40

percent by 1985.

Cogeneration opportunities exist to produce

electricity or mechanical shaft power as a byproduct of existing steam systems. For instance, in one

pIant an existing steam boiler produced 300- and

40-psi steam (as needed in the plant). By modifying the boiler to produce steam at 800 psi and

800° F, and interposing a turbogenerator (with

exhausts at 300 and 40 psi), enough electricity

to supply the plant was generated. Since, utility

electricity normally requires 10,000 Btu to produce 1 kWh of electricity, and this operation used

4,200 Btu to produce 1 kwh of electricity, there

was a net energy savings of 5,800 Btu/kWh. Many

applications such as this will doubtlessly be found

in the 1980’s.

Potential savings from production integration

extend far beyond the case of cogeneration, however. Production of intermediates, such as ethylene and butadiene, is increasingly being integrated into petroleum refining complexes. This

trend will be accelerated by the shift toward

heavier cracking feedstocks such as heavy gas oil

or fuel oil because of the greater importance of

coproduct ion.

Integration of the production of ethylene, propylene, and a wide range of petrochemicals from

a naphtha-based (aromatics-based) scheme is a

strong possibility by 1990. Another option would

be to integrate ethylene and acetylene production with ammonia and/or methanol. Ethylene/

acetylene coproduction will become increasingly

attractive as distillate prices rise and heavier

feedstocks are used, and will undoubtedly result

in some downstream process switching as acetylene again becomes competitive with ethylene as

a feedstock for acrylates, vinyl acetate, and vinyl

chloride.

In the United States, at least, there is considerable interest in redeveloping coal-based

chemical technologies via synthesis gas. Synthesis
128 . Industrial Energy Use

gas is currently produced mainly by steam reforming natural gas in the presence of a catalyst

to yield a mixture of carbon monoxide and hydrogen (CO-H 2). This process is the basis of most

commercial methanol production. In recent

years, there has been a good deal of interest (supported by the Department of Energy (DOE)) in

coal gasification by a similar technique, resulting

in ammonia and/or methanol, the obvious firststage chemical products. Interest in methanol is

amplified by the possibility that it may be a viable

coal-based alternative to gasoline motor fuel. For

these reasons a number of large-scale methanol

synthesis processes are under active development. It is quite likely that methanol will grow

in importance as a chemical intermediate and

that a significant fraction of its 1990 production

(perhaps 5 to 10 percent) will be derived from

coal.

INVESTMENT CHOICES FOR THE CHEMICALS INDUSTRY

Given traditional means of accounting for corporate funds, major corporations in the chemicals

industry can finance investments by either internally or externally generated funds. Within the

internal category, there is net income, depreciation, deferred taxes, or advanced tax credits.

From external sources, there are long-term debt

and, in some cases, equity stock sources. The first

part of table 36 presents data for 1979, 1980, and

1981 on-the funding sources for the 15 largest

chemical companies in the United States. The

second part of the table shows how the 15 largest

chemical companies have allocated their moneys

over the past 3 years. As shown, these major corporations devoted over 50 percent of their cash

flow to capital expenditures in 1980.

CMA, in reporting energy conservation improvements under DOE’s Industrial Energy Reporting Program, listed the aggregate number of

energy-related projects undertaken by those 110

companies participating in the CMA report. Table

37 lists the generic categories of these projects.

The diversification of the projects in the list

reflects the diversity of the industry itself.

It is unlikely that the trends in energy usage in

the chemical industry since 1973 will simply continue. Although, it is implicitly assumed that continued rising energy costs will remain the primary

force driving energy conservation, it can be

assumed that the reductions that have been

achieved to date are a result of implementing the

Table 36.—Funding Sources and Funding Uses of Cash Flow of Fifteen Largest Chemical Companies

1979 1980 1981

$ millions 0/0 of total $ millions 0/0 of total $ millions 0/0 of total

Sources of funds

Net income. . . . . . . . . . . . . . . . . . . . . $ 3,801 36.30/o $3,981 33.20/o $4,358 18.20/o

Depreciation and depletion . . . . . . . 3,602 34.4 3,818 31.8 4,267 17.9

Deferred taxes . . . . . . . . . . . . . . . . . . 427 4.1 679 5.7 1,012 4.2

Other internal sources . . . . . . . . . . . 1,093 10.5 815 6.8 1,833 7.7

Long-term debt . . . . . . . . . . . . . . . . . 1,210 11.6 2,079 17.3 7,493 31.4

Stock . . . . . . . . . . . . . . . . . . . . . . . . . . 322 3.1 630 5.2 4,931 20.6

Total. . . . . . . . . . . . . . . . . . . . . . . . . $10,454 100.0 ’%0 $12,002 100.00/0 $23,894 100.00/0

Allocation of funds

Dividends . . . . . . . . . . . . . . . . . . . . . . $ 1,474 14.1 % $ 1,603 13.4% $ 1,845 7.7%

Capital expenditures . . . . . . . . . . . . . 5,633 53.9 7,027 58.5 8,344 34.9

Additions to working capital . . . . . . 1,075 10.3 1,057 8.8 3,759 15.7

Reduction of long-term debt . . . . . . 1,042 10.0 1,119 9.3 1,493 6.3

Other applications. . . . . . . . . . . . . . . 1,230 11.7 1,196 10.0 8,453 35.4

Total. . . . . . . . . . . . . . . . . . . . . . . . . $10,454 100.0 ’%0 $12,002 100.0 ’%0 $23,894 100.00/0

SOURCE: Chemical arid Engineering News, June 14, 1982, p, 43.
Ch. 6—The Chemicals Industry ● 129

Table 37.—Types of Energy Efficiency-improving

Projects Undertaken by Chemical Manufacturing

Association Companies

New process units and technologies

ž 25 companies reported new energy efficiency-improving

projects, such as replacing infrared dryers with microwave

units; improving chlorine cell energy use; instalIing new,

low-density, polyethylene production facilities; and converting high-pressure methanol manufacturing facilities to

low-pressure facilities.

Improvements in existing processes

●

●

●

●

70 companies reported capital projects that replaced existing equipment or added process control to existing

equipment.

10 companies reported projects that changed materials

usage and thereby improved energy use.

75 companies reported changes in plant operations that

improved energy use.

30 companies reported projects that improved product

yield, thereby decreasing the amount of energy used per

unit of production.

Housekeeping and retrofit improvements

● 64 companies reported energy-efficiency i m prove merits

from improved maintenance.

. 59 companies improved their waste heat recovery.

• 70 companies invested in improvements i n power and

steam operations.

● 36 companies improved plant heating, ventilation, and air

conditioning.

• 38 companies reported improvements in energy recovered

from waste materials.

. 71 companies improved their process pipe insulation.

SOURCE “Energy Efficiency Improvement and Recovered Materials Utilization

Report, ” prepared for DOE by the Chemical Manufacturing Associa-.

tion, June 1, 1982

shorter payback, more apparent, and easier to

obtain energy conservation opportunities. The industry had to seek a new balance between factors of production, capital, labor, and energy.

Each future reduction in energy use will make the

next increment more difficult or expensive to obtain. Moreover, a certain minimum amount of energy must be used and cannot be reduced for a

given amount of industrywide output.

The major trends within the chemicals industry

appear to be as follows:

●

●

●

●

●

●

Continued improvement in equipment efficiency and operational management.

Improved methods of physical separation.

More capital-intensive energy conservation

and recovery projects.

More production integration (including cogeneration) to combine exothermic and endothermic reactions and utilize byproducts

and waste products efficiently.

More use of heavy gas oils and coal as feedstocks and synthesis gas in production of ammonia and methanol.

New processes driven primarily by feedstock

costs and availability.

OTA finds that there is still room for improved

energy housekeeping and improved process control in many plants. Du Pont, unusual among

chemical companies in that it does most of its

own plant design and engineering, set up a consulting service in 1973 to sell energy conservation engineering services to other firms in the industry. Its consultants claim to be able to reduce

the average client’s energy bill by 20 percent, 40

percent of which can typically be achieved without major capital investment.

Moreover, equipment suppliers are constantly introducing incremental improvements–e. g.,

in sensors and microprocessor controls and in

motor, pump, and turbine efficiencies. These

changes, together with efficiencies of larger scale,

would result in 10 to 20 percent better performance for most new plants in 1990 as compared

to 1980, even if plant layouts were unchanged.

IMPACTS OF POLICY OPTIONS ON THE CHEMICALS INDUSTRY

In order to analyze the impacts of legislative Information Agency (E IA) that indicated that disoptions on the chemicals industry, OTA first tillate fuel prices will remain relatively stable

made certain assumptions about economic through the 1980’s and then rise at a rate of 2

growth rates and energy price trends that might to 3 percent above inflation by 2000.

occur between now and 2000. The assumptions, In addition, OTA assumed that the following

presented in tables 2 and 3 of chapter 1, were five specific trends would occur in the chemicals

based on energy price projections of the Energy industry.
130 . Industrial Energy Use

—

●

●

●

●

●

Ethylene feedstocks will switch from gaseous

feeds (ethane and propane) to liquid feeds

(naphtha and gas oil).

More chlorine will be produced from the diaphragm cell and less from the mercury cell.

Ammonia and methanol production from

coal via synthesis gas will become more

prevalent, especially after 1990.

Acetylene production will move toward the

crude oil, submerged-flame process.

Less phosphoric acid will be produced in

electric arc furnaces.

While some of these trends were drawn purely on economic grounds, some are the result of

the increasingly cautious attitude toward the use

of limited feedstock resources by the industry.

For example, by moving toward liquid feeds, an

olefin plant will increase its feedstock flexibility

because liquid feedstocks require additional

vaporizing equipment, and this equipment can

be used for a variety of liquid feeds.

Investment Strategy

There is some concern that small chemical

firms will respond differently to policy options

than will large firms. As part of the OTA analysis,

case study visits were made to two small (gross

revenue less than $250 million per year) chemical

companies. OTA found no difference between

these firms and the larger ones in terms of their

energy conservation decision making.

Smaller chemical companies do tend, however,

to be motivated by a desire to produce products

that have a distinct market differentiation. Whereas large firms tend to rely on high volumes and

have relatively high break-even points, smaller

firms seek a temporary monopoly or advantageous competitive position in some special area.

For these smaller firms, it is more important to

spend money differentiating their products than

to minimize the cost of standard products.

Ultimately, smaller firms in the chemicals industry can be expected to respond rationally to

a Government policy. OTA analysis indicates that

a small firm will not take advantage of an initiative

simply because it is there, unless it contributes

toward the firm’s objectives and coincides with

its outlook for the economy.

In order to project the impacts of four legislative

options, OTA used three types of analytical information. First were the observations of case

study corporations and workshop participants.

Their experiences and perceptions are presented

in the opening paragraphs of the subsection dealing with each legislative option. Next, OTA considered a series of eight capital projects, along

with their predicted energy efficiency improvements and costs. These projects were used to illustrate the changes in internal rate of return (l RR)

percentages as each legislative option was applied

to the series. Some of these projects were generic

to all manufacturing establishments, such as replacement of older electric motors with more efficient ones or installation of process control computer facilities. Other projects were specific to the

chemicals industry, for example, installation of

a heat exchanger in an ammonium nitrate production plant. Table 38 presents brief descriptions

of these eight projects along with a summary of

the economic and energy assumptions used to

calculate individual IRR percentages. Third, OTA

used the Industrial Sector Technology Use Model

(ISTUM). The analysis begins with the reference

case.

The Reference Case

The reference case is based on the economic

and legislative environment that exists for industry

today and was presented previously in chapter

3. Given the chemical industry reference case,

OTA assessment indicates that there will be little change in capital investment trends from that

which has been observed in the past 5 years. Recent declines in energy prices may delay projects

designed to facilitate fuel switching, especially

those switching from distillate fuels to coal.

Switching from natural gas energy sources will

in all likelihood continue. It seems clear that improvements in energy efficiency will be dictated

more at the direction of the economic business

cycle, and by perception of opportunity of risk,

than by policy.

The reference case incorporates the 1981 Economic Recovery Tax Act, with its special provisions for accelerated depreciation and safe harbor leasing.
Ch. 6—The Chemicals Industry ● 131

Table 38.—Chemical Industry Projects To Be

Analyzed for Internal Rate of Return (lRR) Values

1. Inventory control —A computerized system can keep track

of product item availability, location, age, and the like. In

addition, these systems can be used to forecast product

demand on a seasonal basis. The overall effect is to lower

inventory yet maintain the ability to ship products to

customers with little or no delay. In typical installations,

working capital costs are dramatically reduced.

Project life—5 years.

Capital and installation costs—$560,000.

Energy savings —O directly, but working capital could be

reduced by $1.2 million.

2. Electric motors. -The chemical industry uses electrical

motors for everything from vapor recompression to mixing, pumping, and extruding. In this analysis, OTA has

assumed that five aging electric motors will be replaced

with newer, high-efficiency ones.

Project life—10 years.

Capital and installation costs–$35,000.

Energy savings–$16,000 per year at 4¢/kWh.

3. Ammonia nitrate fertilizer plant cogeneration project.—

Installation of a turbogenerator unit to recover electrical

power from a steam production facility. Superheated steam

is produced at 600 psi and then passed through a mechanical turbine to generate electricity. The turbine exhaust,

which is 175 psi steam, is then used for normal plant

product ion.

Project life—10 years.

Capital and installation costs–$231 ,000.

Energy savings—$72,300 per year.

4. Computerized process control—The most common retrofit

purchases being made for industrial systems are measuring gauges, controlling activators, and computer processors. The main accomplishment of such a process control system is to enhance the throughput and quality of a

chemical production plant with only materials and small

energy inputs.

Project life—7 years.

Capital and installation costs—$500,000.

Energy savings—$150,000 per year.

5. Heat exchanger in nitric acid plant. -Equipment installed

to heat incoming plant gas streams with the exhaust gas

from a 175 psi steam line.

Project life—10 years.

Capital and installation costs–$155,000.

Energy savings—$41,200 per year.

6. Counterflow heat exchanger.—A counterflow heat exchanger preheats air entering a kiln with the exhaust stack

gases from the same kiln.

Project life—10 years.

Capital and installation costs—$200,000.

Energy savings—$53,000 per year.

7. Waste heat boiler.-lnstallation of a heat exchanger and

waste heat boiler in an ammonia plant.

Project life—10 years.

Capital and installation costs–$1,425,000.

Energy savings—$351 ,000 per year.

8. Ammonia plant cogeneratlon project-installation of a turbogenerator unit to recover electrical power from a high-

-pressure, natural gas stream just before it enters the

reformer burner.

Project life—10 years.

Capital and installation costs–$816,000.

Energy savings—$193,000 per year.

SOURCE: Office of Technology Assessment.

The gross output of the chemicals industry is

anticipated to grow at a rate of approximately 4

percent per year between now and 2000. Consider data presented in table 39. Between 1969

and 1979, the industry grew at an annual rate of

5.8 percent. That growth rate will probably decline slightly as energy prices increase over the

next 20 years. Under the energy price scenario

of the reference case, OTA analysis projects, the

fuel to be consumed and the energy service to

be provided between now and 2000* (see tables

40 and 41).

