CONTROLLING ACID DEPOSITION

BY SEASONAL GAS SUBSTITUTION

IN COAL- AND OIL-FIRED POWER PLANTS

Gary Galeucia

MIT Energy Laboratory Report No. MIT-EL 86-004

June 1986

Controlling Acid Deposition By Seasonal Gas SubstitutionIn Coal- And Oil-Fired Power Plants

by

Gary B. Galeucia

Submitted to the Alfred P. Sloan School of Management on May 16, 1986, in partialfulfillment of the requirements for the Degree of Master of Science in Management.

Abstract

Acid deposition, primarily the result of sulfur emissions due to fossil fuelcombustion, is a serious environmental problem. Resolving the problem will imposecosts measuring in the billions of dollars. Based on evidence that the rate of wetsulfate deposition in eastern North America is higher in the summer half of the yearthan in the winter half of the year, seasonal control of emissions is proposed as ameans of minimizing acid deposition control costs. This paper evaluates the proposalthat natural gas be substituted for coal and oil in electric power plants during Aprilthrough September.

A model is presented that simulates the substitution of natural gas for coal and oilin power plants in the eastern 31 state region so as to minimize total costs withrespect to deposition reductions at an Adirondack receptor. The results of the modelshow: 1) changes in fuel consumption as a result of substitution, 2) the increasedeffectiveness of seasonal versus year-round controls, and 3) the costs of achievingvarious levels of deposition reduction at an Adirondack receptor.

The costs of seasonal gas substitution, in terms of emission and depositionreductions, are compared to cost estimates for other proposed control methods andstrategies. An example is given that calculates the cost with respect to deposition of asource-oriented control strategy, so that the cost of seasonal gas substitution can befairly compared with it. The conclusion of these cost comparisons is that seasonal gassubstitution is cost-competitive with some other control methods, at least in somestates.

Thesis Supervisor: Dr. Henry D. Jacoby, Professor of Management

Acknowledgement: This research was performed at the MIT Energy Laboratory withthe support of the Electric Utility Program and under the supervision of Prof. JamesA. Fay and Dr. Dan S. Golomb. Their assistance and guidance is gratefullyacknowledged.

Table of ContentsPage

Title Page I

Abstract 2

I. Introduction

11. Acid Deposition S

III. The Old And New Of Acid Rain Policy 10

IV. Seasonal Gas Substitution 13

V. The Seasonal Gas Substitution Model 16

VI. Results Of The Model 23

VII. Gas Supply For Substitution 29

VIII. Other Costs 31

IX. Conclusions 32

References 33

Tables 35

Figures 46

Appendix A 61

Appendix B 74

Appendix C 89

I. INTRODUCTION

Until recently, air pollution was considered a local problem. Now it is known that

winds can carry air pollutants hundreds of miles from their points of origin.Transported air pollutants can damage aquatic ecosystems, crops, manmade materials,

forests, and human health. The process by which air pollutants damage these

resources is referred to as "acid rain". The term acid rain is used to describe the

complex chemical changes that result from the presence of oxides of sulfur, oxides ofnitrogen, and other compounds in the air that may lead to increased acidity in

precipitation, in ground and surface waters, and in soil. A more comprehensive and

accurate term is acid deposition, since the transfer of acid material from the

atmosphere to the biosphere may occur not only in the aqueous phase (rain, snow,

fog, etc.) but also as dry deposition, in which gaseous or particulate material is

adsorbed by the ground, vegetation, or surface water.

Precipitation acidity' considerably below pH 5.6 has been observed in the eastern

United States and Canada, as well as many other areas in the world. Increased acidity

in precipitation and dry deposition of acidic material may increase the acidity of

surface waters, with consequent adverse impacts on fish and other aquatic life.

Increased acidity may also affect vegetation, such as forests or crops, directly or

indirectly through changes in the soil.It has also been claimed that increased acidity of surface water could adversely

impact human health by mobilizing toxic ions such as lead and copper into drinking

water. However, there appears to be little reason to believe that such health effects

*Acidity is usually measured on a logarithmic scale called pH. PH is defined as the negative

logarithm of the hydrogen ion concentration, which is measured in molar equivalents per liter. A

neutral solution has a pH - 7.0, and the sale ranges from pH - 0 (strong wid) to pH - 14 (strong

alkali). Carbon dioxide dissolves in water to form a weak acid; the pH for pure water in

equilibrium with C02 is 5.6.

4

will become a significant public policy issue; the main concerns about the effects of

acid deposition seem to be the adverse consequences for aquatic and terrestrial

ecological systems.

Sulfur dioxide (SO2) is the major chemical compound responsible for precipitation

acidity; it is produced largely as the result of the combustion of fossil fuels. i.e. coal

and petroleum products. S02, along with other chemical compounds, is oxidized into

acid compounds primarily in the atmosphere. Precipitation and gravity cause these

acid compounds to be deposited on the Earth's surface, sometimes at great distances

from the sources of the original pollutants. The sources of these pollutants include

electric utilities, automobiles, and smeters.

These pollution sources exist as the result of economic activity. Consequently,

reducing pollutant emissions is not vithout cost. Economic theory tells us that

pollutant emissions should be reduced to the point vhere the marginal cost of

reducing the emissions equals the marginal benefit derived from the lover emission

level. This simple principle is greatly complicated by uncertainties regarding the

magnitude of the costs and benefits of lover emission levels. It is complicated further

because these pollutants cross political boundaries to damage areas far from the

sources of the economic activity that generated the emissions. Consequently, political

realities and questions of equity are part of the problem.

What is known of the acid rain problem is that there are identifiable and

quantifiable sources of emissions. and that there are areas suffering varying degrees

of damage due, at least in part to these emissions.

Formulating a policy that balances costs and benefits, let alone political and equity

concerns, is a very complex and continuing task. Acid rain policy has evolved rapidly

in the 1980's. It has moved away from legislation calling for broad-based emissions

reductions toward more efficient policies that recognize the sial relationshi

between emissions sources and the areas sensitive to the deposition caused by the

emissions.

This paper presents evidence that acid rain policy should step beyond the

recognition of these spatial relationships tovard a recognition of mSoral

relationshins between emissions and deposition. What is meant by temporal

relationships is that there are seasonal variations in deposition rates for a relativelyconstant rate of emissions. Just as it is more efficient to seek relatively greater control

of emissions from sources that are relatively close to sensitive areas, it is also more

5

efficient to exert relatively greater control of emissions when the deposition rate as aresult of the emissions is highest.

As one means of controlling emissions when deposition rates are highest, this

paper investigates the impacts of substituting natural as for coal and oil in electricutility boilers during April through September. A seasonal gas substitution model has

been developed to quantify the costs of this strategy for various levels of depositionreduction. The model is static in that it is run for a single year, 1983; this means that

actual price and quantity daa for coal, oil, and gas comes from that year. The model is

concerned with emissions of sulfur dioxide (S02). from electric utilities in the 31

eastern states and the District of Columbia (DC). as veil as the resulting deoosition of

sulfate (S04) at a sinagle recentor in the Adirondack Mountains of New York.

The paper starts by describing hov acid deposition is formed as a result of

emissions from fossil fuel combustion. This is followed by a presentation of the

finding that deposition rates are seasonally variable for a relatively constant rate of

emissions. Next. the policy dilemma that acid rain creates is briefly described and is

followed by a review of hov acid rain policy has evolved from source-oriented to

receptor-oriented control strategies. By combining the idea of receptor-oriented or

targeted strategies with the evidence of seasonal variation in deposition rates, a new

type of targeted control strategy is created. The original targeted strategy related

emission sources and deposition receptors spatially. The new targeted strategy. in

addition to being spatially targeted. is targeted temporally in order to take advantage

of seasonal variations in deposition rates.

To utiliz this new strategy, seasonal substitution of natural gas for coal and oil is

proposed. A model is presented that simulates the substitution of natural gas for coal

and oil so as to minimize the cost of achieving deposition reductions. The results of the

model show: 1) the changes in fuel consumption as a result of substitution, 2) the

increased effectiveness of seasonal versus annual gas substitution, and 3) the costs of

seasonal gas substitution. The costs, in terms of emission and deposition reductions

achieved, are compared to cost estimates for other proposed control methods and

strategies. An example is given that calculates the cost with respect to deposition of a

source-oriented strategy, so that the cost of seasonal gas substitution can be fairly

compared with it. The conclusion of these cost comparisons is that seasonal gas

substitution is cost-competitive with these control strategies. at least in some states.

The model does not consider two important factors: 1) the availability of gas supply,

6

and 2) the capital cost for seasonal gas substitution. These factors are discussed

briefly, with the conclusions being that: 1) there may be restrictive limits to gas

supply and deliverability, and 2) capital costs for seasonal gas substitution are

probably very low relative to capital-intensive control methods such as flue gas

desulfurization. The paper ends by restating the conclusions made throughout.

7

II. ACID DEPOSITION

II. 1. How Acid Deposition is Formed

The dominant precursors of acid deposition are sulfur dioxide (S02) and nitrogen

oxides (NOx). The sulfur oxide orecursors. the focus of this oer. are primarily

oroduced by burning sulfur-contining fuels (e.g. coal and oil). After release into the

atmosphere, the sulfur oxides (SOx) will oxidize and can form acids when combined

with water. The particular sequence of changes a pollutant undergoes depends on the

physical and chemical characteristics of the air mass in which it travels. These

characteristics (e.g. initial concentrations of pollutants, wind speed, air turbulence.

sunlight intensity, temperature, rainfall frequency) are highly variable, which iswhy scientists cannot precisely characterize the detailed path of a pollutant from its"source" to its "sink".

To become acid. emitted S02 must be oxidized either: 1) in the gas phase. 2) after

absorptions into water droplets, or 3) after dry deposition on the ground. The

transformed pollutant can be deposited in wet form (as rain, snow, or fog), or in dry

form (due to particles containing the pollutant settling out of the atmosphere). The

amount of time a pollutant remains in the atmosphere. and therefore how far it istransported, depends significantly on its chemical form. For example, S02 gas is

dry-deposited at a greater rate than sulfate particles (products of oxidation). If S02 is

quickly converted to sulfate (SO4), a smaller fraction of emitted sulfur compounds will

be deposited locally. in the absence of precipitation. The rate of conversion from S02

to S04 depends on the chemical composition of the atmosphere. The frequency and

intensity of precipitation controls the rate of wet sulfate deposition.

Dry deposition is believed to occur at a fairly constant rate over time (i.e. a certain

percentage of the S02 in the air is dry-deposited each hour). with some variability

induced by local conditions. Wet deposition is episodic, and the amount deposited

varies considerably even within a rainfall event. For example, a short rain may

deposit heavy doses if pollutants have been forming and accumulating in the local

atmosphere over time. Without sufficient time for pollutant concentrations to

accumulate, a second rainfall event in quick succession may result in little new acid

deposition.

In general, areas close to emission sources receive significant proportions of their

pollution from steady dry deposition of S02. Areas remote from emission sources

receive a greater share of total deposition from wet deposition, since much of the S02

8

available for dry deposition has been depleted or converted to a wet form. Deosition

in this paper refers to wet sulfate (S04) deposition. Air over any particular area will

carry some residual pollution from distant areas, as well as infusions from nearer

sources. The continuous replenishment and depletion of pollutants along the path of

the air mass, makes precise source-receptor relationships difficult to determine.

II. 2. Seasonal Variation In Deposition Rates

Analysis of several years of precipitation chemistry data has established that wet

sulfate deposition rates in the northeastern U.S. and southeastern Canada are higher

in summer months (April-September) than in winter months (October-March)(Boversox et al., 1985; Golomb et al., 1985). Figure 1 shows the seasonal patterns of

sulfate deposition over three years at four receptors. Seasonal differences in sulfatedeposition can be clearly seen.

The exact causes of the differences in seasonal deposition patterns are not

perfectly understood; they are probably linked to seasonal storm tracks. Raynor and

Hayes (1982) observed that sulfate (and hydrogen) ion concentrations are highest in

precipitation associated with cold fronts and squall lines, which occur most frequently

in summer months. These higher concentrations are apparently due to the fasterconversion of the emitted sulfur dioxide into sulfate in summer. The quantity of

sulfate being deposited in a storm is a function of the previous trajectory of the warm,

moist air mass and the amount of precipitation in the storm. In winter, more of theunoxidized S02 is blown offshore and hence does not fall on the land as acid wet

sulfate.

Although the chain of processes from emissons of pollutants to eventual deposition

of acid and acid-producing substances is complex and not fully understood, all

evidence points to a relationship between emissions and deposition. Current scientific

understanding suggests that reducing sulfur dioxide emissions would reduce the

deposition of sulfates. The greatest potential for reducing acid deposition in the

eastern U.S. comes from the reduction of S02 emissions.

g

III. THE OLD AND NEW OF ACID RAIN POLICY

III. 1. The Policy Dilemma

Fossil fuels are vital to the U.S. economy's production of goods and services.

Hovever, burning these fuels also produces large quantities of pollutnts--substancesthat. once released into the atmosphere, can damage natural resources, health.

agricultural crops, manmad materials, and visibility. Consequently, our Nation's lays

and oolicies must strike a balance between the economic benefits and the risks of

fosil fuel combustion.Recognition of the risks of damage has led some individuals and groups to call on

the federal government to control pollutant emissions, most specifically sulfur dioxide,

more stringently than current as require. Others, pointing to uncertainties aboutthe causes and consequences of transported pollutants, are concerned that more

stringent emission controls may be mandated prematurely or at too great a cost.

Transported air pollutants also raise significant equity issues. The individuals

served by the activities which generate emissions can be different from those vho

incur resource damage. Similarly, particular groups and regions might bear the costs

of controlling emissions, while others receive the benefits.

Transported air pollutants have become an issue for potential federal action

because they cross political boundaries. The current federal system of pollution

control relies on state-level abatement programs to limit pollution levels in individual

states. (National emission standards for nev sources of pollution--New Source

Performance Standards--are the exception to this.) Hovever. no effective means of

controlling extensive pollution transport across state lines currently exists.

Transported pollutants also cross the international boundary into and from Canada.

Article 1, Section 10 of the Constitution prohibits states from entering into agreements

vith foreign nations without the consent of Congress: thus. any pollution control

agreements vith CaLnad would require federal action.

Existing federal air pollution control mechanism are governed primarily by theClean Air Act. To date, control strategies developed under the Act have ocused on

controlling local ambient air concentrations. The effectiveness of this approach for

controlling transported air pollutants is questionable. For example, the so called "tall

stacks" approach has been used by utiditis to meet local ambient standards as specified

10

by the Clean Air Act. By releasing emissions far enough above the ground. the

pollutants are carried away from the local area, and Clean Air Act compliance is

attained. The pollutants are transported away from the local area, but are not reduced

in total. For any acid rain policy to be effective it must specifically control emissions

that can be transported through the atmosphere to receptors with resources sensitive

to acidity.

III. 2. Source-Oriented Control Strategies

A dynamic linkage exists between acid rain policy formulation and the control

strategies that will be called for when policy is formulated. To illustrate, in the first

years of this decade the emphasis of policy was on controlling S02 emissions. The

early theory was simply that emissions caused acid rain. Therefore, most legislative

proposals of the early 1980's called for broad-based emission reductions and distributed

the reductions proportionally throughout the eastern 31 states. These proposals are

known as source-oriented control strateies because they are concerned only with

emissions at the source and do not consider source proximity to adversely impacted

areas.

The emphasis of recent policy has evolved as more has been learned about acid

rain. What has been learned is that: "First, ...in the northeastern U.S. and southeastern

Canada the rainfall is more acidic than rainfall elsewhere in the country; secondly,

this same region is located close to those areas in the U.S. and Canada which have the

greatest density of sulfur oxides emissions. Thirdly, there are acidified clear lakes

-lakes not directly affected by man's activities- in areas that receive heavy acid

deposition, and in contrast there are few affected lakes where deposition is light. Most

scientists active in the field believe that acidic deposition has been a major

contributor to the acidification of these lakes. But not all areas in the eastern US. are

sensitive to acid rain. The areas at risk are those which receive the deposition and

have limited buffering capacity" (Eltins, 1985).

Notice that Mr. Elkins', who is Director, Office of Program Development, Office of

Air and Radiation, U.S. EPA. emphasis is on acid deoosition rather than emissions. the

effects of deposition, and the sensitivity to acid deosition. Control strategies that are

concerned with the proximity of emission sources to adversely impacted areas are

known as targeted or receptor-oriented strateies. Mr. Elkins is telling us something

about the direction of acid rain policy, namely that when EPA is ready to make an acid

11

rain control policy recommendation, targeted control strategies are likely to be part of

that policy.