Tables 42 and 43 show that process heat, which

should decrease from 526 trillion to 379 trillion

Btu, will shift from the proportions of 76 percent

natural gas, 13 percent oil, and 11 percent electricity to those of 70 percent natural gas, 14 percent oil, and 15 percent electricity. In steam and

power generation, natural gas will decrease from

70 percent of the 2,456 trillion Btu to 34 percent

of the 3,180 trillion Btu predicted to be used in

2000.

Figure 31 shows that the energy intensity of the

average product in the chemicals industry is projected to fall from its present value of 17.6 thousand Btu per pound of product to approximately 15 thousand Btu per pound by the end of the

century. Figure 32 shows that fuel use is projected

to grow only slightly from its present level of 6.8

Quads to just over 8 Quads by 2000, assuming

the energy price and product growth rates built

into the initial parameters of OTA’s modeling

efforts.

Projected Effects of Policy Options

The following sections describe the projected

effects of the four policy options i n comparison

to changes in the chemicals industry energy use

and product energy intensity in the reference

case. Figure 32 presents a graphical overview of

the impact of these policies.

Option 1: Removal of Accelerated

Depreciation

Removal of accelerated depreciation is projected to have little impact on energy use in the

“It should be noted, once again, that energy demand projections

are predicated on a set of exogenously determined energy prices

and a fixed product output.
132 . Industrial Energy Use

Table 39.–Historical and Assumed Growth Rates in SIC 28

1969-80 1980-85 1985-90 1990-2000

All manufacturing FRBa growth rate . . . . . . . . . . 3.250/o 3.9 ”/0 4.3 ”/0 3.7 ”/0

Chemical industry FRBa growth rate . . . . . . . . . . 3.9 ”/0 5.0 ”/0 5.00/0 4.60/o

Fuel price, gas ($/MMBtu) . . . . . . . . . . . . . . . . . . . – 5.0 6.3 9.0

Fuel price, residuum ($/MMBtu) . . . . . . . . . . . . . . – 5.0 6.2 9.0

Fuel price, coal ($/MMBtu) . . . . . . . . . . . . . . . . . . . – 2.2 2.3 2.4

Fuel price, electricity ($/MMBtu) . . . . . . . . . . . . . . – 13.8 13.7 13.8

a

Federal Reserve Board.

SOURCE: Office of Technology Assessment

Table 40.-Reference Case Energy Use Projection, by Fuel: 1980-2000

(In million Btu)

Gas oil Coal Purchased

Year Fuel Feedstock Fuel Feedstock Fuel electricity Total energy

1980 . ......2,114 388 377 1,711 287 537 5,41 4

1985 . ......2,085 371 369 2,002 462 558 5,847

1,794 333 439 2,431 829 613 6,439

1,201 246 518 3,268 1,636 702 7,571

aAt 3,412 Btu/kWh.

SOURCE: Office of Technology Assessment.

Table 41.–Reference Case Energy Use Projection, by End Use: 1985-2000

(In million Btu)

Machine

Year Process heat Steam and power drive Electrolysis Feedstocks Total

1985 . . . . 526 2,456 585 177 2,163 5,847

1990 ., . . 515 2,640 644 129 2,511 6,439

2000 . . . . 379 3,180 681 151 3,180 7,571

SOURCE: Office of Technology Assessment.

Table 42.—Reference Case Energy Use Projection,

by Process Heat Fuel: 1985=2000 (In percent)

Year Total Gas Oil Coal Electricity Other a

1985 . . . . . . . 100 76 13 — 11 11

1990 . . . . . . . 100 79 10 1 10 —

2000 . . . . . . . 100 70 14 1 15 —

aChemical byproducts and waste products used as fuels.

SOURCE: Off Ice of Technology Assessment.

Table 43.—Reference Case Energy Use Projection,

Steam and Power Fuel: 1985=2000 (in percent)

Year Gas Oil Coal Other a

1985 . . . . . . . . . . . . . . . . . . . . . . . . . 70 8 18 4

1990 . . . . . . . . . . . . . . . . . . . . . . . . . 56 11 30 3

2000 . . . . . . . . . . . . . . . . . . . . . . . . . 34 14 50 2

aChemical byproducts and waste products used as fuels.

SOURCE: Office of Technology Assessment.

Figure 31 .—Chemicals Industry Energy Intensity

Projection, 1970-2000

1970 1975 1980 1985 1990 1995 2000

Year

SOURCE: Off Ice of Technology Assessment
Ch. 6–The Chemicals Industry ● 1 3 3

12

10

8

6

4

2

0

Figure 32.–Chemical Industry Projections of Fuel Use and

Energy Savings by Policy Options, 1990 and 2000

Fuel Use Projections

Natural

gas

Oil Coal Purchased

electricity

1990 2000

Ref No EITC Btu Cap Ref No EITC Btu Cap

case ACRS tax avail case ACRS tax avail

Fuel Savings Projections

1.0 

0.9 —

0.8 -

0.7 “

0.6 -

0.5 “

0.4 -

0.3 -

0.2

0.1

0.0 —

Recovered Cogenerated

energy energy

1990 2000

-

Ref No EITC Btu Cap Ref No EITC Btu Cap

case ACRS tax avail case ACRS tax avaiI

SOURCE: Office of Technology Assessment

99-109 0 - 83 - 10
734 ● Industrial Energy Use

chemicals industry, since the accelerated cost

recovery system (ACRS) effects are so dependent

on the generaI investment climate. OTA analysis

indicates that the energy intensity decline with

ACRS removal is coincident with the reference

case energy intensity projection over the next 17

years. In addition, the fuel use projections are virtually identical for both the reference case and

the removal of accelerated depreciation, as

shown in figure 32.

Table 44 presents the IRR calculations of the

eight chemical projects under both old depreciation and accelerated depreciation schedules. As

shown, there is essentially no change between

the two columns of calculations, nor is there any

change in the relative rankings of each of the projects. In sum, energy use, compared to the reference case, is unaffected by removal of the ACRS

depreciation schedule.

Option 2: Targeted Energy Investment

Tax Credits

Targeted energy investment tax credits (EITCS)

of the magnitude discussed in this report will likely have little effect on energy efficiency in the

chemicals industry between now and 2000. Such

incentives are perceived as having three functions. First, they are useful for increasing the IRR,

thereby presumably elevating the desirability of

a project that would not have met the hurdlerate cut-off for consideration as par-t of a corporation’s capital plan. OTA calculations show that

a 10-percent EITC would change the IRR by 3 to

6 percentage points, depending on the length of

a project’s lifetime. This change is not large

enough to influence significantly the decision to

implement a capital project. OTA was unable to

find evidence of a chemicals project that was influenced by a 10-percent EITC.

Second, targeted tax credits increase general

cash flow in an energy-intensive company. Logic

would dictate that if an organization were to invest 25 percent of its funds in energy efficiencyimproving capital stock, to the degree that more

money is generated for investment through such

a credit, 25 percent of that additional money

would go to energy efficiency-improving equipment. At best, however, this is speculative. The

case study firms and workshop panelists state that

some energy would be saved with increased cash

flow, but the amount saved is unquantifiable and

very company-specific.

The third reason for justifying tax credits is to

raise the awareness of corporate management

that saving energy is important, not only for profitability, but also for the national interest. Although the effect of this rationale is unquantifiable, workshop panelists say it could be an important motivating influence to some organizations.

OTA analysis projects that a 10-percent EITC

would produce no change in chemicals industry

energy intensity from that projected in the reference case. Figure 32 shows that the fuel use

patterns would be unchanged as well,

To illustrate the effect of a 10-percent EITC on

the IRR, the eight chemical industry projects

Table 44.—Effects of Policy Options on IRR Values of Chemical Industry Projects

Policy option $1/MMBtu

tax on natural gas and

Project Reference case ACRS removed 10-percent EITC petroleum products

1, Inventory control . . . . . . . . . . . . . . . . . . . . . . 87 87 87 87 (No fuel)

2. Electric motors . . . . . . . . . . . . . . . . . . . . . . . 43 43 48 51 (Electric)

3. Fertilizer plant cogeneration project . . . . . 18 18 20 18 (Coal)

4. Computer process control . . . . . . . . . . . . . . 16 16 22 19 (Oil)

5. Nitric acid plant heat exchanger . . . . . . . . 15 15 18 21 (N. Gas)

6. Counterflow heat exchanger . . . . . . . . . . . . 15 15 18 19 (Oil)

7. Waste heat boiler . . . . . . . . . . . . . . . . . . . . . 11 11 14 16 (N. Gas)

8. Ammonia plant cogeneration project. . . . . 11 11 15 17 (Gas)

SOURCE: Office of Technology Assessment.
Ch. 6—The Chemicals Industry • 735

previously described were analyzed with and

without the tax credit. In table 44, the IRR for

each project is presented. As shown, only two

projects–projects 4 and 8–changed their relative

rankings. However, such changes are unlikely to

cause projects 4 and 8 to be undertaken at the

expense of projects 3 and 7. There might be other

factors which the investment tax credit might supplement or bolster to cause the project to be undertaken, but the tax credit alone would not be

so motivating.

Option 3: Tax on Premium Fuels

OTA’s assessment of the impact of a fuel tax

of $1 -per-million-Btu fuel tax on natural gas and

distillate fuels is that it would have a positive effect on improving energy efficiency but could

have an overall negative effect on the U.S. chemicals industry with respect to foreign competition.

OTA’s ISTUM analysis projects a premium fuels

tax to have little effect on energy use in the

chemicals sector. The energy intensity of chemicals industry products is projected to be within

a percentage point of being identical to that of

the reference case. However, as shown in figure

32, fuel use patterns are projected to shift slightly. A premium fuels tax would cause natural gas

consumption to fall by approximately 10 percent,

while coal would increase by a similar amount.

[t is also noteworthy that a premium fuels tax

would decrease cogeneration of electricity, since

the most reliable and efficient fuel in cogeneration units is natural gas. OTA projects that cogeneration could fall by 25 percent under the premium fuels tax scenario.

If a premium fuels tax were to be levied, multinational chemical companies would probably

build production facilities outside U.S. boundaries in order to take advantage of lower energy

prices. The products would then be imported to

the United States or shipped to other countries.

In either case, this would adversely affect U.S.

balance of payments, since chemical trade generated an $11 billion positive flow in 1981.

The fuels tax would also change the IRR percentages, as indicated in table 44. The effect of

the fuel tax on the eight sample projects would

be more pronounced than in the case of the EITC.

The gain in the IRR was almost 6 percentage

points for project S, the nitric acid plant heat exchanger, for example. The overall effect on most

of the projects was to increase the IRR overall by

4 to 6 points.

Option 4: Low Cost of Capital

At present, the availability of capital is not a

major constraint in the chemicals industry. The

chemicals industry has been profitable over the

last 10 years, especially compared to the steel industry. High interest rates have not hurt chemical

firms directly, although they have indirectly decreased the demand for chemical products in the

housing and auto industry. Moreover, chemical

companies have been able to borrow funds

where needed, Although making funds available

for general investment at lower interest rates does

have an impact on the IRR, the energy, employment, and capital investment consequences are,

at best, difficult to estimate.

Energy intensity is projected to fall in approximately the same fashion with the capital availability option as in the reference case, although

the projected level is slightly higher than with the

reference case. Figure 32 shows that with less expensive capital, chemicals industry firms would

install more cogeneration capacity, and thereby

decrease purchased electricity demand while increasing natural gas use. In a sense, this increase

is an energy accounting artifact. Fuel use is being switched from public utilities to the industrial

sector. As with all cogeneration, the effect on the

energy economy is to make the United States

more energy efficient with cogeneration, even

though it looks less efficient for the chemicals

industry.

In order to illustrate the effect of lower interest

rates on IRR, OTA first assumed that the chemicals industry projects would be funded by debt

financing. In the analysis, shown in table 45,

those projects that were good investments at the

outset continued to be good investments with the

change in interest rates. While the IRR values

changed slightly, none surpassed the others with

a low cost of capital option.
136 ● Industrial Energy Use

Table 45.—Effect of Lower Interest Rates on IRR Values of

Chemical Industry Projectsa

Reference case IRR IRR with policy options:

Project with 16°/0 interest rate interest rate of 8°/0

1. Inventory control . . . . . . . . . . . . . . . . . . . . 385 370

2. Electric motors . . . . . . . . . . . . . . . . . . . . . 93 97

3. Computer process control . . . . . . . . . . . . 3 6 44

4. Nitric acid plant heat exchanger . . . . . . 35 39

5. Counterflow heat exchanger . . . . . . . . . . 33 38

6. Ammonia plant cogeneration

project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 31

7. Fertilizer plant cogeneration project . . . 26 28

8. Waste heat boiler . . . . . . . . . . . . . . . . . . . 24 27

aAll projectts are assumed to be two-thirds debt financed and one-third equity financed,

SOURCE: Office of Technology Assessment.
The

/

-4

I

Chapter 7

Steel Industry

.“

.vr#

Photo credit American Iron and Steel Institute
I
Chapter 7

The Steel Industry

INDUSTRY OVERVIEW

Steel is made from iron ore, iron scrap, coal

(converted to coke), and limestone. it is one of

the largest and most versatile bulk commodities

in commercial use, having many structural applications and competing successfully with other

structural materials, such as aluminum, plastics,

and wood, for a variety of markets. International

competition within the steel industry has reduced

U.S. production and is forcing major modernizing investments, despite dim future prospects and

relatively limited investment capital. Among other

efficiency gains, these investments are dramatically reducing the energy input per ton of steel. *

Historically, steel production has followed the

business cycle because a large share of steel is

used for highly cyclical construction and consumer durables.1 After hitting a peak of over 100

million tons of steel shipped in 1979, the industry

has been especially hard pressed because the Nation has experienced its worst recession since

the 1930’s and because import competition has

steadily intensified.2 In 1981, the domestic steel

industry shipped 87 million tons of product (up

4 million tons from 1980) and on the average

about 79 percent of raw steel making capacity was

in operation. In 1982 shipments plummeted to

just under 60 million tons and less than 50 percent of capacity was utilized.3

Industry Structure

The domestic steel industry, classified as SIC

3312 includes blast furnace-based integrated

steelmaker, nonintegrated minim ills, and independent producers of wire, bars, and pipe who

● For more information, see table 53 and fig. 37.

I Technology and Steel Industry Competitiveness, ch. 5 (Washington, D. C.: U.S. Congress, Office of Technology Assessment, OIAM-122 June 1980)

IRobert W. Crandall, The U.S. Steel Industry in Recurrent Crisis:

Policy Options in a Competitive World (Washington, D. C.: The

Brookings Institution, 1981); and American Iron and Steel Institute,

Steel at the Crossroads: The American Steel Industry in the 1980s,

ch. 2, 1980.