This emphasis on acid deposition and targeted control strategies is manifesting

iself in EPA's research agenda. "We are now greatly expanding our research efforts to

deal with the gaps in our knowledge, and to put our country in a better position to

recommend targeted and efficient policies" (Elkins. 1985). EPA's research mission is

explicitly directed at economically efficient, targeted control policy, with particular

attention tovard deposition and sensitivity to deposition. The task at had is to identify

emission control methods that mesh with this olic orientation.

1II1.3. Targeted Control Strategies

Recent work in atmospheric modeling has brought new moaning to the idea of

targeted strategy. The traditional definition says that source/receptor pollutant

transport relationships exist that make it more efficient to identify areas sensitive todeposition and then use those transport relationships to identify the primary sources

that contribute to deposition in the sensitive area. This definition could be

characterized a being spatially targeted.

The nev, added dimension to the idea of targeted strategy can be characterized as

being temporally targeted. Differences in seasonal rates of sulfate desition create

the ogoortunity for seasonal control of sulfur emissions as a more effective means ofreducing annual amounts of sulfate deoosition. By encouraging or requiring S02emissions to be curtailed in the summer half of the year, there is a larger reduction of

annual deposition per ton of S02 removed than if the same quantity were removed

year-round. Therefore, it may prove to be less expensive to reduce deposition by

controlling emissions only in the summer half of the year, rather than year-round.In other words, there will be a larger reduction in annual deposition per dollar spentcontrolling emissions during the summer half of the year. than if the same number of

dollars were spent controlling emissions year-round.

12

IV. SEASONAL GAS SUBSTITUTION

IV. 1. Why Natural Gas?

Seasonal control of emissions can be accomplished by substituting lower sulfur

fuels for higher sulfur fuels during periods with higher deposition rates (i.e.

April-September). This naer evaluates the annual vet sulfate deoosition reduction

that would result from substituting natural gas for coal and residual oil in utility

boilers during April through SeDtember.

Natural gas was chosen as a substitute fuel because it produces virtually no sulfur

dioxide when burned. Seasonal gas substitution allows a continued utilization of

existing coal resources in the winter half (October -March) of the year and increased

utilization of natural gas during the summer half (April-September) of the year.While the fuel price differential between gas and coal may be substantial, the capital

required for retrofit gas burner installation is expected to be quite low. Thus. the

comparative annual cost to a achieve a given target deposition reduction -- by seasonal

fuel switching to natural gas vs. year-round scrubber operation-- may very well turn

out to be in favor of gas subsitution. This is precisely the goal of the aper: estimating

the costs of seasonal gas substitution in sulfur emitting power plants in absolute units

as well as relative to the costs that would result if these plants installed emission

control devices (e.g. scrubbers) to achieve the same amount of sulfate deposition at an

environmentally sensitive receptor.Imaortant factors to be considered in seasonal natural gas substitution strategies

include:

1. In the summer months there is currently excess capacity in the natural gas

distribution system. According to Wilkinson (1984) only 78% of the pipeline capacity

is used in the summer months. and in some regions as little as 51%. Summer gas

supply and deliverability will be discussed later in this paper.

2. Seasonal gas substitution could be implemented rapidly relative to the period needed

to install scrubbers or develop "clean burning" technology for a large number ofplants. The quick implementation schedule would allay fears that further delays in

reducing acid deposition may cause irreparable damage to the environment.

Anticiated benefits beyond lower sulfate deposition, from seasonal gas substitution

include:

1. Improved local air quality with lower ambient air concentrations of S02 and

13

particulates.

2. Improved visibility.

3. Increased potential for achieving attainment in non-attainment areas.

4. Decreased dependence upon imported oil.

5. Reduced sensitivity to fuel supply disruptions e.g. coal strikes or oil embargos.

6. Increased reliance on domestic energy resources.

7. Decreased consumption of limestone and other sulfur-capture materials used in

emission controls.

8. Decreased land requirements and cost for scrubber sludge and flyash disposal.

IV. 2. Natural Gas as a Boiler Fuel

Natural gas has never been a favorite utility boiler fuel in most parts of theeastern U.S. Combustion of natural gas produces more than 10% of total btu output by

electric utilities in only seven of the eastern 31 states (EIA, 1984a). The primary

reason for this pattern is that natural gas is an expensive boiler fuel relative to coal.

This reason is certainly a viable one. There are two less viable reasons why natural

gas may continue to be disfavored as a boiler fuel.

The first concerns the perception by some that gas reserves are imminently

exhaustible. A reasonable range for the amount of the remaining conventional

natural gas in the U.S. Lower 48 that is recoverable under present and easily

forseeable technological and economic conditions is 430 to 900 trillion cubic feet (TCF)

as of December 1982 (TA, 1985). (This resource estimate does not include Alaskan,

Canadian, Mexican, or unconventional resources.) At a consumption rate of 20 TCF per

year., slightly higher than present consumption, the resource estimated above will last

21 to 4 vears. The best explanation for this misperception of imminent exhaustibility

is that in the 1970's gas demand exceeded gas supply as a result of price controls on

natural gas. The market disequilibrium created the image that we were running out

sooner rather than later.

This first misperception led policymakers to restrict gas use. which in turn has

created a second misperception, namely that gas use is restricted. Restrictions on gas

use in electric utility power plants were enacted when the federal Powerplant and

Industrial Fuel Use Act (PIFUA) of 1978 was signed into law on November 9, 1978.

However, PIFUA restrictions were sharply repealed by the Omnibus Budget

Reconciliation Act signed into law on August 13, 1981. Since the 1981 amendment, the

14

PIFUA restrictions on natural as use do not aoolv to "eii n" ovwer Dlnts at all. A

pover plant is "existing" if it vas in service or under construction prior to November9. 1978 (Bardin., 1985). Furthermore, exemptions are available to post-1978 powver

plants. Pre-1978 pover plants contribute the bulk of total S02 emissions because a)

most generating units vere built prior to 1978. and b) older plants ae subject to less

restrictive pollution control regultions.

15

V. THE SEASONAL GAS SUBSTITUTION MODEL

V. 1. General Description

The analysis in this paper relies upon a model developed to evaluate the annual wet

sulfate deposition reduction that would result from substituting natural gas for coal

and residual oil in utility boilers during April through September. The model does not

consider load dispatching as a means of reducing emissions, i.e. generating more

power from an existing gas-fired plant or turbine that has excess capacity in summer

and wheeling that electricity, rather than seasonally substituting gas in coal- or

oil-fired plants. The inclusion of load dispatching strategies is left for future analyses.

The seasonal gas substitution model estimates the corresonding annual control costs

and fuel substitution amounts for any level of deoosition reduction.

The model's S02 emission sources are 387 utility plants burning coal or residual oil

as a primary boiler fuel in the eastern 31 states and D.C. The criteria for including a

plant in the model were that it had to have a rated capacity of 50 megawatts or larger,

and at least 10% of total btus had to be generated from either coal or oil. The names,

locations, and fuel characteristics of these plants are listed in Appendix A. Refer to

the guide at the beginning of the Appendix for column definitions.

The atmospheric transport model, known as the MIT acid deposition model (Fay et

al.. 1985; Golomb et al.. 1985; Kumar. 1985). is an adaptation of the Fay-Rosenzweig

climatological long-range transport model originally developed for estimating annual

average S02 concentrations in the U.S. (Fay et al., 1980). It is empirically determined

in that the model parameters are derived by comparison with airborne concentrations

and wet deposition measurements.

Because the physical and chemical processes that pollutants undergo is highly

variable, the accuracy of long range atmospheric transport models is frequently

questioned. Even among those scientists that develop them there is considerable

variability in the estimation of the transfer coefficients. In spite of this, the MIT aciddeposition model has been well received by those knowledgeable in the field.

Therefore, it is justifiably appropriate to use for this analysis.

The MIT acid deposition model derives transfer coefficients which estimate the

quantity of deposition at a receptor per unit of emission at a source. Transfercoefficients have been derived for both an annual and a seasonal (summer/winter)

16

basis. The seasonal gas subsitution model uses the summer transfer coefficients to

relate emissions reductions, as a result of substituting natural gas for coal and oil, to

deposition reductions at an Adirondack receptor. Table 1 lists the values of the

seasonal and annual transfer coefficients between the 31 eastern states plus D.C. and

an Adirondack receptor. Table 1 shows that the summer transfer coefficients are on

average nearly twice as large as the winter ones. In other words, on average. summer

emissions from the 31 eastern states cause nearly twice the deoosition at an

Adirondack receptor as an equal Ouantity of winter emissions.

The transfer coefficient Tij is the ratio of the amount of deposition at receptor j

contributed by source i divided by the emission amount Qi from source i. The total

deposition Dj at receptor j equals the sum of the products of the transfer coefficient Tij

times the emission Qi :

Dj - i Ti (1)

When seasonal transfer coefficients are used, the annual deposition is obtained by

summing seperately the product of the transfer coefficient and emissions for summer

(April- September) and winter (March-October):

(Dj)an - i (Tij Qi)vi + 7i (Tij Qi)su (2)

In the seasonal gas substitution model the emission-deposition relationship takes

the functional form,

(Dj)su -'i (Tij Qi)su(3)

where the transfer coefficients (Tij)su are constants, the summer deposition (Di)su is

the independent variable, and summer emissions (Q0 i)su are dependent variables. By

selecting a desired summer deposition quantity, the required level of emissions is

determined, which in turn determines the amount of gas substitution necessary to

achieve the desired deposition quantity for the April-September period.

The same transfer coefficient is used for all emission sources within a state. This is

valid for states distant from the receptor, but may be questionable for states close to

the Adirondacks. For instance, New York state has emission sources both to the west

and south of the Adirondacks. The higher the variation in direction and range from

the sources within a state to the receptor, the less appropriate it is to use a singletransfer coefficient for all sources within that state. The use of single transfer

17

coefficients within a state was chosen for this analysis because: ) the bulk ofdeposition at an Adirondack receptor comes from distant states, and 2) it simplifies the

presentation of the analysis. The use of multiple transfer coefficients within a state is

left for future analysis.

V. 2. Functional Form

The model is in fact a linear program (LP) which seeks to minimize the

incremental spending on natural gas as a result of substitution. For each electric

power plant i. there is a cost differential between a given btu quantity of gas and coal

and/or gas and oil. Multiplying this cost differential by the quantity of gas substituted

equals the incremental spending on fuel by the power plant.

Minimization of the incremental spending on natural gas is performed subject to

two types of constraints. The first constraint specifies the desired level of deposition

and has already been described above by Eq. (3). The second type of constraint

requires that the same quantity of btus are produced by each power plant under the

gas substitution strategy as were actually produced when no substitution occured. The

btu output of each source is equal to the btu content of the coal, oil, or gas multiplied

by the quantity of coal. oil. or gas consumed. Actual btu output was determined from

fuel heat content and consumption data (EIA, 19684).

The LP model in its functional form seeks to minimize the sum of the products:

MIN i Fi Gi (4)

subject to:

Dsu(target) = 2 i (Tij Qi)su (5)

(btu)i - HCi Ci + H i + Hg Gi (6)

where the symbols are:

(btu)i - seasonal (April-September) total btu output for power plant i.

Ci - seasonal quantity of coal burned by power plant i,

Dsu - target seasonal deposition quantity for a specified receptor,

Fi - fuel cost differential between gas and coal and/or gas and oil at power

plant i.

Gi - seasonal quantity of natural gas substituted for coal and/or oil at

18

power plant i.

HCi - heat content of coal consumed by power plant i,

Hg heat content of natural gas (one cubic foot- 1000 btu assumed for all

power plants).

H°i- heat content of oil consumed by power plant i.

The Adirondacks receptor is used in the model because it is environmentally

sensitive and centrally located with respect to other environmentally sensitive areas

in the U.S. and Canada. By adding additional deposition constraints. the model could be

made to consider more than one receptor. This would require the use of a unique set of

transfer coefficients for each additional receptor. For simplicity of presentation, the

model has been limited to a single receptor.

However, it is possible to speculate as to the effect of multple receptors. For

instance, if a Southern Applachian receptor were used in addition to an Adirondack

receptor, more substitution would occur in southern states. Increased substitution in

southern states in order to reduce Southern Applachian deposition would also reduce

Adirondacks deposition by a small amount. As a result. less substitution would be

required in northern states in order to achieve the same deposition reduction in theAdirondacks. Thus, there is a spillover effect when multiple receptors are used. The

inclusion of multiple receptors is left for future analyses.

V. 3. Emissions

Most legislative proposals to date have focused on a 31 state region encompassing

the states east of, and bordering on, the Mississippi River. Of the 26 to 27 million tons

of sulfur dioxide emitted in the continental United States in 1980, about 22 million tons

came from this 31 state region. The model uses 22 million tons as the base level when

calculating percentage reductions in emissions. This paper calculates that the electric

utilities included in this analysis we resoonsible for aOproximatelv 16 million tons of

S02 emissions (Table 2), or 73% of the 22 million ton total (assuming 1983 total

emissions were equal to those in 1980).

Table 2 lists 1983 emissions of S02 attributable to the burning of coal and residual

oil in electric power plant boilers in the 31 easternmost states and DC. i.e. the power

plants in Appendix A. Emissions were calculated from annual electric utility coal and

oil consumption data (EIA, 1984a) neglecting any sulfur removal processes which may

19

have been used in that year. These emissions are used by the model for calculating

deposition at an Adirondack receptor,

Since in most states sulfur emission rates are fairly constant throughout the year(NAPAP, 1985), the model assumes that fuel consumption during April through

September is equal to one-half of annual fuel consumption. Therefore. emissions

during April through September are assumed to equal to one-half of annual emissions.

To assess this assumption, net generation data (trillion kilowatthours of output) was

compiled for coal-fired plants in the eastern 31 state region (Figure 2). Figure 2 shows

that monthly variations in net generation do occur. However, if the monthly figuresare summed for the periods April-September and October-March, the former period

accounts for 51% of annual net generation. From this, it can be safely inferred that

emissions during April through September are equal to one-half of annual emissions

in the eastern 31 state region. This does not necessarily hold true for individual states:

future analyses may wish to account for state-level variations in seasonal fuel

consumption and S02 emissions.

V.4. Deposition

The amount of wet sulfate deposition at a receptor can be linearly related to the

amounts of sulfur emissions from sources using transfer coefficients. These transfer

coefficients, and the MIT acid deposition model from which they were derived, were

discussed earlier. Total annual wet sulfate deposition at an Adirondack receptor was

estimated to be 27.5 kilograms sulfate per hectare per year (kg S04 haly - l)(Fay et al.,

1985). This figure is used as the base for calculating percentage reductions in total

annual wet sulfate deposition at an Adirondack receptor. Table 3 contains the summer

and annual deposition amounts. at an Adirondack receptor, which were calculated to

have been contributed by the sources included in this analysis. (Note: It is necessary

to multiply the figures in Table 3 by a factor of three in order to convert sulfur (S) to

sulfate (S04). S04 is three times the molecular weight of S.) This aPer calculates that

electric utilities in the eastern 31 states contribute 142 k S04 h - annually to anAdirondack receptor. or 52% of the 275 k S04 ha 1 total. Of this 14.2 kg annual total,11.2 kg or 79% is calculated to be deposited between April and October. Summer

deposition is disproportionately higher because the summer transfer coefficients are

nearly twice as large on average as winter ones (see Table 1).

20

V. 5. Calculating the Cost of Seasonal Gas Substitution

Incremental spending on natural gas by utilities is assumed to equal the

incremental quantity of natural gas consumed at a power plant as a result ofsubstitution, multiplied by the cost differential between gas and coal, or gas and oil, at

that plant, summed for all such power plants. It should be noted that the costs derived

here for seasonal gas substitution are solely the result of the price differentialsbetween gas and coal or oil. Preliminary estimates of the incremental capital and

operating costs associated with seasonal gas substitution indicate that the fuel price

differential is by far the major cost. Because capital and operating costs for seasonal

gas substitution are uncertain and relatively small, this paper will leave the inclusionof these factors to future analyses.

The coal and oil prices used in the analysis are actual average prices per million

btu paid by the power plants in 1983 (EIA, 1984a). These prices are listed in Appendix

A. columns 5 and 10. The gas prices used are the state-average cost per million btu

paid by electric utilities in that state (Table 4). If no electric utility burned gas in astate, then the average price paid by industrial consumers was used (EIA, 1984b). From

the gas prices listed in Table 4, it can be seen that prices vary significantly from state

to state. Using the data in Appendix A and Table 4, the plant-level price differentials

have been calculated, and are shown in Appendix B.