‘American Iron and Steel Institute, Annual StatMlca/ Report for

1981 (May 1982) and 1982 (unpublished).

purchase and process semifinished steel (see table

46). In 1977, 396 companies operated 504 plants

and employed 442,000 people. The 91 million

tons of steel they shipped had a value of $36.2

billion and represented about 1.9 percent of the

U.S. gross national product (GNP).4 Of these

companies, the top 16 companies accounted for

approximately 83 percent of blast furnace and

steel mill product shipments (see table 47).

Steel producers can be classified as either integrated or nonintegrated. Nonintegrated mills

are further divided into minimills and specialty

4

Ibid., and U.S. Department of Commerce, B urea u of the Census, Statistical Abstract of the United States, 1980, pp. 437, 444.

Table 46.—Definition of SIC 33—The Primary

Metals Industry

This major group includes establishments engaged in the

smelting and refining of ferrous and nonferrous metals from

ore, pig, or scrap; in the rolling, drawing, and alloying of ferrous and nonferrous metals; in the manufacture of castings

and other basic products of ferrous and nonferrous metals;

and in the manufacture of nails, spikes, and insulated wire

and cable. This major group also includes the production of

coke. Establishments primarily engaged in manufacturing

metal forgings or stampings are classified in Group 346.

The major 3-digit industries are:

SlC Title

331 . . . .

332. . . .

333. . . .

334. . . .

335. . . .

336. . . .

339. . . .

Blast furnaces, steel works, and rolling and

finishing mills

Iron and steel foundries

Primary smelting and refining of

nonferrous metals

Secondary smelting and refining of

nonferrous metals

Rolling, drawing, and extruding of

nonferrous metals

Nonferrous foundries (castings)

Miscellaneous primary metal products

Within SIC 331, 4-digit industries include:

SIC Title

3312 . . . Blast furnaces (including coke ovens), steel

works, and rolling mills

3313 . . . Electrometallurgical products

3315 . . . Steel wire drawing and steel nails and spikes

3316 . . . Cold rolled steel sheets, strips, and bars

3317 . . . Steel pipe and tubes

SOURCE: Office of Management and Budget, Standard Industrial Classificafion

Manual. 1972

139
140 ● Industrial Energy Use

Table 47.—Steel Shipments by Major

U.S. Companies, 1976

Steel shipments

Thousands of Percent of

net tons total

United States Steel Corp. . . . . . . . . . . . 19,486 21.8

Bethlehem Steel Corp. . . . . . . . . . . . . . . 12,600 14.3

National Steel Corp. . . . . . . . . . . . . . . . . 7,644 8.8

Republic Steel Corp. . . . . . . . . . . . . . . . 6,535 7.3

Inland Steel Co.. . . . . . . . . . . . . . . . . . . . 5,600 6.3

Armco Steel Corp. . . . . . . . . . . . . . . . . . 5,082 5.7

Jones & Laughlin Steel Corp. . . . . . . . . 5,097 5.7

Lykes-Youngstown Corp. . . . . . . . . . . . . 3,388 3.8

Wheeling-Pittsburgh Steel Corp. . . . . . 2,816 3.1

Kaiser Steel Corp.. . . . . . . . . . . . . . . . . . 1,616 1.8

McLouth Steel Corp. . . . . . . . . . . . . . . . 1,639 1.8

CF&l Steel Corp. . . . . . . . . . . . . . . . . . . . 1,101 1.2

Interlake, Inc. . . . . . . . . . . . . . . . . . . . . . . 797 0.9

Northwestern Steel & Wire Co. . . . . . . 839 0.9

Cyclops Corp. . . . . . . . . . . . . . . . . . . . . . 849 0.9

Allegheny -Ludlum Industries, Inc. . . . . 383 0.4

Major company total . . . . . . . . . . . . . 75,872 84.7

Industry total . . . . . . . . . . . . . . . . . . 89,450 100.0

SOURCE: “1976 Steel Industry Financial Anal@ s,” Iron Age, Apr. 25, 1977.

steel companies (see table 48). In integrated

plants, the primary source of iron is iron ore in

the form of lump ore, sinter, or pellets. Iron ore

is converted into steel through a series of processing steps, including production of coke, pig

iron, raw steel, and steel products. Minimills are

generally much smaller, have more limited product lines, and one less stage of production since

the process begins with steel scrap or directly reduced iron, feedstocks that do not require gross

refining in a blast furnace (see table 48). Specialty companies are also smaller, but have a much

larger number of specialized products than do

minim ills. Both smaller operations rely primarily

on the electric arc furnace to make molten metal,

but the specialty producer tends toward higher

grade ferrous scrap and refined alloy metals in

order to make high performance goods.

The annual production capacities of steel plants

operated by the three major sectors of the steel

industry are shown in table 48. With respect to

the scale of production in U.S. plants, 46 of the

50 plants with raw steel productive capacity

above 1 million tons per year in 1978 were

owned by the 17 integrated companies. In contrast, all but one of the 54 plants operated by 43

scrap-based companies had annual production

capacities below 1 million tons. All but nine of

the scrap-based plants had less than half of that

Table 48.–Capacities of Steel Plants in the United States, 1978

Number of plants operated by the —

43

17 33 scrap/DRl a

Total number

Size-range raw steel integrated speciality companies of plants

capacity, tonnes/yr companies companies (minimills) in size range

7,256,000-8,162,999. . . . . . . . . . . 2 0 0 2

6,349,000-7,255,999. . . . . . . . . . . 1 0 0 1

5,442,000-6,348,999. . . . . . . . . . . 1 0 0 1

4,535,000-5,441,999. . . . . . . . . . . 3 0 0 3

3,628,000-4,534,999. . . . . . . . . . . 4 0 0 4

2,721,000-3,627,999. . . . . . . . . . . 9 0 0 9

1,814,000-2,720,999. . . . . . . . . . . 11 0 1 12

907,000-1 ,813,999 . . . . . . . . . . . 15 3 0 18

816,300- 906,999 . . . . . . . . . . . 1 0 0 1

725,600- 816,299 . . . . . . . . . . . 0 1 2

634,900- 725,599 . . . . . . . . . . . 0 0 1 1

544,200- 634,899 . . . . . . . . . . . 1 3 3 7

453,500- 544,199 . . . . . . . . . . . 1 1 3 5

362,800- 453,499 . . . . . . . . . . . 1 1 4 6

272,100- 362,799 . . . . . . . . . . . 2 1 5 8

181,400- 272,099 . . . . . . . . . . . 2 2 14 18

144,190- 181,399 . . . . . . . . . . . 1 2 6 9

126,980- 144,189 . . . . . . . . . . . 0 2 4 6

90,700- 126,979 . . . . . . . . . . . 0 10 9 19

68,025- 90,699 . . . . . . . . . . . 0 3 2 5

45,350- 68,024 . . . . . . . . . . . 2 10 9 21

22,675- 45,349 . . . . . . . . . . . 0 5 0 5

0- 22,674 . . . . . . . . . . . 0 3 0

aDRl = directly reduced iron (see p. 153).

SOURCE: American Iron and Steel Institute.
Ch. 7—The Steel Industry • 141

productive capacity because, in general, profit

rates were greater for small plants that bought

scrap and sold products within a single region.

The centers of integrated steel production continue to be in the traditional industrial areas of

the North Central and Eastern States (see table

49). The smaller, scrap-based companies tend to

be distributed more uniformly among general

population and manufacturing centers.

The major forms of steel are sheet and strip,

structural and plate, bars, pipes and tubes, wire

and wire products, and tin mill products. Major

markets for steel include the automotive, construction, machinery and equipment, containers

and packaging, and oil and gas industries and

steel service centers. In 1980, the distribution of

steel products by grades was 84.7 percent carbon steel, 13.8 percent alloy steel, and 1.5 percent stainless steel. A projection of steel product

mix is shown in table 50.

Economics of Steel Production

Profitability

In recent years, the slowing demand for U.S.

steel has resulted in low or negative profits for

many U.S. steel producers. Capital-intensive industries like steel are the most severely penalized

by accelerating inflation and highly cyclical economic conditions. From 1967 to 1980, steel mill

Table 49.—Raw Steel Production by State, 1980

States Thousands of tons

Pennsylvania . . . , . . . . . . . . . . . . . . . . . . . . . . . . .

Indiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Ohio. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Minnesota, Missouri, Oklahoma, Texas,

Nebraska, and lowa. . . . . . . . . . . . . . . . . . . . . . .

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Virginia, West Virginia, Georgia, Florida, North

Carolina, South Carolina, and Louisiana . . . . .

Rhode Island, Connecticut, New Jersey,

Delaware, and Maryland . . . . . . . . . . . . . . . . . . .

Arizona, Colorado, Utah, Washington, Oregon

and Hawaii . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Alabama, Tennessee, Mississippi, and

Arkansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

New York . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Kentucky. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

23,517

19,820

16,100

8,961

8,642

7,877

6,066

5,161

4,795

3,452

2,675

2,628

2,141

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111,835

Table 50.—Projection of Product Mix in U.S.

Steel Production, 1976-2000

Distribution in percent

Product 197 6

a 1980 1985 1990

Structural . . . . . . . . . . . . . . . . . . . 10 12 12 12

Plate . . . . . . . . . . . . . . . . . . . . . . . 9 10 10 10

Rails . . . . . . . . . . . . . . . . . . . . . . . 2 2 2 2

Hot-rolled bars . . . . . . . . . . . . . . 9 7 7 7

Other bars ... , . . . . . . . . . . . . . . 7 9 9 9

Pipes and tubes . . . . . . . . . . . . . 9 11 13 15

Wire . . . . . . . . . . . . . . . . . . . . . . . 3 3 2 2

Tin mill products . . . . . . . . . . . . 7 7 6 6

Hot-rolled sheet and strip. . . . . 17 15 15 14

Cold-rolled sheet and strip . . . . 20 17 16 15

Galvanized sheet . . . . . . . . . . . . 7 8 8 8

aAverage of 1975.77 used to eliminate fluctuations.

SOURCE: American Iron and Steel Institute and the Office of Technology

Assessment,

product prices rose 22.6 percent faster than consumer prices, while the average real rate of return

after inflation in the steel industry, which remained around 10 to 11 percent throughout the

early 1950’s, declined steadily after 1955 and fell

to below zero in the mid-l970’s. Moreover, profitability in steel production was not uniform. The

average rate of return on investment for major

integrated steel companies was 1.4 percent in

1977 and 6.2 percent in 1978. Nonintegrated

steel companies had an average rate of return on

investment of 6.2 percent in 1977 and 12.3 percent in 1978. Alloy and specialty steel companies

had average rates of return on investment of 9.1

percent in 1977 and 11.1 percent in 1978.5

After-tax profits as a percentage of stockholder

equity in the steel industry were below that for

all manufacturing (often by a substantial margin)

in every year since 1957, except during the severe

recession of 1974. In fact, for most of the 1970’s

the after-tax rate of return on stockholder equity

in the steel industry was below the prime lending

rate (quite the reverse of the 1950’s and 1960’s).6

Capital Investment

High inflation and high interest rates during the

1970’s contributed to: 1) slowing the overall investment in the steel industry, 2) reducing the

ability of the industry to borrow funds to make

5 Technology and Steel Industry Competitiveness, ch, 4, op. cit.,

pp. 119-124.

SOURCE: American Iron and Steel Institute, 61&j.
142 • Industrial Energy Use

long-term investments at a time when firms were

becoming more dependent on external financing of investments (because of low profit levels),

3) discouraging long-term investment (because

of increased uncertainty about economic conditions), and 4) decreasing growth prospects for the

U.S. steel industry. *

As shown in figure 33, steel industry capital investment increased substantially between 1972

and 1975; the level more than doubled even if

the figures are discounted for inflation. However,

after 1975, there has been a significant decline

in investment in terms of both current and constant 1972 dollars. This decline shows no sign of

reversing itself.

One consequence of declining profitability of

steel production in the United States during the

1970’s was the shift from internal to external

*Steel production in the United States is on a long-term downward

trend as measured by the ratio of steel produced to GNP. OTA analysis indicates that the most optimistic forecast for steel through the

1990’s would have production well within current production

capacity.

financing of capital investment. While capital expenditures in the steel industry increased from

an average value of $1.46 billion for the 1970-73

period to $2.79 billion for the 1975-78 period,

capital expenditures as a percentage of net internally generated funds increased from an average value of 78.2 percent for the 1970-74 period

to 142.1 percent for the 1975-78 period. In addition, there was a perceptible increase in the

debt-equity ratio, from 39.7 percent in 1971 to

49 percent in 1980.7

As in other industries, accelerating inflation and

economic instability encouraged a slow drift away

from long-term financing to short-term financing

of investments as interest rates increased and real

rates of return diminished, and away from less

liquid long-term asset holdings to more liquid,

short-term asset holdings. That kind of shift

toward the short end on both the asset and liability side—although rational, given general economic conditions—reflected the decreasing abili7

Technology and Steel Industry Competitiveness, op. cit.

Figure 33.–U.S. Capital investment in Steel industry, 1971=82

1971 72 73 74 75 76 77 78 79 80 81 8 2

a

Year

aEstimated.

SOURCE: Office of Technology Assessment.
Ch. 7—The Steel Industry ● 143

ty of the steel industry to finance the kind of longterm, fixed capital investments necessary for preserving or enhancing the competitive position of

U.S. steel producers in the domestic and foreign

markets.

Furthermore, despite the availability of accelerated depreciation throughout the period

1954-79, inflation increased sufficiently to erode

the capital purchasing power of depreciation allowances. Between 1954 and 1961, the purchasing power of depreciation allowances declined

a modest 4.3 percent relative to the construction

price index, and 2.8 percent relative to the GNP

deflator. As inflation accelerated during the

1962-74 period, the capital purchasing power of

recovered depreciation allowances declined 35.1

percent relative to the construction price index,

and 15.2 percent relative to the GNP deflator.

Without analyzing specific expenditures it is impossible to determine to what extent capital investments for pollution control improved yields

and lowered material or energy costs. Obviously, such gains would have diminished the net cost

of pollution control investments. Nonetheless,

these investments did place an additional strain

on the steel industry’s ability to invest in productive capacity and technological improvements.

pollution control expenditures increased from

$448.4 million for the period 1951-65 ($29.9 million per year), to $572.8 million for the period

1966-70 ($1 14.56 million per year), to $1,229.9

million for the period 1971-75 ($246 million per

year), to $2,643.3 million for the period 1976-80

($528.7 million per year).8

Finally, to gain a broader economic perspective, it is appropriate to compare U.S. steel investment figures with those of the energy industries. U.S. petroleum and gas companies invested

about $76 billion in 1980.9 The highest projected

capital investment requirement for maintaining

the U.S. steel industry in a competitive position

during the 1980’s is $7 billion per year.10

8American Iron and Steel Institute, Annual Statistical Report for

1980, 1981, p. 10.

9

0il and Gas Journal, ‘‘Spending Plans by U.S. Firms 9.5% Less

Than Outlay in 1982,” Feb. 28, 1983, p. 40.