The actual coal and oil prices, as well as the state-average gas prices, are not

necessarily indicative of present and future prices, and therefore of pricedifferentials, for these fuels. A fall in oil prices, which are determined in the world

market, could be expected to produce a decrease in natural gas prices because the two

fuels are to some extent substitutes. Coal prices are affected to a greater extent by

production costs, and to a lesser extent by the prices of oil and gas because these fuels

are not close substitutes. Hence, a fall in oil prices and a subsequent fall in gas pricesshould be accompanied by a relatively smaller decrease in coal prices. The result is

that in a period of lower oil prices, a smaller price differential between gas and coal

could be expected.

To test this hypothesis informally, it is useful to look at gas. coal, and oil prices and

price differentials over time (Figure 3). (Prices have been taken from EIA, 1985 and

are adjusted to 1983 dollars using the U.S. Bureau of Labor Statistics producer price

index for crude energy materials.) During the period 1983 to 1985, the price of oil rose

fairly steadily throughout 1983 and into mid-1984, and then declined during the

21

remainder of 1984 and throughout 1985. The price of gas followed a similar pattern to

that of oil, but the rise and fall are less pronounced. The price of coal remained

relatively stable throughout the period. So, the hypothesis is substantiated, at least

during this short period.The implications of this for fuel price differentials are shown in Figures 4a and b.

Figure 4a shows that the gas/coal price differential rose and fell with the same pattern

as the price of gas itself. Thus, the direction of the price of gas reveals the direction of

the gas/coal price differential. In the current environment of lover as prices.

seasonal sa substitution for coal is eausllr. if not more. econoaical than it was in

19B3.

In regard to the gas/oil price differential, Figure 4b shows that seasonal gas

substitution for oil becomes more attractive when the oil price is rising and less

attractive when it falls. In the current environment of lover oil prices, the gas/oil

price differential is smaller, but it is still negative. Hence, there is still an economic

incentive for gas substitution.

The historic prices are used here as a first approximation and illustration of the

fuel price differential trends in current years. More detailed explanations and

forecasts of fuel prices are left to future analyses.

V. 6. Using the Seasonal Gas Substitution Model

The model, described earlier, is a linear program which seeks to minimize the

incremental spending on natural gas subject to constraints on deposition and btu

output. The model is exercised by selecting various target levels of deposition

reduction and then solving the model. The model selects a oover lant to use seasonal

m substitution based on: 1) the rate at vhich it contributes to deosition. and 2) thefuel orice differential it faces. The rate at which a plant contributes to deposition is afunction of the sulfur content of the fuel per million btu and the transfer coefficient

between the power plant and the receptor. Power plants where these two factors are

relatively lrge will be selected first for gas substitution. Similarly. power plants that

have smaller fuel price differentials will be selected first.

Beyond the cost of seasonal gas substitution, the model shows which plants switch,

how much gas consumption increases, and how much coal and oil consumption

decrease; from which the effect on emissions can be calculated.

22

VI. RESULTS OFTHE MODEL

Appendix C is a sequential list of the 387 plants as they enter the solution.

Plant-level and cumulative data are also provided. To use the Appendix, look in column

14 for the desired percentage reduction in deposition. This and all preceding plants

have been selected for gas substitution. Reading horizontally, columns 5 and 7

indicate the cumulative amount of coal and oil displaced, column 10 indicates the

amount of gas substituted, column 11 indicates the sulfur emission reduction, and

column 17 indicates the total cost. Refer to the guide at the beginning of the Appendix

for definitions of all the columns.

Each time the model was exercised, total annual deposition was reduced in 5%

increments. Corresponding levels of gas substitution, coal and oil displacement,

emission reductions, and resultant cost were calculated for each 5% decrement. These

results are summarized in Table 5. For example. in the case of a 20% sulfate deposition

reduction, 909 billion cubic feet (bcf) of natural gas are substituted for 53 million tons

of coal and 87 million barrels of oil at a cost of $2.929 billion (1983$). with a resulting

emission reduction of 2.9 million tons of S02. For a 30% sulfate deposition reduction,

these quantities increase to 1440 bcf of gas being substituted for 97 million tons of coal

and 94 million barrels of oil at a cost of $5.858 billion, with a resulting emission

reduction of 4.8 million tons of SO2.

From this data, the total, average, and marginal cost curves for seasonal gas

substitution with respect to deposition can be derived (Figures 5. 6, and 7). Total cost

starts at negative $0.204 billion for a 5% deposition reduction, and rises nonlinearly to

$10.931 billion for a 40% deoosition reduction. Cost is initially negative because a

negative price differential exists between gas and oil at some plants. Because its

objective is to minimize cost, the seasonal gas substitution model chooses the plants

with negative price differentials first. This condition raises the question of why these

plants do not convert from oil to gas regardless of pollution concerns. Some oil-fired

plants have converted since 1983, e.g. Boston Edison's Mystic #7 burns gas seasonally.

The others have not for reasons that the model fails to consider. Perhaps gas supply is

unavailable or insufficient, or perhaps utility management has no incentive to

convert given its monopoly power.

Total, average, and marginal cost curves are useful for comparing the costs of

various control methods and strategies. They will be used later in the paper when

23

seasonal gas substitution is compared with another proposed control strategy.

VI. 1. The Effectiveness of Seasonal Control Strategies

For evaluating the effectiveness of emission reduction schemes, Golomb et al.

(1985) defined a gain factor (GF) as the ratio of the fractional deposition decrement at

a chosen receptor (here, Adirondacks). to the fractional emission decrement in the

eastern 31 state region that occurs as a result of the reduction scheme. Dividing the

fractional deposition decrement at an Adirondack receptor by the corresponding

fractional emission reduction at the various levels of gas substitution produces a series

of gain factors for this strategy. For each level of percentage decrease in deposition,

there is a corresponding percentage reduction in emissions as a result of seasonal gas

substitution. The GF is calculated from the model results and is a measure of the

overall effectiveness of any deposition control strategy.

To show the increased effectiveness of seasonal over year-round controls, a

comparison of the gain factors from these two strategies is made. Using Eq.(2), it is

possible to calculate the annual deposition reduction that would result at each level of

gas substitution if the same quantity of gas were substituted year-round instead of

during April through September. When a given quantity of gas is substituted, the S02

emission reduction remains the same regardless of whether substitution occured

seasonally or year-round. Substituting a given quantity of gas for coal or oil will

reduce emissions by some constant amount regardless of when during the year

substitution occurs; the same is not true with respect to deposition. The annual

deposition reduction is smaller in the case of year-round controls because the winter

transfer coefficients are smaller. Table 6 presents the GF for each of several levels of

seasonal and year-round gas substitution. For example, for a 25% reduction in

deposition, there is a corresponding 3.9 million ton or 18% (if a 22 million ton base is

assumed) reduction in S02 emissions, (due to 1176 bcf of natural gas being substituted

for coal and oil). If this same quantity of gas were evenly substituted year-round,

emissions would still be reduced by 18%, but, because both summer and winter

transfer coefficients are used, the deposition reduction is now 16%. The GF for

seasonal substitution is (25%/18%)-1.40, while that of year-round substitution is

(16%/18%)-0.88. Hence, seasonal substitution is 59% [(1.40%/0.88% )-1.591 more

effective than year-round substitution at this level. Figure 8 is a graphical

comparison of the gain factors for seasonal and year-round controls. The

24

effectiveness varies somewhat because the relative amount of gas substitution

occuring in each state varies at different levels of deposition reduction.

The GFs for both seasonal and annual controls are diminished at higher levels of

deposition reduction. This is because plants further from the receptor are included in

the solution as the deposition reduction becomes larger. The distance between the two

lines in Figure 6 represents the superiority of seasonal over annual gas substitution.

This distance remains relatively stable regardless of the level of deposition reduction.

In general. a seasonal control strategy is 52-60% more effective than an annualcontrol strategy for reducing deposition at an Adirondack recentor.

VI. 2. The Effect of Substitution on Fuel Consumption

Each plant in the model burns a known quantity of coal or oil annually (EIA,

1984a). It has been assumed that half this quantity is consumed during April throughSeptember. This is supported by evidence that net generation by coal-fired plants

during April through September is 51% of annual net generation in the eastern 31

state region during 1983 (Figure 2).