10American Iron and Steel Institute, Steel at the Cross Roads: The

American Steel Industry in the 1980s, chs. Ill and Vll, 1980.

Employment

In 1976, Pennsylvania, Ohio, Indiana, Illinois,

and Michigan accounted for 72.4 percent of raw

steel production out of a total of 128 million net

tons. By 1980, they accounted for only 68.2 percent of raw steel production out of a total national

production of 111.8 million net tons.11 The decline in the share of these five States in total raw

steel production corresponds to their disproportionate share of the decline in total employment

in the steel industry—from 674,872 in 1974 to

568,958 in 1980 (or 15.7 percent). The visible

consequences of decreased steel production and

employment, when concentrated in specific comm unities, are more difficuIt to dismiss as market

adjustment processes.

Employment trends cannot be understood

without some reference to employment costs.

During the period 1971-80, in which U.S. employment in steel production declined substantially, total employment costs per hour rose from

$6.261 per hour to $18.451 per hour (about 13

percent per year). 12 As a benchmark, the rate of

inflation in the consumer price index during the

1970’s was approximately 8 percent per year. In

short, employee compensation in the steel industry increased at a rate about 50 percent greater

than the annual rate of inflation. The Council on

Wage and Price Stability report in 1977 indicated

that during the period 1952-77, total hourly costs

increased 450 percent for steel production, compared to an increase of 297 percent for all manufacturing workers. 13

Production Costs

The costs of producing plain carbon steel products vary markedly between companies and

plants, depending strongly on the product mix

and particular requirements and costs of raw

materials and energy. Furthermore, the costs are

substantially higher for the integrated steel companies than for scrap-based mini mill companies. *

11 American Iron and Steel institute, Annual Statistical Report for

1980, p. 57.

121 bid., p. 21.

13 Council on Wage and Price StabiIity, Report to the President

on Prices and Costs in the U.S. Steel Industry, 1977.

*Many financial experts have predicted that the scrap-based companies will account for 25 percent of domestic steel production

by 1990. There is no technical barrier to such growth. Growth in

excess of this rate will depend on the ability of the scrap-based companies to develop competitive quality in other product lines.
144 • Industrial Energy Use

The following figures are broad average estimates of production costs for plain carbon steel

products in integrated and scrap-based companies:

Costs per ton of shipments

Categories Integrated Scrap based

Raw materials. . . . . . . . $105.00 $100.00

Energy and fuels . . . . . 125.00 75.00

Labor . . . . . . . . . . . . . . 175.00 100.00

Total . . . . . . . . . . . . . $405.00 $275.00

At market prices of $410 to $500 per ton, only

$5 to $95 per ton remain for capital costs in the

integrated sector. *

Product Demand

One deterrent to capital investment in the steel

industry during the late 1970’s and early 1980’s

was the slackening of product demand, particularly in the construction and automobile industries. The downturn in steel shipments to the construction and auto industries between 1973 and

1980 accounted for nearly 60 percent of the 27.6-

million-ton decline in U.S. steel shipments. To

the extent that depressed conditions in both these

sectors are likely to persist throughout the early

1980’s, the short-term prospects for growth in

U.S. steel production are likely to remain modest

at best. On the other hand, it should be noted

that between 1973 and 1980, steel shipments to

the oil and gas industry increased 57.7 percent,

from 3.4 million torts in 1973 to 5.4 million tons

in 1980 .

1 4

The downturn in steel demand decreased capacity utilization rates. while utilization rates are

always subject to measurement errors, the cycle

in raw steel production capacity utilization rose

from 80.9 percent in 1976 to 87.8 percent i n

1979, and declined to 72.8 percent in 1980 and

to 50 percent for the first 9 months of 1982, as

estimated by the American Iron and Steel Institute (AISI). AISI estimates that the current combined capacity utilization rate of the East Euro-

*These estimates do not apply to periods of abnormally low demand such as the industry experienced during the second quarter

of 1982. During these times, cost per ton can be much higher since

large fixed costs must be spread over fewer units of product.

14 American Iron and Steel Institute, Annual Statistical Report for

1980, pp. 30-33,

pean countries, Japan, and the United States has

been below 60 percent for much longer. With

projected rapid expansion of steel capacity in the

developing countries to more than 100 million

tons in 1985, the continued pressure on the East

European, Japanese, and U.S. steel mills is evident.

Imports and Exports

The U.S. average share of world raw steel production has declined from 60.1 percent in the

post-war 1940’s to 45 percent in the 1950’s, 32

percent in the 1960’s, and 25 percent in the

1970’s. During this same period, imports as a percentage of apparent U.S. domestic steel supply—

negligible during the first half of this century—

rose from 0.24 percent in the 1940’s to 15.5 percent in the 1970’s. Imports represented approximately 20 percent of apparent domestic steel

supply in 1981 and 25 percent by the second

quarter of 1982.15

The primary source of competition for U.S.

steel sales in the U.S. market has come from

Japan, whose production costs are about 20 percent lower. The U.S. Council on Wage and Price

Stability compared production costs in dollars per

net ton of finished steel products, assuming the

U.S. product mix for 1976. The two primary

sources of the Japanese cost advantage were associated with higher U.S. labor costs ($1 00.24 per

ton in the United States, compared to $60.48 per

ton in Japan) and the lower yield in converting

raw steel into finished steel in the United States

compared to that in Japan (0.71O and 0.75, respectively). 16

Focusing more directly on labor costs and labor

productivity, it is clear that among major competitors only Japan has maintained a substantial

advantage relative to the United States. The productivity of a dollar spent on labor in steel production in Japan was more than three times as

great as that in the United States in 1964 and

more than twice as great in 1975.

15 American Iron and Steel Institute, Annual Statistical Report for

1981 (May 1982) and 1982 (unpublished).

16 Council on wage at-id Price Stability, Report to the President

on Prices and Costs in the U.S. Steel Industry, 1977; Technology

and Steel Industry Competitiveness, ch. 4, op. cit.
Ch. 7—The Steel Industry ● 145

For the period 1957-75, the hourly labor costs

rose more rapidly in West Germany, France, and

Japan than they did in the United States. For example, hourly employment costs in steel production in Japan rose 806 percent, from $0.65 in 1957

to $5.89 in 1975. From 1964 to 1975, output per

man hour increased 167 percent (from $3.51 to

$9.35) in Japan, yet only 17.5 percent (from $6.92

to $8.13) in the United States .17

The more rapid rise in hourly employment

costs in Japan and West Germany helps explain

the decline in the index of output per dollar spent

I 7

Ibid .

on labor in Japan relative to that in the United

States–from 3.22 in 1964 to 2.58 in 1975–and

the decline in the index of output per dollar spent

on labor in West Germany relative to that in the

United States–from 1.55 in 1964 to 1.09 in 1975.

If the U.S. steel industry continues to modernize

its capital equipment and to diminish the share

of non production employees in the work force,

the comparative advantage of these foreign producers in output per dollar spent on labor will

continue to decline. However, the United States

may still face stiff competition from developing

nations such as Brazil and Korea, where plant and

equipment are very modern and wage rates are

very low.

ENERGY AND TECHNOLOGY

Production Processes

Energy is consumed in steel production during the processes of six major stages: preparation

of raw materials, ironmaking, steel making, primary finishing, secondary finishing, and heat

treating. Table 51 lists major process technologies

for each stage of production and figure 34 combines them in a flow chart.

Table 51 .—Energy Services and Major Processes in

the Iron and Steel Industry

Energy service Major processes

Beneficiation . . . . . . . . . Sintering

Pelletizing

Coking ., . . . Byproduct coke oven/wet quench

Byproduct coke oven/dry quench

Formcoking

Ironmaking ... ... Blast furnace

Blast furnace with hydrogen injection

Direct reduction—gas

Direct reduction—coal

Steelmaking Basic oxygen furnac e

Electric arc furnace

Open hearth furnace

Primary finishing . . ., Ingot casting/soaking/breakdown mill

Continuous casting

Ladle preheating

Secondary finishing. . Batch reheating/rolling

Continuous reheating/rolling

Electric induction reheating/rolling

Direct rolling

Cold rolling

Heat treating . . . . . Direct tube furnace

Radiant tube furnace

Electric furnace

SOURCE Off Ice of Technology Assessment

Preparing Raw Materials

Iron ore, coal, and limestone are the raw materials of making steel. After preparation, they are

combined in a blast furnace, where the iron ore

is smelted to metallic ore. Coal, which is first converted to coke, supplies the carbon necessary for

generating the terrific heat and reducing gases

necessary for smelting. Limestone is used to combine with the impurities in the molten iron to form

slag, which floats atop the liquid and can be removed.

During materials preparation, two processes

are particularly energy intensive.

Beneficiation of Iron Ore.–Through several

processes known generally as beneficiation, iron

ore chunks are first crushed and ground, then refined. They are then agglomerated, that is, sintered (heated to form a mass) and formed into

marble-sized pellets. The agglomeration processes are particularly energy-intensive,

Coking.–The reduction of iron ore to metallic

iron is most economically accomplished by carbon. In modern ironmaking, the source of carbon is coke, a solid, relatively nonvolatile product, about 90 percent pure carbon, that remains

when coal is heated at 1,650° to 2,000° F for 12

to 18 hours to boil off its volatile components.

99-109 0 - 83 - 11
146 • Industrial Energy Use

Figure 34.—Process Flows in the Iron and Steel Industry

Energy service Process flow

category

Iron ore Iron ore fines

Agglomeration . . . . . . . . . .

Met

Coking . . . . . . . . . .

Ironmaking . . . . . . . . . .

Steelmaking . . . . . . . . . . . .

[

Lump

iron ore

Primary

finishing . . . . . . . . . . . . .

Secondary

finishing . . . . . . . . . . . . .

Heat treating . . . . . . . . . . . .

SOURCE: Energy Productivity Center, Mellon Institute, Final Report on Industrial Energy Productivity Project, Volume 4, The

Iron and Steel Industry, September 1982.
Ch. 7—The Steel Industry • 147

There are two proven processes for manufacturing coke, the beehive oven and the byproduct

(slot) oven; although in the United States the

byproduct process is used almost exclusively. In

the byproduct process, coal is heated in chambers in the absence of air by the external combustion of fuel.

Ironmaking

Iron ore must be first transformed to metallic

iron by the reduction of the iron oxides in the

blast furnace–the conventional, and only, technology existing in the United States today to produce iron. To make iron, iron-bearing materials

(iron ore, sinter, pellets, mill scale, slag, iron or

steel scrap, and the like), fuel (coke), and flux

(limestone and/or dolomite) are charged into the

top of the blast furnace. Heated air (blast) and,

in some instances, fuel (gas, oil, or pulverized

coal) are blown in at the bottom. The hot air blast

burns the coke to heat, reduce, and melt the

charge as it descends through the furnace. The

liquid iron and slag that collect in the furnace are

tapped at regular intervals through separate tap

holes.

Blast furnace capacities vary from 1,000 to

10,000 tons per day of hot metal. The industry

trend is toward large furnaces. The two most recently built blast furnaces have a production

capability in the range of 8,000 to 10,000 tons

per day.

Steelmaking

Steelmaking is a refinement process whereby

undesirable amounts of other chemical elements,

such as carbon, manganese, phosphorus, sulfur,

and silicon are reduced and removed from the

pig iron, and small quantities of other elements

(fluxes and alloying materials) are added to produce desired steel properties.

Steel is made in three types of furnaces–the

basic oxygen furnace, the electric arc furnace,

and the open hearth furnace. All three processes

are used to produce carbon steel. Stainless steel

is limited to basic oxygen furnaces and electric

arc furnaces; the latter are also used to produce

special alloys from select scrap feedstocks.

Now the leading and fastest steel making process, the basic oxygen furnace refines steel (in

about 32 minutes per batch) by blowing oxygen

into the furnace, producing an intense chemical

reaction in the charge of scrap, molten iron, and

lime. The basic oxygen process produced 61 percent of the Nation’s raw steel in 1979.

The electric arc furnace refines molten iron and

produces steel by electric arcing between three

carbon electrodes and the scrap iron charge. I n

1980, such furnaces produced 27 percent of the

Nation’s raw steel.

The open hearth furnace is charged by scrap

limestone, and iron, followed by molten iron.

Oxygen and natural gas, fed into the bath, produce the temperatures necessary to refine the

mixture into steel. The open hearth process,

which dominated steelmaking in the United

States for many years, has steadily lost ground.

Production in open hearth furnaces declined

from 85 million tons (64 percent) in 1966 to 13

million tons (12 percent) in 1980.

Primary Finishing

Primary finishing includes the operations of

casting—pouring liquid steel into its first solid

form (raw steel)–and then converting the raw

steel to semifinished shapes such as slabs,

blooms, and billets. There are two casting techniques, ingot and continuous.

In ingot casting, the conventional casting method, liquid steel is tapped into a refractory-lined,

open-topped vessel called a ladle. The ladle is

moved by an overhead crane to a pouring platform where the steel is then poured or “teemed”

into a series of molds. The steel solidifies in each

of the molds to form a casting called an “in got.”

Subsequently, the molds are removed, and the

stripped, cooling ingots are placed in a soaking

pit, where they are reheated to an even temperature for rolling (shaping). After soaking, the

molds are transported to mills for rolling into

blooms (rectangular forms) and billets (square

forms) for use in structural shapes and bars, and

slabs, for use in all flat-rolled steel.

Continuous casting is a newer process in which

liquid steel is directly cast into the desired semi-
148 ● Industrial Energy Use
Ch. 7—The Steel Industry . 149

Photo credit: American Iron and Steel Institute

Molten iron is being tapped and taken away from the blast

furnace for further processing into steel

Photo credit: American Iron and Steel Institute

Steel from the electric furnace is being poured into ladle for

processing in the continuous caster

finished shape, thus eliminating the intermediate

steps of ingot casting and reheating, and lowering the energy per final ton of product. Figure

35 shows a cross-section of a typical caster.

Secondary Finishing

Secondary finishing includes the operations of

reheating the slabs, blooms, and billets produced in primary finishing and transforming them

through hot and cold rolling steps into final products. Reheat furnaces are used to heat steel

shapes to temperatures of 2,300° to 2,400° F

prior to rolling operations. Such furnaces can be

classified into two types—batch and continuous—based on their mode of operation. Fossil

fuels are the usual energy sources in these furnaces, but electric furnaces are also used.

Heat Treating

The final step in the finishing operations is heat

treating. Cold-working steel results in a highly

stressed product with low ductility. The principal

purposes of heat treating are to relieve these

stresses, obtain full recrystallization to a more

uniform grain structure, and improve ductility to

a level suitable for forming operations. This goal

is accomplished by heating the steel to a specified

temperature at which it is held for some time

(soaking), followed by gradual cooling. The most

common heat treatments performed are annealing, normalizing, spheroidizing, hardening, tempering, carburizing, and stress relieving. Of these,

annealing is done on the largest scale within the

U.S. steel industry.

Energy Use

All of the stages of steel production use energy

to alter the chemical composition of the metal
150 ● Industrial Energy Use

Figure 35.—Cross.Section of a Typical Continuous Casting Machine

Withdrawal machine

Spray

I

J.-L I

SOURCE: American Iron and Steel Institute, 1976

or to work the metal into useful forms and shapes.

Every plant and company has its own unique mix

of process efficiencies, for a variety of reasons

such as the age of the plant, the design of equipment, and the mix of products. As an illustration,

the mix of primary and byproduct fuels for one

major integrated steelmaker is presented in figure

36.

Under the most ideal circumstances, the energy

required to produce solid iron from iron oxide

can never be less than 7 million Btu per ton

(MMBtu/ton). Since the energy required to melt

iron under the most ideal circumstances is about

1 MMBtu/ton, the inherent thermodynamic advantage of making liquid steel from scrap rather

than from iron ore is about 6 MMBtu/ton. When

process heat losses are included, the advantage

falls in the range of 9 to 14 MMBtu/ton. *

Photo credit: American Iron and Steel Institute

The slab is being torch cut after emerging from the

continuous slab caster

*These estimates include the energy value of coal at the power

generator–i.e., a conversion factor of 10,494 Btu/kWh has been

applied.
Ch. 7—The Steel Industry ● 151

Figure 36.— Energy Consumption by Production Process in a Typical Integrated U.S. Steelmaker

Coal

65.60/0

Sales

3.9%

Bled

I

Coke Basic oxygen

oven

Blast

furnace

Open hearth

furnace

furnace

furnace

6.5%

Oil

8.30/o

Electricity

5.20/.

Natural gas

20.80/0

2.90/,

)

*

I I Steam and Power

4

1

Boilers

14.0%

1 1

8.6%

4.8%

SOURCE Off Ice of Technology Assessment

current total energy requirements for the pro- Petroleum provides only a small amount of enduction of finished steel products in different

pIants and countries from iron ore range from 25

to 35 MMBtu/net ton. A review of alternative

energy sources used in steel production, along

with relative shares for the period’ 1972-80 leads

to several points worth noting. First, coking coal,

steam coal, and purchased coke consistently provide nearly two-thirds of the energy used in U.S.

steel production (see table 52). Natural gas accounts for about 25 percent; petroleum, less than

5 percent; and purchased electricity, which has

risen significantly in recent years, about 7 percent. The increase in electricity is due primarily

to increased use of the electric arc furnace. Electricity in this case is generated to a great extent

by coal or nuclear fuel.

ergy, although the substitution of petroleum and

natural gas for coal and other energy sources frequently results in net total energy savings in ironmaking and steel making. For example, total energy requirements in the iron blast furnace can

be reduced by the injection of oil or gas in the

blast, and total energy requirements in the steelmaking electric arc furnace can be reduced by

in situ heating of scrap with oxyhydrocarbon

burners,

A summary of fuel use, scrap use, and process

use during the period 1976-80 is presented in

table 52. The data are normalized on the basis

of tons of shipments. Several important trends are

evident. With the addition of continuous casting
152 . Industrial Energy Use

equipment

liquid steel

increasing

Table 52.—Fuel Use and Energy. Related Trends in the Steel Industry

Fuel use per ton of steel shipments

(10° Btu)a

1976 1977 1978 1979 1980 1981

Coal, coke. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22.4 20.0 17.2 17.9 18.2 16.0

Coal, steam. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.8 0.8 0.8 0.8 0.8 0.8

Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.7 6.2 6.1 6.4 6.7 7.0

Purchased coke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7 1.2 1.7 1.9 1.2 0.8

Fuel oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.7 2.8 2.9 2.1 1.3 1.1

Liquefied petroleum as . . . . . . . . . . . . . . . . . . . . . 0.7 1.0 0.6 0.3 0.2 0.2

Purchased electricity . . . . . . . . . . . . . . . . . . . . . . . . 1.7 1.7 1.7 1.7 1.8 1.9

Totals, 106 Btu . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36.5 33.7 30.9 31.2 30.0 27.8

Cost, c 1982 dollars . . . . . . . . . . . . . . . . . . . . . . . . . .128.4 120.6 113.7 114.0 109.4 105.6

Recent trends~

Shipments, 10° tons . . . . . . . . . . . . . . . . . . . . . . . . . 89.4 91.1 97.9 100.3 83.9 87.0

Raw steel, 10° tons . . . . . . . . . . . . . . . . . . . . . . . . . . 128.0 125.3 137.O 136.3 111.8 119.9

Yield, %

D

. . . . . . . . . . . . . . . . . . . . . . . . . . ., . . . . . . . 69.8 72.9 71.5 73.6 75.0 72.6

Continuous cast, 0/ 0 . . . . . . . . . . . . . . . . . . . . . . . . . 10.6 12.5 15.2 16.9 20.3 21.1

0/0 of raw steel:

Open hearth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.3 16.0 15.6 14.0 11.7 11.2

Basic oxygen process. . . . . . . . . . . . . . . . . . . . . . 62.5 61.8 60.9 61.1 60.4 61.1

Electric arc furnace.. . . . . . . . . . . . . . . . . . . . . . . 19.2 22.2 23.5 24.9 27.9 27.7

Total purchased scrap, %

e

. . . . . . . . . . . . . . . . . . . 36.0 40.0 40.0 43.0 48.0

aBaSed on preventative calorific values.

bAssuming 3,412 Btu/kWh.

Clg82 average prices applied tO yearly fi9ures.

dshipments divid~ by raw liquid steel, The decline in 1981 is an artifact of a sharp increase in Inventov

epercent of total metallic feedstocks.

SOURCE: American Iron and Steel Institute and the Office of Technology Assessment.

the yield of steel shipments from raw

has increased at a steady rate. The

role of electric arc furnaces has

brought a-bout a concomitant increase in the use

of scrap for steel production. While the use of

coal and petroleum products has declined over

the last 5 years, the use of natural gas per ton of

shipped steel has remained relatively constant.

These and other trends and their significance in

assessing the possible impacts of legislative options are discussed in the following sections.

Energy Conservation

Steelmaking has a number of investment opportunities to save energy or to switch to lower

cost fuels, and many have been exploited in the

past decade. A comparison of energy and production data indicates that almost 17 percent less

energy was used per ton of product in 1981 compared to 1972 (see table 53 and fig. 37). Most of

the investments that have brought about this

energy reduction can be described in terms of

specific technologies, but some save energy as

an incidental benefit of any modernization that

shortens times for processing and handling of hot

metals. A sample of these opportunities is summarized in table 54.

While there are many energy-saving technologies, the substitution in the last 5 years of continuous casting for ingot casting and the displacement of the basic oxygen furnace or open hearth

furnace by the electric arc furnace are pivotal for

economic as well as energy efficiency reasons.

In fact, analysis of 1976 and 1980 data shows that

actual reductions in energy per ton of steel shipments can be almost entirely explained by the

increased use of continuous casting and the melting of scrap in electric arc furnaces. *

Electric Arc Furnace

Electric arc furnace (EAF) technology saves

energy by allowing the substitution of scrap metal

for iron ore. Expansion of scrap-based production has been encouraged recently by relatively

low scrap prices, leading to a cost advantage of

*This analysis is contained in a separate contractor report.
Ch. 7–The Steel Industry . 153

Table 53.—Comparison of 1981 and 1972 Energy Consumption

for U.S. Steel Companies

For corporations using 1972

as the reference year

1981 1972

consumption consumption

(trillion Btu) (trillion Btu)

Bituminous coalb c 

. . . . . . . . . . . . . . . . . . . . . . . . .

-

1,144 1,944

Metallurgical . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,082 1,854

Boiler . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 83

Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 7

Anthracite coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 —

Coke (purchased) . . . . . . . . . . . . . . . . . . . . . . . . . . 182 110

Coke oven gas (purchased) . . . . . . . . . . . . . . . . . . 2 4

Tar or pitch (purchased). . . . . . . . . . . . . . . . . . . . . 3 1

Total coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,335 2,059

Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 508 667

Distillate fuel oil . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 13

Residual fuel oil . . . . . . . . . . . . . . . . . . . . . . . . . . . 81 187

Gasoline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Other petroleum products . . . . . . . . . . . . . . . . . .

—

4 1

Propane . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 1

Other liquefied petroleum gas . . . . . . . . . . . . . . . — 1

Total petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . 96 204

Electricity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119 125

Purchased steam . . . . . . . . . . . . . . . . . . . . . . . . . . 1 —

Total energy consumptions. . . . . . . . . . . . . . . . 2,059 3,055

aAll ~on~umption figures shown are net of sales, invento~ changes, and excluded usage. Dueto historical data collection

procedures for individual fuels, some groupktgof particular fuels occurs.

bBituminousco~ may include asmall amount of anthracite coal.

cEnergy content of coal byproduct sold is not included in this figure (i.efi subtracted from the gross f19ure).

dotherpetroleurn products may include S0rne9aSOline.

epropane consumption may include a small amount of other liquefied petroleum gaSes.

SOURCE: American Iron and Steel Institute, data for 51 companies operating in 1961.

Figure 37.—Comparison of Steel industry Energy

Use and Production Output, 1972 and 1981

Energy Production

use

Coal

I J

1981

Energy Production

use

Petroleum

Natural Electricity and Production

gas steam index

SOURCE” American iron and Steel Institute

over $125 per ton of shipments. Furthermore, if

total demand for steel products remains steady

or grows very slowly, supplies of scrap should

continue to balance demand and thus hold scrap

prices at favorable levels for steelmaker. This expectation is reinforced by growing supplies of directly reduced iron (DRI) from nations that have

inexpensive supplies of natural gas or electricity. DRI is an excellent EAF feedstock because it

is free of trace elements that contaminate scrap;

therefore, mixtures of DRI and scrap may be used

in the future to produce higher quality steel products.

Continuous Caster

Continuous casting is more energy efficient

than ingot casting for two reasons. First, the use

of continuous casting eliminates the need for ingot stripping, reheating, and primary rolling. Second, the yield of slabs and billets from continuous

casting is much greater than that from ingot casting because less metal must be returned to the
154 ● Industrial Energy Use

Table 54.-Technologles for Improving Energy Efficiency in the Steel Industry

Investment option Energy efficiency-improving characteristics

Dry-quenching of coke

Coke-oven gas desulfurization

Blast furnace top gas turbine

External desulfurization of hot metal

High-pressure blast furnace

Electric arc furnace (EAF)

Water-cooled panels, EAF

Oxy-fuel burners, EAF

Open hearth, shrouded, fuel-oxygen lances

BOF gas collection

Scrap preheating, BOF

Secondary, ladle refining, EAF (e.g., AOD)

Closed system ladle preheating

Continuous casting

Continuous slab reheaters

Continuous annealing and reheating systems

Direct rolling

Indication heating of slabs/coils

Steam-coal injection into the blast furnace

Recovers waste heat of hot coke from ovens; saves coke; reduces

environmental pollution because coke is quenched in a closed system.

Natural gas substitute. Some loss of calorific value, but improved

product quality.

Recovers waste energy by cogeneration. Only possible with the best

high-pressure furnaces.

Saves coke by allowing lower slag volume and hot metal temperature in

the blast furnace. Some energy used in desulfurization.

Lowers coke consumption.

Allows for increased use of scrap, thereby lowering overall energy

requirements for steel production.

Allows for higher productivity and net energy savings in melting when

refractory consumption is considered.

Saves electrical energy and reduces melting time. Total energy

consumption may be increased.

Reduces fuel requirements in the open hearth. May prolong useful life

of open hearth.

Recovers calorific value of carbon monoxide with net energy savings.

Allows for greater use of scrap, thereby saving energy in ironmaking.

Saves electrical energy by removing refining function from EAF.

Saves natural gas used for preheating ladles.

Increases yield, thereby decreasing overall energy requirements; saves

fuel gas in ingot reheating.

Saves clean fuel gas through increased efficiency.

Saves clean fuel gas through increased efficiency.

Saves clean fuel gas through the elimination of slab reheating.

Allows fuel switching to electricity, conserves total energy, and

increases yield.

Allows fuel switching from more expensive gas or oil. Technology

should be available in 5 years.

SOURCE: Office of Technology Assessment.

steelmaking processes in the form of waste and

unfilled ingot molds. Specifically, the use of continuous casting represents a saving of about 2

MMBtu/ton in clean gaseous fuels used in reheating and about 2.5 MMBtu/ton in the general plant

fuel mix from increased yield.

In 1981, 21.1 percent of U.S. steel was continuously cast. For comparison, continuous casting percentages of East European countries and

Japan in 1980 were 39.2 and 59.5, respectively.

If U.S. industry could invest in continuous casting

equipment to raise its percentage to 60 percent,

about 5 MMBtu/ton of shipments could be saved

without any other changes,

Although all of the technological options have

been demonstrated in domestic plants, not all of

them will be competitive investments in every situation. Many of these options require retrofitting

existing equipment. In some instances, older

equipment cannot be modified at a reasonable

cost to take advantage of the opportunity. Sometimes physical plant layout prevents adoption of

a specific technology.

In addition, it should be noted that new technologies often result in benefits that are difficult

to evaluate. For example, besides saving energy,

continuous casting and improved reheating facilities improve steel quality as well as reduce environmental problems.
Ch. 7–The Steel Industry . 155

INVESTMENT CHOICES FOR THE STEEL INDUSTRY

Investment Strategy

Firms that have traditionally been in the steel

business are not really in business to make steel,

but to make profits. The two objectives–profits

and steel—are not necessarily in conflict, as demonstrated by mini mills, but for a broad cross section of major integrated and specialty steel producers, profitability in steel appears to be a distant future goal. Certainly, given the recent capacity utilization rates under so percent and the

long downward trend for domestic steel production, the steel industry is not a strong magnet for

new investments.

With the exception of minim ills, which use

scrap metal feedstocks instead of iron ore and

coke, existing steel firms are now deciding

whether to invest more in steel or not; if they do,

large investments are required just to match their

foreign and domestic competition. Profits can still

be made, but current low operating rates make

investment difficult because they severely limit

internal funds. Attempts to raise outside capital

can lower credit ratings and sharply discount

stock values. In these circumstances, many existing firms are forced into triage, writing off their

least competitive shops in order to keep their best

capacity on line.

Negative investment prospects would turn

around if general economic activity were to pick

up sharply. When industry experts were asked

to comment on the impacts of the four policy options analyzed by OTA, they generally couched

their responses in terms of the need for product

demand to increase, followed by concern about

high interest rates as they affect both product

market demand (i e., steel-intensive products are

often investment goods) and the cost of borrowing for steel industry investments. High interest

rates reduce the leverage of all four policy options by making it more difficult to achieve efficient capacity configuration. Both of these general economic concerns, the depressed GNP and

high interest rates, were often raised to suggest

that the steel industry’s present use of energy was

justified by existing product and factor markets.