When a plant is chosen by the model for gas substitution, the coal or oil it would

burn during April through September is replaced by natural gas. The quantity of gas

substituted is determined by calculating the quantity of gas that would be needed to

replace the btu output that the coal or oil would produce. The average heat content forcoal and oil at each plant is used for this calculation (EIA. 1984a).

For natural gas, a heat content of 1000 btu per cubic foot is assumed. Acutal average

heat content for natural gas in the U.S. is approximately 1050 btu/cubic foot (EIA,

1984b); a 5% reduction to 1000 btu/cubic foot has been allowed to account for boiler

derating. i.e. a 5% loss in boiler output. Basically, derating occurs because a boiler

designed to burn coal or oil does not burn gas with equal effectiveness because of

differences in the combustion characteristics of the fuels. Experience with derating

due to gas substitution is meager, since gas substitution in coal and oil burners is very

limited at present. Five percent is a reasonable allowance. based on experience with

substituting natural gas for oil at Boston Edison's Mystic 7 unit (Boston Edison, 1985).

Detailed work on dersting and inefficiencies caused by burning gas in boilers

designed for coal or oil is left to future analyses.

The model calculates the quantities of gas substituted and coal and oil displaced for

the various levels of deposition reduction that the model was exercised for, as shown in

25

the bottom half of Table 5. These quantities were mentioned earlier in the case of 20%

and 30% deposition reductions. Figures 9, 10, and 11 show curves of these quantities.

Initially most of the gas is substituted for oil. However, because oil's contribution

to deposition is very small, coal quickly becomes the object of substitution. To

illustrate, Figure 11 shows that for a 5% deposition reduction, gas displaces 79 million

out of a possible 97 million barrels of oil, i.e. 80%. For coal. Figure 10 shows that 8

million out of a possible 176 million tons, i.e. less than 5%, is displaced. For a 20%

deposition reduction, the respective percentages for oil and coal are 90% and 30%, oil's

percentage rises only slightly while coal's percentage increases by a factor of six.

Hence, beyond the lowest levels of deposition reduction, substituting gas for coal is

nearlv,comnletelv resoQnsible for further reductions.

VI. 3. The Average Cost of Emission Reduction

Figure 12 shows the reductions in S02 emissions for various reductions in

deposition. Using this and the total cost data, the average cost of emission reductions at

various levels of deposition reduction can be calculated (Figure 13). The average cost

of reducing S02 emissions via seasonal gas substitution ranes from a negative $340

nor ton S02 at the 5% denosition reduction level (from Figure 12 this corresponds to a

0.6 million ton reduction in emissions). to a ositive S1584 oer ton S02 at the 40%

deposition reduciton level (a corresponding 6.9 million ton emission reduction). (The

cost of emission reduction is negative when there is a negative price differential, i.e.

when oil is more expensive per btu than natural gas). For comparison, the S02

removal cost by limestone flue gas desulfurization (scrubber) was reported to be in the

range $576-1126 per ton (Miller, 1985). From the sixth column in Table 5, it can be

seen that the average cost of seasonal gas substitution is in or below the average cost

range for scrubbing, for up to a 25% reduction in total annual deposition at the

Adirondack receptor. The conclusion is that there are a substantial number of plants

where the cost of seasonal gas substitution is competitive with that of scrubbing.

As noted earlier, the costs of seasonal gas substitution are based on 1983 fuel price

differentials. Future price differentials may vary, consequently, future costs may be

different,

VI. 4. The Average Cost of Deposition Reduction

The debate over alternative strategies for controlling acid rain has focused mainly

26

on the expected costs of reducing S02 emissions. Total cost and S/ton of S02 removed

are frequently used to compare alternative control strategies. In making these

comparisons, a distinction should be made between receptor-oriented (or targeted)

strategies that maximize the amount of deposition reduction at a receptor(s) for a unit

of emission reduction, and source-oriented strategies aimed solely at reducing total

emissions. A direct comparison of the cost of receptor- and source-oriented strategies

can be misleading; these strategies will not result in equal deposition reductions at a

given receptor for equal emission reductions.

In order to facilitate a direct comparison, it is useful to define a cost per unit of

deposition reduction at a particular receptor. Dividing the total cost for seasonal gas

substitution by the corresponding quantity of deposition reduction at a receptor,

produces a measure of the average cost of reducing deposition at that receptor. The

average cost of deposition reduction at an Adirondack receptor, expressed in terms of

billions of dollars per kg S04 per hectare per year (B$/kg S04 ha I yrl), is shown in

Table 5, column 4. The average cost for deposition reduction ranges from a negative

$0.165 billion/ kt S04 hair-lt. for a 5% deposition reduction to $1.002 billion/ kt S04

hI;!-i for a 40%' deoosition reduction.

After first determining the resulting deposition reduction, the average cost of

deposition reduction may be calculated for any source-oriented emission control

strategy. Cost comparisons, based on the cost of deposition reduction rather than the

cost of emission reduction, can then be made between seasonal gas substitution and

source-oriented control strategies. The following section illustrates such a

comparison.

Morrison and Rubin (1985) developed a model that computes the emission

reduction and cost that would result from emission caps of 1.5 and 1.2 lbs. S02 per

million btu on utility emissions using optimized combinations of switching to lower

sulfur coal and flue gas desulfurization (FGD). The 1.5 and 1.2 lbs. emission caps

resulted in annual emission reductions of 8 and 10 million tons S02 respectively. Based

on the distribution of emission reductions across the eastern 31 states, these emissionreductions would respectively yield 7.2 and 8.2 kg S04 ha 1 yfrt deposition reductions

at an Adirondack receptor (calculated using the MIT acid deposition model annual

transfer coefficients). These quantities of deposition reduction are respectively

equivalent to 26% and 30% reductions from the 27.5 kg S04 hal 1 base deposition level

at an Adirondack receptor.

27

Table 7 summarizes the following comparisons. Morrison and Rubin calculated

total cost ranges of $1.5-2.6 and 3.2-4.7 billion (1980S) for the S and 10 million tons of

S02 emission reductions, respectively. Using a GNP deflator of 1.2 to adjust to 1983

dollars makes the cost ranges $1.8-3.1 and 3.8-5.6 billion, respectively. Dividing the

cost by the deposition reductions gives $0.25-0.43 and 0.46-0.68 billion per kg S04

deposition removed, respectively, for the two cases. Referring to Table 5, column 4,

the average cost of deposition reduction for similar (25% and 30%) reductions via

seasonal gas substitution is $0.64 and 0.72 billion per kg. The conclusion is that, for

25% and 30% deposition reductions fat an Adirondack receptor, Morrison and Rubin's

optimized straegy has a lower average cost per kilogram of S04 reduced than does

seasonal gas substitution. This is not to my that seasonal gas substitution is not

cost-competitive with other control strategies, in this case an optimized combination

of switching to lower sulfur coal and FGD. I respectfully submit that Morrison and

Rubin's is but one control strategy; other control strategies will have different costs,

some higher and some lover. The purpose of the preceding comparison is primarily to

show that cost comparisons with respect to deposition can be made between source-

and receptor-oriented strategies.

Using the data in Appendix C, state-level average costs were computed for 25% and

30% deposition reductions (Table 8). Figures 14 and 15 show this data ranked from

lowest to highest, plotted against the cumulative percentage deposition reduction of

the states. For example, in Figure 14. Ohio's (OH) average cost is $0.724 billion per kg

S04 hal, at the 25% deposition reduction level; it accounts for an approximate 5%

deposition reduction by itself, and together with preceding states accounts for a 12%

deposition reduction.

While the average costs for seasonal gas substitution in the entire eastern 31 state

region are higher than those derived from Morrison and Rubin's two cases for

equivalent deposition reductions, there are several states that do have average costs of

achieving deposition reduction via seasonal gas substitution that are within theranges of Morrison and Rubin's cases. The following states, DC, FL, MA. NJ, NY, RI, and

VA, have average costs that are in or below the ranges specified by Morrison andRubin, namely $0.25-0.43 billion (25% reduction) and $0.46-0.68 billion (30%

reduction) per kg S04 ha' 1 reduced. Thus, it appears that seasonal gas substitution

may be cost-competitive with other control methods, in this case an optimized

combination of switching to low-sulfur coal and FGD, in some states.