Closely following is a third broad economic issue—steel imports. Among integrated and specialty steelmaker, there is the widespread belief

that many exporting countries are unfairly subsidizing steel exports to the United States and that

such imports have been a major reason why domestic capacity is below the 50 to 60 percent

levels necessary for breaking even. Consequently,

a large cross section of firms believes that restriction of steel imports is a top priority for Government action.

Appropriately, in an economy based on notions

of free trade, steel industry proposals for import

restriction are controversial. Critics question the

steel industry’s willingness and ability to meet

legitimate foreign competition. They point out

that research, development, and demonstration

efforts have been minimal for several decades,

despite the growing foreign competition. They

also identify important inefficiencies in major integrated mills that can be traced to longstanding

company and union policies, practical only when

U.S. technology was preeminent. Finally, several

major companies have recently demonstrated a

clear lack of confidence in their ability to compete by abruptly closing down existing plants

without replacement and by diversifying into

nonsteel activities.

In addition to this general economic background, an energy-related discussion of steel industry investment should take into account the

industry’s legitimate strategic goals of overall cost

minimization and product market growth. Within

total costs or total cost per ton, energy (including

coke) constitutes 25 to 30 percent, which is somewhat less than the cost share for labor and only

somewhat larger than shares for materials and

capital. Furthermore, by far the largest energy expenditure is for coal (on the average around 66

percent, excluding coal-fired electricity), which

is the most abundant energy resource in the

United States. If special attention for energy is

justified, it must be primarily because natural gas

(a premium fuel) accounts for about one-fourth

of total steel energy.
156 ● Industrial Energy Use

In other words, energy investments must compete for scarce funds along with all other profitable technologies, and in order to examine energy impacts of Federal policy options, the full

range of technical investment alternatives must

be considered. Fortunately, as discussed above,

this does not really stretch the analysis far from

energy because the two primary energy-saving

technologies, continuous casters (CC) and EAFs,

are also two of the best investments to reduce

total costs per ton of steel. In fact, CCs and EAFs

are virtually mandatory investments for any firm

wishing to modernize itself. Without continuous

casting, low-product yields and quality, as well

as high energy costs, diminish sales and profits.

Similarly, without expanding EAF capacity to

maximize scrap utilization to produce lower

grade carbon steel products, a firm can have costs

in excess of $100 per ton higher than those of

its competitors. Consequently, with significant opportunities remaining for both technologies in the

United States, CC and EAF investments act as bellwethers for domestic steel. Investment in additional CC and EAF capacity amounts to a greater

commitment to stay in the steel business and thus

to invest in other projects that improve product

quality and reduce total costs.

Specific Energy-Related Investments

While the following policy analysis will focus

on generic CC and EAF technology, there are

many other energy investments that save energy

and reduce energy costs to a lesser extent. Significant energy savings may also be achieved indirectly when large investments in product finishing motivate complementary plant reconfiguration that reduce delays in product handling, and

thus heat losses in reheating (see table 54).

When all of these direct and indirect routes to

energy saving are added together, they can save

as much energy as the addition of CCs or an EAF.

But project economics vary a great deal from

plant to plant, making it difficult to describe

generic projects. Several have been included

along with the given CC and EAF in the illustrative

internal rate-of-return (1 RR) calculations, but it is

important to remember that all such calculations

when applied to real investment planning are

highly site-specific.

POLICY IMPACTS ON THE STEEL INDUSTRY

policy impacts on energy consumption by the

steel industry are defined by comparison to a

reference case projection that assumed no

change in current policies, including the accelerated depreciation section of the Economic

Recovery Tax Act of 1981 (ERTA). Safe harbor

leasing provisions are not included in the projections made below, although the steel industry has

been among the largest users of this opportunity

to raise investment capital by reducing corporate

income taxes.

The Reference Case

The steel industry is currently making investments that sharply lower production costs by increasing energy efficiency, among other improvements in process efficiency and product quality.

Besides investments in EAF and CC, significant

savings in energy costs are expected in the 1990’s,

when technology will be available for substituting

steam coal for natural gas and oil as hydrocarbon, which is injected directly into the blast furnace.

In this reference case, OTA assumed the fuel

price growth rates, general economic growth

rates, and steel industry growth rates shown in

table 55. Figure 38 shows that OTA projects energy efficiency in the production of steel to

decline from 31 MMBtu/ton of shipments to

about 19 MMBtu/ton by 2000, an improvement

predicated on slow but steady growth in shipments. This growth in demand for domestic products is important to assure the availability of investment funds, especially for the large, integrated producers who in the fall of 1982 were

operating well under .50 percent of their available

capacity. If this growth in demand does not

occur, improvements in efficiency will occur

more slowly, although total energy use may not
Ch. 7—The Steel Industry ● 157

Table 55.—Historical and Projected Growth Rates for

Production and Fuel Prices, 1976-2000

1976-80 1980-85 1985-WI 1990-2000

All manufacturing FRBa growth rate . . . . . . . . . . 3.25°/0 3.9% 4.30/0 3.7%0

Iron and steel industry . . . . . . . . . . . . . . . . . . . . . . –1.6 0.8

Fuel price, gas($MMBtu) . . . . . . . . . . . . . . . . . . . . — 9.0

Fuel price, residual ($/MMBtu) . . . . . . . . . . . . . . . – 5.0 6.2 9.0

Fuel price, coal ($/MMBtu) . . . . . . . . . . . . . . . . . . . – 2.2 2.3 2.4

Fuel price, electricity ($/MMBtu) . . . . . . . . . . . . . .– 13.8 13.7 13.8

a

Federal Reserve Board.

SOURCE’ Office of Technology Assessment

Figure 38.—Iron and Steel Industry Energy

Intensity Projections, 1970-2000

18 I

I I 1 I I !

1970 1975 1980 1985 1990 1995 2000

Year

exceed projected levels because of the shutting

down of older, fuel-inefficient capacity.

As part of this general, energy efficiency improvement, the reference projection calls for a

steady decline in the use of both oil and gas,

shown in table 56, as both premium fuels are displaced in reheating (of in-process ingots, slabs,

and billets) and in blast furnace injection. Use of

metallurgical coal is also expected to decline,

primarily because of the displacement of hot iron

from the blast furnace by melted scrap and by

directly reduced iron from the EAF. There will

also be major declines in the coke rate per ton

of hot iron due to the direct injection of cheaper

hydrocarbons (steam coal) into the blast furnace.

SOURCE Office of Technology Assessment

Table 56.—Fuel Use Summary: Reference Case, 1980-2000 (In trillion Btu)

Total fuel Use

Natural Residual Distillate Metallurgical Total

Year gas oil oil coal Steam coal Electricity Other fuels primary fuels

1980 . . . . . . . . . . . . . . 448 175 33 1,675 213 0.8 2,615

1985 . . . . . . . . . . . . . . 438 136 20 1,617 : : 244 2,543

1990 . . . . . . . . . . . . . . 368 117 15 1,417 111 262 1.0 2,291

2000 . . . . . . . . . . . . . . 297 95 10 979 400 307 1.0 2,088

Fuel use as percent of total purchased fuels

Metallurgical

Year Gas Oil Steam coal coal Electricity

1980 . . . . . . . . . . . . . . . . . . . . . . 17 8 64 8

2000 . . . . . . . . . . . . . . . . . . . . . . 15 3 20 47 15

Fuel use as percent of total purchased fuels minus metallurgical coal

Year Gas Oil Steam coal - Electricity

1980 ....., . . . . . 43 20 7 20

2000 . . . . . . . . . . . 27 6 38 29

SOURCE: Off Ice of Technology Assessment.
158 . Industrial Energy Use

The reference case and policy impacts are also

illustrated in terms of the profitability of generic

investment options. Table 57 describes eight generic investments, along with economic and energy assumptions used to dollars. The profitability

of each project is reflected in the calculated IRR

on investment (see table 58).

Projected Effects of Policy Options

Option 1: Removal of Accelerated

Depreciation

Like all capital-intensive industries, the steel industry welcomes policies that reduce the tax burden on income. Safe harbor leasing conferred exceptionally large benefits on the steel industry—

primary metals obtained the third largest share

of leased property among two-digit SIC industries

–because many modernization investments

were well over due and because low profit rates

would not otherwise have provided the opportunity to shelter income from taxes via accelerated depreciation.

The outstanding policy question, however, involves incremental investment activity. Has the

steel industry made significantly greater investment in energy-saving equipment because of

ERTA and can it be expected to do so in the

future? Equivalently, because energy saving and

cost reduction are more or less accomplished by

the same key technologies, has there been significantly greater investment in general?

Table 57.—Steel Industry Projects To Be Analyzed for Internal Rate of Return (lRR) Values

1. Electric arc furnace. -This furnace is used to melt

steel scrap into molten metal suitable for secondary

refining, rolling, and casting. Assuming scrap is

available at reasonable prices, this investment will

substantially lower product costs as well as save

energy.

Project life—10 years.

Capital costs—$20 million.

First year cost savings—$12 million. 6.

2. Reheat furnace.—Replacement of existing reheat

furnaces improves energy efficiency because

prolonged use would have degraded old unit and

because the new unit embodies technological

developments since the original unit was installed.

Project life—10 years.

Capital costs—$12 million.

First year cost savings—$3.5 million. 7.

3. Continuous caster.—Continuous casting lowers costs

and saves energy by eliminating costs of ingot casting

(e.g., stripping, reheating, and primary rolling) and by

reducing waste in the form of metal which must be

returned to the steelmaking process.

Project life—10 years.

Capital costs—$125 million.

First year cost savings—$30 million.

4. Dry-quenching of coke. —Dry-quenching involves

sealing the coke battery and thus in order to recover 8.

thermal and particulate emissions as finished coke is

cooled. H results in higher yields and fuel savings

besides reduced environmental emission.

Project life—10 years.

Capital costs—$16 million.

First year cost savings—$2 million.

5. Inventory control. -A computerized system can keep

track of product item availability, location, age, and the

like. In addition, these systems can be used to

forecast product demand on a seasonal basis. The

overall effect is to lower inventory, yet maintain the

ability to ship products to customers with little or no

delay. In typical installations, working capital costs are

dramatically reduced.

Project life—5 years.

Capital and installation cost–$560,000.

Energy savings—O directly, but working capital could

be reduced by $1.2 million.

Electric motors. -The steel industry uses electrical

motors for rolling, mixing, pumping, and solid

materials transfer. In this analysis, OTA has assumed

that five aging electric motors will be replaced with

newer, high efficiency ones.

Project life—10 years.

Capital and installation cost–$35,000.

Energy savings–$16,000 per year at 4¢/kWh.

Computerized process control—The most common

retrofit purchases being made for industrial systems

are measuring gauges, controlling activators, and

computer processors. The main accomplishment of

such a process control system is to enhance the

throughput and quality of a steel mill with only

materials and small energy inputs.

Project life—7 years.

Capital and installation costs–$500,000.

Energy savings—$150,000 per year.

Steel mill cogeneration project.—lnstallation of a

turbogenerator unit to recover electrical power from

steam production facility. Superheated steam is

produced at 600 psi and then passed through a

mechanical turbine to generate electricity. The turbine

exhaust, which is 175 psi steam, is used then for

normal plant production.

Project life—10 years.

Capital and installation cost–$231,000.

Energy savings—$72,300 per year.

SOURCE: Office of Technology Assessment.
Ch. 7—The Steel Industry ● 159

Table 58.—Effects of Policy Options on IRR Values of

Steel Industry Projects

IRR with policy options

$1/MMBtu

Reference ACRS 100/0 tax

Project case removed EITC no EITC

Electric arc furnace. . . . . 5 7 55 63 57

Electric motors . . . . . . . . 43 43 48 43

Reheat furnace . . . . . . . . 31 29 35 37

Continuous caster. . . . . . 25 24 30 26

Process control . . . . . . . . 16 17 22 16

Dry-quenching . . . . . . . . . 13 12 16 13

Waste heat boiler . . . . . . 11 11 14 16

Cogenerator . . . . . . . . . . . 11 11 15 17

SOURCE Office of Technology Assessment.

There is no short, quantitative answer. OTA has

only scattered data on 1981 investment behavior

and even with a complete data set, calculation

of the incremental impact requires knowing what

investment would have been without ERTA. Furthermore, since only a year has passed since

ERTA became law, actual investment data would

not reflect many large projects that may have

been initiated as a result but have not proceeded

beyond the planning stage. From 1979 through

1980 announcements for planned investments

were as high as $7 billion, a fact that strongly suggests that many steel firms believed that ERTA

would sharply improve steel prospects. Unfortunately, many projects appear to have been

shelved owing to deteriorating sales in 1982.

Regarding the CC and EAF, several pertinent

observations can be made. Generic I RR calculations indicate that the accelerated cost recovery

system (ACRS) marginally increases the profitability of both technologies (see tables 57 and 58).

However, virtually all industry representatives indicated that such marginal improvement has almost nothing to do with actual investment decisions. For EAF, the very large potential reduction

in cost per ton allows paybacks that are already

in the range of 2 years. It takes longer to amortize a CC, but such investments must be made

in order to meet the competition, both in quality and cost. The domestic industry realizes that

both technologies are essential, and therefore

these investments will proceed at a pace determined primarily by product market conditions

and the availability of funds. Since most domestic

steel firms are severely restricted in their access

to debt and equity markets, ERTA has probably

increased steel investment only to the extent that

it has actually increased retained earnings. Highly

profitable minimills are the exception because

they have relatively easy access to outside capital

and so the ERTA tax savings can be leveraged into

much larger actual investments.

In the energy savings and energy use projections shown in figure 39, ACRS helps cogeneration potential in this industry and encourages improvement in blast furnaces rather than greater

reliance on electric arc furnaces-hence, the increase in purchased electricity and lower metallurgical coal demand shown without the ACRS.

Overall energy, however, is not affected significantly since the most promising technologies

here (CC and EAF) are likely to penetrate without

the help of a new depreciation scheme.

Option 2: Energy Investment Tax Credits

Like ERTA, the energy investment tax credit

(EITC) would have its greatest impact on steel investment by increasing retained earnings. As

shown in table 58, it would have a somewhat

greater impact on IRR, based on generic project

data, but again the increment in IRR would be

of small consequence compared to product demand assessments in decisions of whether or not

to invest in a CC or EAF.

Energy projections in figure 39 show that an

EITC would help the steel industry displace some

of its natural gas use in high-temperature heating,

mostly through better and wider use of heat recovery equipment. It would have less impact on

the use of oil, since oil is not used as widely as

gas in applications with heat recovery potential.

As a result, total energy demand would change

very little in response to the incremental savings

from heat recovery.

Offsetting these limited financial benefits, several industry experts were concerned about why

tax credits should be targeted to energy use at

all. in their view, just about every major investment will involve energy conservation, so targeting may just mean unnecessary administration.