28

VII. GAS SUPPLY FOR SUBSTITUTION

The seasonal gas substitution model has not considered gas deliverability

constraints which may limit the amount of substitution that occurs within a state as

specified by the model. A gas deliverability constraint would occur whenever the gas

supply infrastructure lacks the necessary capacity to meet the incremental demand

imposed by a level of gas substitution, or if total gas production is exceeded by the

incremental demand. In order to utilize gas substitution, the utility must access its gas

supply from a gas distribution company's or gas transmission company's

high-pressure pipeline. Tran ission capacity can be expanded, but this may

increase fuel costs, which may make gas substitution les competitive relative to other

control strategies.

Because the primary use of natural gas is for space heating, summer demand is

lower than winter demand in nearly all states. This condition favors seasonal gas

substitution, but not in an unlimited or universal pattern. The ratio of summer sales

volume to winter sales volume averaged 49% and ranged from 33% to 103% in the 31

eastern states and DC in 19B4 (Table 9). The winter/summer sales ratio is only an

indicator of general capacity and cannot be relied upon as a derinitive measure of

excess capacity available to every generating unit within a state. For the purposes of

this study it is assumed that the difference between winter and summer consumption

is an approximate measure of available capacity. The aggregate difference between

summer and winter volume is 2030 billion cubic feet, which would provide

approximately enough gas substitution for a 37% reduction in deposition (from Figure

7). However, not every state has the necessary surplus summer gas required at all

levels of deposition reduction. For example, for a 25% deposition reduction, only 14

states have the surplus needed to supply their share of the model's solution. The

summer surplus is estimated from Table 9. column 4; the incremental demand for gasin each state sufficient for a 25% reduction in deposition is shown in Table 10.

While the availability of natural gas is a significant factor, as supply constraints

are not included in the model. This simplification is made because the availability of

gas is difficult to estimate within a state or at a given plant. The determination ofavailability is left to those considering gas substitution. A general approximation of

gas availability can be made by comparing seasonal sales volumes for selected gas

transmission and distribution companies. Table lla shows the ratio of summer to

winter sales volumes for major interstate transmission companies operating in the

29

eastern US.; Table lb shovs the ratios for several gas distribution companies. It can

be seen that excess summer capacity is generally available, but the amount varies

greatly between companies and regions.

30

VIII. OTHER COSTS

Preliminary findings concerning incremental capital and operating costs for

seasonal gas substitution reveal two significant points. First, capital costs are low and

implementation is quick. Using as an example the Boston Edison Mystic *7 unit, an

oil-fired generating unit that converted to seasonal gas use, the boiler modification

and gas supply construction cost $3.5 million for the 565 MW unit and was completed in

approximately one year (Boston Edison, 1965). This is approximately $6/kV. In

contrast, capital costs for limestone flue gas desulftrization (scrubbing) are between

$175 and $317/kW (Miller, 1983), and have much longer lead times. Second, ash

generation is reduced. If the variable component of ash disposal is significant, there

is a potential cost saving from seasonal gas substitution. For example, a 500 MV

coal-fired unit might produce 130,000 tons of bottom and flyash annually. If variable

disposal costs are $10/ton, the ash disposal cost is $1.3 million annually. Seasonal gas

substitution could save one-half of this sum. The present value of these savings are

close to or may exceed the capital costs associated Vith seasonal gas substitution.

The crucial determinant of the cost-competitivenes of gas substitution is the price

differential between gas and coal and gas and oil. Since long term prices are

impossible to predict with certainty. gas substitution is regarded as being financially

risky when compared with other control methods. Actually, gas substitution my be

les risky than more capital intensive control methods. Because there is relatively

small capital investment associated with gas substitution, a utility could easily abandon

it if a more cost-effective solution became available without forfeiting a large

investment. Because of the large capital outlay needed for scrubbing equipment, a

utility saddled with an expensive scrubber is financially limited if it wants to exploit

less expensive control methods that may become available.

31

IX. CONCLUSIONS

Nearly all of the "acid rain" policy and policy analyses have focused on emission

reductions and the cost of controlling emissions. But it is deposition, not emissions per

se, that matters. Monitoring has shown that deposition rates are significantly higher

during April through September than during October through March for equal

emission rates. Based on this evidence, it is more efficient to control emissions (and

hence deposition) during the summer half of the year.

Seasonal substitution of gas for coal or oil is a reasonable option for utilities to

control S02 emissions and is vwell suited to comply with policies which focus on

controlling deposition. However, it is not a panacea for reducing S02 emissions. The

quantities of gas needed for substitution in order to make total emission reductions of

more that a few million tons per year in S02 emissions would exceed existing capacity

in many states. Some generating units are located too far from a gas supply or face

fuel cost differentials that are too large to make gas substitution economically

competitive with other control methods. On the other hand, many generating units do

have access to sufficient quantities of gas at costs that make gas substitution

competitive with other emission control methods.

The cost-effectiveness of any control method should be related to its effect on

deposition rather than its effect on emissions. One ton of S02 removed in the summer

half of the year has a greater effect on deposition than reducing that ton year-round.

It was shown that in terms of equal deposition reductions in the Adirondacks. that thecosts of seasonal gas substitution and some year-round controls may be comparable in

some states.

Conclusions:

* In some states seasonal gas substitution may be economically competitive with

other control methods for achieving equal annual deposition reductions in sensitive

areas.

* In some states gas deliverability and supply may limit the amount of gas

substituted.

* Capital costs for gas substitution are very low relative to FGD systems.

32

References

Bardin, D. J., 1985. "Real and Imagined Restrictions on Electric Utility Fuel Use ofNatural Gas." Public Utilities Fortnightlv March 21, 1985.

Boston Edison. 1985. Personal communication vith Mr. Paul Kingston. OperationsSupervisor, Mystic *7 unit, July 1985.

Boversox, V. C. and G. J. Stensland, 1965. "Seasonal Variations in the Chemistry ofPrecipitation in the United States." Paper 85-6A2 presented at the 78th AnnualMeeting of the Air Pollution Control Association., Detroit, MI.

Elkins, C. L., 1985. "Acid Rain Policy Development." Journal of the Air PollutionControl Association. No.3.

Energy Information Administration (EIA). 194. Cost and Oualitv of Fuels for ElectricUtility Plants 1983.

Energy Information Administration (EIA), 1984b. Natural Gas Monthly. January-December 1964.

Energy Infromation Administration (EIA). 195. Electric Pover Monthly January1985.

Fay, J. A.. D. Golomb, and J. Gruhl. 1983. "Controlling Acid Rain," MIT-EL 83-004,Energy Laboratory. Massachusetts Institute of Technology. Cambridge. MA 02139.

Fay. J. A.. D. Golomb. and S. Kumar. 1985. "Source Apportionment of Wet SulfateDeposition in Eastern North America." Atmospheric Environment. 19. pp. 1773.

Fay, J. A. and J. J. Rosenzveig, 1980. Analytical Diffusion Model for Long DistanceTransport of Air Pollutants." Atmosheric Environment pp. 355-365.

Golomb. D.. J. A. Fay. and S. Kumar, 1985. "Seasonal Control of Sulfate Deposition."Paper 85-lB.8 presented at the 78th Annual Meeting of the Air Pollution ControlAssociation. Detroit. MI.

Kumar S.. 1985. "Modeling Acid Deposition in Eastern North America." Sc.D. Thesis.Massschusetts Institute of Technology, Cmabridge, MA 02139.

Miller, M. J., 1985. "Retrofit S02 and NOx Control Technologies for Coal-Fired PoverPlants," Paper 5-1A2 presented at the 78th Annual Meeting of the Air PollutionControl Association, Detroit, MI.

Morrison, M. B. and E. S. Rubin, 1985. "Linear Programming Model for Acid RainPolicy Analysis." ournal of the Air Polution Control Association. 35. No. 11.

33

National Acid Precipitation Program (NAPAP), 1983. "Historic Emissions of Sulfur andNitrogen Oxides in the U.S. from 1900 to 1980," EPA-600/7-85-009a.

Office of Technology Assessment (OTA), 1985. U.S. Natural Gas Availability: Gas SuoolyThrough the Year 2000. Washington, D.C., U.S. Congress, Office of TechnologyAssessment, OTA-E-245, February 1985.

Raynor, G. S. and J. V. Hayes, 1982.Island, NY Precipitation in RelationPollution. 17, pp. 309-335.

"Concentrations of Some Ionic Species in Longto Meteorological Variables," Water. Air. and Soil

Wilkinson, P., 1984. "Seasonal Fuel Switching to Natural Gas: A Logical Approach toReduce Sulfur Dioxide." Gas Enervy Review. 12, pp. 11-17.