Since their primary goal is to reduce total costs,

they see no obvious reason why energy deserves

more attention than do labor, capital, or materials. Indeed, special tax incentives for retrofits
160 • Industrial Energy Use

Figure 39.—Steel Industry Projections of Fuel Use

by Policy Options, 1990.2000

Fuel Use Projections

1990

= 2.5

0.8

0.7

and Fuel Savings

2000

Ref No EITC Btu Cap

case ACRS tax avaiI

Ref

case

No

ACRS

EITC Btu

tax

Cap

avail

Natural

gas

Oil Coal

Fuel Savings Projections

Purchased

electricity

0.6 1990 2000

0.5

0.4

0.3

I

0.2 - —

—~

—

0.1

Ref No EITC Btu Cap Ref No EITC Btu Ref

case ACRS tax avail case ACRS tax avail

Recovered Cogenerated

energy energy

SOURCE: Office of Technology Assessment
Ch. 7—The Steel Industry ● 161

(which presumably is how an EITC would apply)

could delay or cancel construction of new plants,

which many believe couId be more efficient in

the long run. They emphasized that they would

be more concerned if oil were a significant fuel

input. Instead, coal is by far the most important

fuel, and at $2.50/MMBtu, there seems to be little economic incentive to subsidize coal conservation.

Furthermore, many in the steel industry are disillusioned by their experience with the original

EITC passed in 1978. At that time, the Treasury

Department narrowly defined the list of qualifying equipment, excluding specifically the CC because the CC could be justified on grounds other

than energy savings. Based on that experience,

industry representatives fear that any new EITC

legislation wouId suffer the same fate. Thus, they

would rather focus their attention on more pressing issues, such as legislation to restrict i m ports.

Option 3: Tax on Premium Fuels

Like virtually all materials-intensive industries,

the steel industry does not welcome additional

taxes on key energy inputs. Approximately 3 percent of total U.S. gas consumption is used for

steel. Gas accounts for about 20 percent of the

steel industry’s total energy supply (including

energy for coking coal). Although the steel industry does not use a significant amount of oil

directly, steel’s primary industrial customers do–

especially the auto industry, but also industries

involved with consumer durables and construction. All of these industries are affected by oil and

gas prices, and an across-the-board tax on these

premium fuels would tend to depress what are

already depressed activity levels in these industries. Another major concern was that such

a tax would disadvantage U.S. firms compared

to untaxed foreign competition, causing exports

to decline and imports to rise.

However, if an energy tax were to help balance

the Federal budget, and thereby lower interest

rates and generally improve growth prospects for

the GNP, the net impact on the steel industry

could be positive. This prospect was considered

too speculative compared to the obvious bias in

the short run against industries whose fortunes

rise and fall with prices of premium fuels.

OTA modeling projections, as shown in figure

39 indicate that a tax on premium fuels, when

compared to the reference case, would have little impact on either energy saved or fuel used.

This is to be expected, since the steel industry

uses predominently coal, and the policy option

is designated not to apply to coal. The IRR calculations in table 58 also show little impact.

However, despite its lack of effect on energy

saved or used, the premium fuels tax wouId affect the steel industry in other ways, primarily by

reducing demand for steel in autos and other consumer durables. industry managers and experts

with whom OTA consulted were unanimous in

their condemnation of an energy tax as being a

burden the steel industry, in its current depressed

state, could not well bear.

Option 4: Low Cost of Capital

All respondents from the steel industry would

like lower interest rates, ideally as a result of a

general decline in the real cost of borrowing.

Lower interest rates would make all capital-intensive industries more competitive, including the

steel industry; and it would make steel-intensive

consumer durables, such as home appliances and

autos, more attractive. However, this prospect

is not directly relevant to this study because a

general lowering of interest rates is not really an

energy policy option.

Instead, what is meant is a special concessionary rate for energy-intensive industries in

general and the steel industry in particular. This

would lower investment costs, but i n order to be

realistic, this policy option must limit the total

amount of debt that would be covered. To make

a difference, at least $10 billion must be involved

over a period of at least 5 to 10 years in order

to convince a severely depressed industry to

mount a large new effort to become more competitive. If $10 billion were outstanding for 10

years, and if the subsidy were 5 percentage

points, then Federal outlays would be $5 billion,

an amount that does not include costs to the entire economy as funds would be diverted from

higher valued uses. A much smaller program

could simply drive out privately placed debt with

no net increase in total investment.

99-109 0 - 83 - 1 2
162 ● Industrial Energy Use

Assuming such a special program, however,

this policy initiative would have greater impacts

than the other policy options, both in terms of

projected fuel use changes and in terms of illustrative rates of return for energy-related investment (compare tables 58 and 59). As seen in figure 39, natural gas and fuel oil use drops 3 to 5

percent, while coal and purchased electricity demand rise by compatible amounts. Total energy

demand also drops (most noticeable in 1990) because of higher conservation through waste-heat

recovery and higher investments in new energyefficient technologies for processing and for

cogeneration. Even though more in-plant electricity generation by utilities tends to increase the

industry’s fuel demand (since it is incurring more

generation losses), the steel industry’s total energy

demand fell slightly. This decline results from the

compensating factor of more efficient use of

energy through increased waste-heat recovery.

Given that steel is not heavily dependent on

oil, many respondents questioned how energy

concerns could justify a large capital subsidy. FurTable 59.—Effect of Lower Interest Rates on

IRR Values of Steel Industry Projects

IRR with

Reference case IRR policy options:

with 16°/0 interest rate

interest rate of 80/0

Inventory control . . . . . . . . . 3850/o 370%

Electric arc furnace . . . . . . . 101 107

Electric motors . . . . . . . . . . . 93 97

Reheat furnace . . . . . . . . . . . 54 60

Continuous caster . . . . . . . . 46 53

Computerized

process control. . . . . . . . . 36 44

Waste heat boiler . . . . . . . . . 24 27

Dry-quenching . . . . . . . . . . . . 17 25

SOURCE: Office of Technology Assessment.

thermore, a large subsidy offer may not be accepted if domestic firms still do not expect to produce competitively. Conversely, loans may be

obtained and then defaulted as optimistic sales

projections do not materialize and firms become

insolvent. Given many marketing uncertainties

and a highly charged political atmosphere where

many jobs are at stake, market viability issues

would be exceedingly difficult to resolve.
Appendix
APPENDIX A

The Industrial Sector

Technology Use Model

One approach to assessing the potential impact of

legislative options on industrial energy use and related

investment has been the use of the Industrial Sector

Technology Use Model (ISTUM). * The ISTUM approach is to specify end-use energy services (e.g.,

bleaching in the pulp and paper industry) and to balance technologies providing similar services and outputs in order to predict minimum, direct, Iifecycle

costs. The model’s fundamental decision criterion,

minimum Iifecycle costs, is used to assess market penetration levels of each competing energy service technology, after which it is possible to project total energy

demand, fuel mix, and energy-related investment for

each industry and for the overall industrial sector. It

is the changes in these projections, resulting from the

impact of various policy measures, that are used as

part of OTA’s assessment.

ISTUM provides a framework for a comprehensive

accounting of energy use in the entire industrial sector. It focuses, however, on those industries that are

major energy users and on those in which process heat

or feedstocks are a significant share of required energy

services. Thus, ISTUM targets iron and steel, pulp and

paper, petroleum refining, and chemicals industries

for particular emphasis. Together with aluminum these

industries represent all of industry’s feedstock energy

*ISTUM was developed as part of the Mellon Instttute’s Industrial Energy

Producttvlty ProJect. Energy and Enwronmental Analysis, Inc., served as a

subcontractor to the Mellon Institute under U.S. Department of Energy contract No. DE-ACO1 -79CS-401 51.

uses, over 60 percent of current fuel use in boilers and

nearly half of fossil fuel used in industrial process heat.

The key elements of organization of ISTUM are the

27 industrial sector classifications listed in table A-1

and the 52 energy service categories listed in tables

A-2 and A-3. Primary emphasis is on energy end use

rather than on fuels use. In steel making, for example,

emphasis is on the energy needed to convert scrap

and pig iron into liquid steel, to shape steel, and to

increase the structural strength of steel products.

As shown in table A-2, ISTUM identifies 13 energy

services as generic—i e., common to most industries.

These include such services as steam generation, mechanical drive, and space heating. Table A-3 lists the

39 industry-specific services, such as bleaching in the

pulp and paper industry and heat treating in the iron

and steel industry. This distinction is important because many energy services are generic, and thus

there is a large market for energy efficiency-improving

technologies throughout the industrial sector.

Figure A-1 lists the data inputs required for ISTUM

and illustrates schematically this model’s approach to

projecting market shares of competing energy serviceproviding technologies.

The time horizon of ISTUM is long, extending to

2000 in 5-year increments. Its base year is 1976, the

most recent year for which detailed energy use data

is available from the U.S. Department of Commerce.

Future industrial energy demands are calculated for

each energy service by converting external (to the

Table A-l.—Standard Industrial Classification Codes Covered in ISTUM

SIC Name SIC Name

10, 14 . . . . . . . . .

11-13 . . . . . . . . . .

15-17 . . . . . . . . . .

20 . . . . . . . . . . . .

21 . . . . . . . . . . . .

22 . . . . . . . . . . . .

23 . . . . . . . . . . . .

24 . . . . . . . . . . . .

25 . . . . . . . . . . . .

26 . . . . . . . . . . . .

27 . . . . . . . . . . . .

28 . . . . . . . . . . . .

Crops

Livestock

Nonenergy mining

Energy mining

Construction

Food

Tobacco

Textiles

Apparel

Lumber

Furniture

Paper

Printing

Chemicals

29. . . . . . . . . . . .

30. . . . . . . . . . . .

31 . . . . . . . . . . . .

32. . . . . . . . . . . .

331. . . . . . . . . . .

3334 . . . . . . . . . .

334. . . . . . . . . . .

34. . . . . . . . . . . .

35. . . . . . . . . . . .

36. . . . . . . . . . . .

37. . . . . . . . . . . .

38. . . . . . . . . . . .

39. . . . . . . . . . . .

Petroleum

Rubber

Leather

Stone, clay, and glass

Iron and steel

Aluminum

Other primary metals

Fabricated metals

Nonelectric machinery

Electric equipment

Transportation equipment

Instruments

Miscellaneous

SOURCE Standard Industrial Classification Manual (Washington, D C Office of Management and Budget, 1972)

165
——

166 ● Industrial Energy Use

Table A-2.—Generic Energy Services Used in the

Industrial Sector Technology Use Model

Boiler generated steam

Cogenerated steam

Machine drive

Space, H, V, and AC

Electricity generation

Refrigeration

Transportation

Lighting

Direct steam

Heating, dirty

Heating, direct, clean

Drying, dirty

Drying, direct, clean

SOURCE: Mellon Institute, Industrial Energy Productivity Project, Final Report,

vol. 1, Executive Summary, September 1982,

Table A-3.—lndustty Specific Energy Services Used

in the Industrial Sector Technology Use Model

Lime calcining Paper lime calcining

Concentration Distillation

Paint drying Cracking

Textile drying Alkylation

Food drying Hydrogen production

Metal melting Hydrotreating

Forging Reforming

Heat treating, generic Agglomerate ion

Feed stocks Iron making

Aluminum melting Coking

Aluminum heating Steel making

Aluminum electrolysis Primary finishing

Brick firing Secondary finishing

Cementmaking Heat treating

Glass melting Organic chemicals

Pulping Inorganic chemicals

Bleaching Plastics and resins

Papermaking Chemical fertilizers

Chemical recovery Chemical feedstocks

Pulp drying

SOURCE: Mellon Institute, Industrial Energy Productivity Project, Final Report,

vol. 1, Executive Summary, September 1982,

model) projections of future product demand into requirements for specific energy services, taking into account anticipated material substitutions and production process changes.

ISTUM technological options are used in three

ways: as potential energy conversion technologies, as

potential energy carrier technologies, and as possible

add-on conservation technologies. It is this multilevel

approach that constitutes the basic framework of the

technology market competition. Technology competition at each level reflects technology choices made

at lower levels. The penetration rates of all technologies are determined after the top-level decision has

been made. Relative market shares are then translated

into actual investments, and technology penetrations

and capital stocks are adjusted accordingly.

At the top level, energy conversion technologies

(i.e., technologies used to process intermediate products or raw material inputs) compete—i.e., are compared side-by-side such that the most cost-effective

technology can be identified. Alternative technologies

in a given service category may perform the task differently, but will produce the same output. For example, in papermaking, conventional and displacement

bleaching technologies can each treat pulps to the

desired degree of brightness. These technologies compete against each other under the criterion of minimizing Iifecycle cost per unit of product output.

At the next level, energy carrier technologies are

compete—i.e., technologies that convert fuel forms

to energy suitable for use in energy conversion technologies. For example, fixed- and fluidized-bed combustion technologies could compete in converting

coal to useful process heat. In addition, several energy

carriers could compete against one another for use

in a particular conversion technology. For a given industry, ISTUM will examine the lifetime dollar costs

of each energy carrier technology as a function of fuel,

capital, labor, and materials costs, and identify that

which provides the needed energy carrier at the best

cost. These carriers could be primary fuels such as

coal, oil, and natural gas, or a processed carrier such

as electricity. Processed carriers may be generated

within an industrial plant (e.g., low-Btu gas brought

onsite as coal and processed in a gasifier) or purchased

from an external utility or supplier. Competition at this

level is based on minimizing cost per unit of energy

service provided. Finally, either a carrier or conversion-level technology may benefit from the addition

of equipment that improves the technology’s efficiency of energy use. These add-on conservation options,

such as heat exchangers, heat pumps, and computer

control systems, are examined at the third level, where

they compete against the value of the energy they

would displace. This competition is based on minimizing cost per unit of energy required.

A key assumption underlying the market competition analysis is that the costs of alternative technologies

cannot be represented adequately as single-point estimates, even at the level of disaggregation built into

ISTUM. Site-specific factors will often affect costs

significantly so that when all such cases are examined,

a distribution of costs results. These distributions are

developed explicitly within ISTUM.

Comparison of technologies on a Iifecycle cost basis

requires knowledge of how each industry discounts

future costs and the accruing benefits of a given investment. In ISTUM, this aspect of industrial behavior

is represented by an explicit discount rate applied over

the useful period of the investment. With this approach, one-time investments and recurring operating,
Appendix A—The Industrial Sector Technology Use Model ● 167

. .
168 . Industrial Energy Use

maintenance, and fuel costs can be placed on a common basis, thereby allowing different technologies to

be compared on an equivalent basis.

Given the large number of industrial process steps

and the even larger number of technologies available

to carry out these steps, the first task of the ISTUM

market competition analysis was to gather technologies into groups, known in the model as homogeneous

cells. Each cell, corresponding to a particular energy

service category, allows competition only among technologies that can substitute for one another or for

other material or energy inputs. Where appropriate,

further disaggregation within a cell can allow for consideration of product quality, marketplace safety, and

minimization of environmental insult. In addition, distinctions within a cell are made for four capacity-size

classes representing different product output rates (in

units per year) and for four technology utilization factors representing the annual rate of unit use (in hours

per year). These distinctions are made because some

technologies may be technically constrained in certain size and utilization categories and because the

costs per unit of output can change for technologies

with different levels of output capability.

Within a model cell, basic equipment and other cost

components are developed as individual building

blocks, thus assuming consistent cost representation

among different technologies. Each cell covers such

items as process-related equipment, auxiliary equipment, and indirect costs, and is often in the form of

a cost distribution, reflecting variations based on sitespecific factors. For example, evaluation of a new coalfired steam boiler involves consideration of building

blocks covering site preparation and powerhouse construction, the boiler and related equipment, fuel and

waste handling equipment, environmental controls,

installation, and indirect capital costs.

Three steps follow completion of the nominal market share competition. First, nominal market shares,

derived by minimizing Iifecycle costs, are modified by

the results of a behavioral analysis. This analysis takes

explicit account of the fact that actual industrial decisions are not entirely economically derived. The

behavioral analyses incorporate a series of noneconomic-related “behavioral lags, ” thereby allowing

ISTUM to model to delayed market penetration of certain energy service-providing technologies. These

behavioral lags are intended to reflect a host of noncost factors that cause investment decisions to deviate

from strict cost minimization.

Second, given either nominal cost-minimum or behavioral-modified market shares, ISTUM transforms

these shares into absolute levels of investment, Total

demand for new equipment over a forecast period is

derived from data on existing capital stock and rate

of growth of product output. In addition, existing capital stock characteristics are modified to account for

retrofit upgrade or replacement decisions.
.,

.—

.-. .

Index
Index

accelerated cost recovery system (ACRS), 13, 15, 57, 76,

77, 110, 131, 158, 159

A. D. Little, Inc., 99

American Iron and Steel Institute (AISI), 144

American Paper Industry (API), 71, 73

American Petroleum Institute (API), 98

Annual Survey of Manufacturers, 42, 45, 115

ARAMCO, 91

Australia, 59, 60

average depreciation range (ADR), 57

Battelle Pacific Northwest Laboratories, 61

B. F. Goodrich, 115

Borden, 115

Brazil, 145

Bureau of Census, 42

Bureau of Mines, 45

Canada, 9, 59, 60, 61, 90

Canadian National Energy Business Program, 61

Carter, President Jimmy, 54

Census of Manufacturers, 42, 45, 65, 120

Chemical and Engineering News, 118

Chemical Manufacturers Association (CMA), 121, 128, 129

chemicals industry:

ACRS, removal of, 131

capital, cost of, 135

capital investment, 118, 128, 135

decrease in energy use, 4

economics of production, 116

energy conservation, 121-128

feed stock:

availability, 124

requirements, 125

physical separation technologies, 126

premium petroleum fuels, use, of, 124

production integration technologies, 127

recovery, technologies for, 127

energy intensity projections (fig. 2), 10, 12

energy investment tax credits (EITCs), 134

energy use, 120

foreign competition, 28, 118

imports and exports, 118

investment strategy, 130

overview, 115-119

premium fuel tax, effect of, 17, 135

processes, changing of, 125

product demand, 28

product mix, 12, 115

production processes, 119

ammonia, 119, 123

ethylene, 119

projects to be analyzed for IRR values (table 38), 131

reasons for study, 3

SIC major group 28, definition of, 115

structure, 115, 117

top 10 chemicals produced, 116

coal, 11, 13, 17, 18, 37, 42, 43

converting to, 50, 51

gasification, 103

liquefaction of, 106

pollution control, 51

refinery fuel, 102

tax on, 16, 17, 37, 38, 39

cogeneration, 9, 15, 16, 17, 40, 55, 56, 77, 127

definition, 51, 55

environmental problems, 52

financial returns, 52

principal advantage, 51

Council on Wage and Price Stability, 143, 144

Dale Jorgenson Associates, 7

Data Resources, Inc., 7

Denmark, 61

Department of Commerce, 22, 47, 165

Bureau of Economic Analysis (BEA), 22

Department of Energy, 4, 21, 30, 42, 43, 53, 55, 61

Industrial Energy Reporting Program, 128

Office of Industrial Programs, 58, 73, 97, 98

Industrial Energy Conservation Program, 58

Implementation and Commercialization Program, 58

Industrial Cogeneration Program, 58

Industrial Process Efficiency Program, 58

Waste Energy Reduction Program, 58

Department of Treasury, 161

DHR, Inc., 61

discretionary capital funds, 8

Du Pont, 121, 129

Eastman Kodak, 115

energy growth rate projections (table 3), 7

Energy Information Administration (EIA), 7, 45, 129

energy price assumptions (table 2), 7

energy-related technologies and processes, 48-53

computer control systems, 48

combustion control, 48

process control, 49

electric motors, 50

fuel switching, 50

coal, technology for converting, 50, 5I

cogeneration, 51, 52

product mix, 53

housekeeping, 48

retrofitting, 48

waste heat recovery, 49

heat exchangers, 49

upgrading energy, 49

heat pump, 50

vapor recompression, 50

Exxon, 107, 115

Exxon Donor Solvent, 106

Federal Energy Administration, 55

Federal Energy Regulatory Commission (FERC), 54, 55, 56

Federal Reserve Board, 47, 121

France, 61, 145

Gordian Associates, 99

171
172 ● Industrial Energy Use

gross domestic product (GDP), 59

gross national product (GNP), 7, 21, 22, 27, 28, 29, 43, 58,

66, 139, 143, 155, 161

Gulf Oil Co., 97

Gulf Research &

H-Oil, 106

Illinois, 143

Indiana, 143

industrial energy

industrial energy

Development Co., 97

demand, 1950-2000, (fig. 1), 5, 6

use:

characteristics of, 39-47

determinants of, 40

cost of equipment, 41

Government regulations, 41

level of technology, 41

product demand, 40

relative price of energy, 41

use of capital equipment, 41

end-use profile, 45

qualitative characteristics of, 41

capital effects, 43

capital intensiveness, 41

process-specific technologies, 42

raw material use, 42

shifts in energy use, 42

use of captive energy, 42

quantitative characteristics of, 43

energy use by divisions, 43

overall consumption, 43

self-generation, 40

trends in energy use, 46

between 1947 and 1972, 46

since 1972, 47

variability of energy intensiveness, 45

costs of, 37, 38

decline, 4, 9, 11, 12, 46, 47

foreign policy, 58-61

implications for the United States, 61

growth rate projections, 7

improved efficiency and conservation, 4, 5, 6, 7, 8, 9, 11,

13

investment considerations, 8, 9

capital, 8

competition, 8

Government policy, 8

material and labor, 8

product demand, 8, 27,

projections, 13

two major alternatives, 7

policies that affect, 53-58

Federal regulations, 55

40

financial incentives, 56, 57

Industrial Energy Conservation Program, 58

pricing issues, 53

prices, 1970-81 (fig. 8), 39

projections of the four major sources, 13

sources of, 37

use by source (table 6), 38

industrial investment, 24-26

capital, 24, 66, 89, 112, 118, 141, 142

chemicals industry, 118, 128, 130

factors that influence, 27

housekeeping, 25

management responsibilities, 24, 27

new construction, 25

nonoil-related, 107

paper industry, 73

product shift, 26

refining industry, 104

retrofit of equipment, 25

steel industry, 141, 155

industrial sector, 21-23

definition of, 21

distribution of employment (fig. 6), 23

employment, 22

energy consumption, 43, 44, 45

productivity, 22

output in (fig. 5), 22

overall energy consumption, 43

Industrial Sector Technology Use Model (ISTUM), 107, 108,

130, 131, 134, 135, 165-168

internal rate of return (lRR), 33, 34, 74, 75, 76, 77, 79, 80,

81, 107, 108, 110, 111, 112, 130, 134, 135, 156, 158,

159, 161, 162

Internal Revenue Service, 15, 111

International Energy Agency (IEA), 58, 59, 60

International Trade Commission, 28

investment tax credit (ITC), 57, 110

Iran, 26

Italy, 59, 60

Japan, 59, 60, 61, 144, 145

Korea, 145

legislation:

Crude Oil Windfall Profits Tax Act (WPTA), 54, 56

Economic Recovery Tax Act of 1981 (ERTA), 3, 13, 56,

57, 130, 156, 158, 159

Energy Policy and Conservation Act (EPCA), 53, 58

Energy Tax Act of 1978 (ETA), 56

Environmental Supply and Environmental Coordination

Act (ESECA), 55

Federal Power Act, 56

National Energy Conservation Policy Act of 1978 (NECPA),

58

Natural Gas Policy Act (Public Law 95-621), 7, 54

Omnibus Budget Reconciliation Act of 1981, 55

Powerplant and Industrial Fuel Use Act (FUA), 55

Public Utility Regulatory Policies Act (PURPA), 52, 55, 56

Tax Equity and Fiscal Responsibility Act of 1982, (TEFRA),

57

Marathon Oil Co., 95

Marcor, 107

Mexico, 90, 119, 124

Michigan, 143

Minerals Yearbook, 45
Index ● 1 7 3

Mobil Oil Co., 107, 115

Montgomery Ward, 107

natural gas, decontrol, 54

Netherlands, 61

Oak Ridge National Laboratory, 99

Occupational Safety and Health Administration, 31

Office of Technology Assessment (OTA), 3, 4, 5, 6, 7, 8, 9,

11, 12, 13, 15, 16, 17, 18, 25, 33, 34, 50, 75, 79, 80,

101, 104, 107, 108, 112, 115, 118, 122, 126, 129, 130,

135, 155, 156

Ohio, 143

0il and Gas Journal 105

oil decontrol, 54

OPEC, 12

Pennsylvania, 143

petroleum refining industry:

atmospheric fluidized-bed combusion (AFBC), diagram of

(fig. 25), 103

capital expenditures, 104

capital investment, 89, 104, 105, 107

coal, use, of, 102

conventional firing, 102

corporations earning more than $16 billion in 1981 (table

22), 86

crude-running capacity, 85

decrease in energy use, 4, 11

domination by vertically integrated firms, 11

economics, 88, 89

employment, 88

energy conservation:

air and water cooling of process streams, 99

fractionation efficiency, 101

housekeeping measures, 101

instrumentation and controls, improvement, 100

insulation, improvement, 100

process heat exchange, improvement, 100

process heaters and steam boilers, 99, 101

pump efficiency, 100

recovery from process streams, 100

refinery loss control, 101

steam system improvements, 100

energy intensity projections (fig. 2), 10

energy investments:

alternative energy sources: 106

geothermal energy production, 106

nonoil-related, 107

oil shale mining and processing, 107

petrochemicals, 106

synfuels: liquefaction of coal, 106

energy losses, 97

energy use, 95

fluidized-bed combustion, 102

foreign competition, 89, 90

increased energy efficiency, technologies for, 99, 101

low-level heat:

mechanical recovery of, 104

thermal recovery of, 104

overview, 85

Petroleum Administration for Defense districts, 85

potential for energy saving, 98

premium fuel tax, effect of, 17, 111

product demand, 27, 88

product mix, 86, 87

production costs, 89

production processes:

alkylation, 93

atmospheric distillation, 92

catalytic reforming, 92

coking, 94

fluid catalytic cracking, 92

hydrocracking, 93

hydrotreating, 93

residuum desulfurizing, 93

vacuum distillation, 92

projects to be analyzed for IRR values (table 26), 108

reasons for study, 3

reduction in demand, 11

refineries, kinds of:

complex, 94

hydroskimming, 94

topping, 94

SIC major group 29, 85, 87, 88

structure, 85-86

trends and uncertainties:

changing crude mix, 91

crude oil prices, 91

crude supply, 91

environmental constraints, 92

motor gasoline upgrading, 92

residual fuel oil demand, 91

unleaded gasoline, 90

policy options, 13-18, 75-81, 107-111, 129-135, 156-

ACRS, removal of, 13, 15, 77, 110, 131, 134, 158

chemicals industry, 129

industrial sector, effects on, 18, 77, 131

energy investment tax credits (EITCs), 13, 15, 16, 79,

134, 159

low cost of capital, 13, 17, 80, 112, 135, 161

paper industry, 75

petroleum refining industry, 107

steel industry, 156

62

110

tax on premium fuels, 13, 16, 17, 79, 111, 135, 161

pulp and paper industry:

ACRS, removal of, 79

biomass fuel, 10

capital investment, 66, 80

conservation improvements, 9, 10, 73

corporations earning more than $1 billion in 1981 (table

1 5), 66

economics, 66

employment, 67

energy consumption, 71

energy intensity projections (fig. 2), 10

energy investment tax credits (EITCS), 79

exporting, 67

foreign competition, 9, 28, 67

overview, 65-67
174 ● Industrial Energy Use

premium fuels tax, 16, 79

product demand, 28, 66

product mix, 66, 67, 76

production processes:

bleaching, 69

papermaking, 70

process control, 71, 77

pulping, 67, 68

recovery operations, 71

refining and repulping, 70

projects to be analyzed for IRR values, 74

reasons for study, 3

rise in energy use, 4

SIC major group 26, 65

structure, 65

Union Camp, Savannah, Ga., 66

Reagan administration, 58

Reliance Electric, 107

Resources for the Future (RFF), 59

Saudi Arabia, 90

South Africa, 106

Spain, 61

SRC-11, 106

Standard Industrial Classification (SIC), 21, 65, 85, 87, 115,

139, 165

Standard Oil, 86, 105

steel industry:

ACRS, removal of, 158

capital, cost of, 29, 161

continuous caster, 150, 153, 156, 158

declining domestic sales, 12

decrease in energy use, 5, 12

economics, 141

capital investment, 141, 142

employment, 143

imports and exports, 144

product demand, 144

production costs, 143

profitability, 141

electric arc furnace, 152, 158

energy conservation, 152

energy intensity projection (fig. 2), 10

energy investment tax credits (EITCs), 159, 161

energy use, 149

foreign competition, 28, 144

investment strategy, 155 “, 

major U.S. companies,

overview, 139-145

premium fuels, tax on,

product demand, 28

product mix, 141

production processes:

heat treating, 149

ironmaking, 147

primary finishing:

continuous casting,

ingot casting, 147

raw materials, preparing of, 145

benefication of iron ore, 145

coking, 145

secondary finishing, 149

steelmaking, 147

projects to be analyzed for IRR values (table 57), 158

raw steel production by State, 1980 (table 49), 141

reasons for study, 3

representative energy-related technologies (table 54), 154

SIC major group 33, 139

structure, 139

strategic planning, 26-34

capital, cost and size of, 28

competition, 28

elements of, 31

financial analysis, 32

investment decisions, 27, 155

investment levels, 32

levels of decisionmaking, 30

material and labor, costs of, 29

product demand, 27

sensitivity analysis, 34

time considerations, 31

Sweden, 59, 60, 61

shipment by, 140

17, 161

147

United Kingdom, 59, 60, 61

U.S. Constitution, 56

U.S. Supreme Court, 55, 56

U. S. S. R., 119, 124

Venezuela, 90

West Germany, 59, 60, 61, 145

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