34

Table 1. Transfer Coefficients for Adirondack Receptora(kilagrams sulfur per hetare deositad per terun sulfur emitted)

(Tij)WI

(kg S

0.25790.17420.79030.60070.62740.23000.29880.28050.31170.18520.33560.16500.72300.62870.52250.40450. 13730.20680.20330.43970.87520.73730.91270.4641

-0.63390.72300.34860.30270.53101.29500.49790.2500

(Tij)suha- 1 /TgS

0.59080.36271.87201.61801.63600.43230.69380.71040.80850.41530.86710.31201.6480

1.67801.04101.09800.27720.43900.46411.12001.78901.88102.18401.29401.77501.64800.82230.74631.41302.61801.37100.6106

(Tij)AN

emitted)

0.4070.2641.198

0.9951.198

0.3300.4730.4700.5240.2970.5600.2371.086

1.033

0.7580.6880.2140.3150.3250.7231.217

1.167

1.366

0.7921.061

1.0860.5560.4940.8821.6540.8420.415

(a) Kumar (1985)

35

State

AL

AR

CT

DC

DE

FL

GA

IL

IN

IAKY

LA

MA

MD

ME

MI

MN

MS

MO

NC

NH

NJ

NY

OH

PA

RI

SCTN

VA

VT

WV

WI

Table 2. Annual Sulfur Emissions from Coal- and Oil-FiredPower Plants in the 31 Eastern States and DC 1983

Million Metric TonsOil

00

0.0240.0010.0070.096000.0040000.0670.0070.005000.001000.0080.0070.10300.0150.001000.00300

SulfurTotal

0.241

0.0320.0240.0010.0340.3020.3790.0880.5480.6900.551

0.0140.1010.0950.0050.2730.071

0.5490.041

0.1650.0310.0470.2070.9320.7270.0010.0820.3030.0590.2050.453

MillionCoal

0.5360.070000.0600.4580.8430.1971.210

1.5341.225

0.0320.0770.19700.6060.1571.218

0.0910.3670.5120.0880.2302.0711.583

00.1820.6740.1230.4561.007

Tons S02Oil

000.0540.0010.0160.213000.0100000.1490.0150.0110.00100.002000.0170.0160.22900.0330.002000.00600

Total

0.5360.0700.0540.0010.0760.671

0.8430.1971.220

1.534

1.225

0.0320.2260.2120.0110.6070.1571.220

0.0910.3670.0680.1040.4602.0711.616

0.0020.1820.6740.1300.4561.007

TOTAL 6.906 0.350 7.25 15.346 0.777 16.123

Source: EIA, 1984

36

StateCoal

ALAR

CT

DC

DE

FL

GA

IAIL

IN

KY

LA

MA

MD

ME.

MIl

MN

MO

MS

NC

NH

NJNY

OH

PA

RI

SC

TN

VA

WI

WV

0.241

0.032000.0270.2060.3790.0880.5440.6900.551

0.0140.0350.08800.2730.071

0.5480.041

0.1650.0230.0390.1040.9320.71200.0820.3030.0560.2050.453

Table 3. Summer and Annual Sulfur Deposition Contributed

by Power Plants in the 31 Eastern States and DCkilograms sulfur per hectare per year (kg S he yr 1 )

State Summer DeDositionCoal Oil

AL

AR

CT

DC

DE

FL

GA

IA

ILIN

KY

LAMA

MD

ME

MI

MN

MO

MS

NC

NH

NJ

NY

OH

PA

RI

SC

TN

VAWI

WV

0.071

0.006000.0220.0440.1320.0180.1930.2790.2390.0020.0290.07400.1500.0100.1270.0090.0920.0210.0370.1130.6030.63200.0340.1130.0390.0630.311

TOTALS 3.464

AnnualCoal

0.0980.008000.0280.0680.1790.0260.2560.3620.3090.0030.0380.09100.1880.0150.1780.0120.1190.0280.0460.141

0.7380.75600.0450.1500.0490.0850.381

4.401

000.0230.0010.0060.021

000.0010000.0550.0060.003000000.0070.0070.11300.0130.001000.00200

0.258

DepositionOil

000.0290.0010.0070.032000.0020000.0730.0070.004000000.0090.0080.141

00.0160.001000.00300

0.333

Source: Calculated from Tables 1 and 2

37

I

Table 4. Average Cost of Natural Gas at Electric Utilitiesin the 31 Eastern States and DC 1983

State $/106 btu

AL 3.129AR 3.21 1

CT 5.930(b)

DE 4.180

DC 4.480(a)

FL 2.529

GA 4.177IL 5.291

IN 4.238

IA 3.747KY 4.551

LA 3. 150MA 3.887MD 4.480(a)

ME 7.660(b)

MI 4.38

MN 3.798

MS 3.325MO 4.164

NC 4.860(a)NH 6.000

NJ 4.046NY 3.932OH 5.169PA 5.104

RI 3.753

SC 4.285

TN 3.870(a)VT 4.220(a)

VA 4.202WI 4.284

WV 4.546

(a) Average prices calculated from data reported on Form EIA- 1 76.(b) Average 1983 price paid by industrial consumers.Source: EIA, 1984 and EIA, 1984a

38

Table 5. Summary of Results for Seasonal Gas Substitution Model

Reduction inS02 Emissions

(1 06 tons)

0.6

1.3

2.2

2.9

3.9

4.8

5.9

6.9

Total Costof DepositionRe tion( I0 $1 983)

-.204

.610

1.671

2.929

4.403

5.858

7.867

10.931

O3m Substituted(billion cubic f)

337

501

709

909

t1176

1440

1795

2396

Average Cost

of DepositionReduction

( 0' S perkg S04 ha - 1)

-.165

.233

.418

.542

.641

.721

.827

1.002

Coal Displaced

( 106 tam)

8

20

37

53

76

97

127

176

Marginal Costof DepositionReduction

( 109 perkg S04 ha- I )

.456

.708

.853

.938

1.093

Average Cost

of EmissionsReduction

($S per ton

502 removed)

-340

469

759

1010

1129

12201.231

1.600

2.996

Oilislaed( 0 brrels)

79

84

87

87

87

94

95

97

1333

1584

S per 106 btu

dsplal

-.303

.609

1.179

1.611

1.873

2.035

2.192

2.281

(a) Calculated from 27.5 kg 504 ha-1 base at Adirondack receptor (Fay et al., 1985).

39

% Reductiona

in Deposition

102

15%

20%

25

30%

35%

40X

% Reduction

in Deposition

5%

10%

15%

20%

25%

30%

35%

40%

Table 6. Gain Factors for Seasonal and Annual Gas Substitution

3 Rductonb

in Deposition(yer- roundcontrols)

3.3

6.5

9.6

12.7

15.7

18.8

22.2

25.4

SummercOin Factlor

1.61

1.49

1.43

1.47

1.40

1.36

1.29

1.25

nlin Factor

1.06

0.97

0.91

0.93

0.88

0.85

0.82

0.80

Effettlveness

52S

543

57%

583

59X

603

573

56

(a) Calculated from bee of 22 million tons of 02 emitted annWlly.(b) Calculed from Eq.(2).(c) Equals % Reductin in Depositin(summer controls) divided by % Reduction In Emissions.(d) Equals % Reduction In Depostn(ye-round controls) divided by % Reducton InEmissims.

(e) Summer coontrols are XX more effctive th year-rounmd controls for reducing depoitionat an Adrondack rceoopr.

40

% Reductionin Deposition(summercontrols)

3 Ruhictonin Emissio

5 3.1

10 6.7

15 10.5

20 13.6

25 17.8

30 22.1

35 27.2

40 31.9

Table 7. Comparison of Costs of Deposition Reductionsat an Adirondack Receptor

S04 Deposition Reduction Avg. Cost ofDeposition Reduction

%a kg S04ha-ly-I (1983 109 S kg- I ha-1 )

Morrison and Rubinb-

26

Seasonal Gas

Substitutionc -

25

0.25 0 -.430f

Morrison and Rubind-

30

Seasonal Gas

Substitutlone-

30

8.2

8.2

0.46 0 -.68 0 f

0.721

(a) Based on modeled (uncontrolled) deposition of 27.5 kg 504 ha- I y- I

(b) Stafford Bill, state-wide emission cap of 1.5 lb./ 106 btu.

(c) Summer gas substitution model set to 25% deposition reduction.

(d) Mitchell Bill, state-wide emission cap of 1.2 lb./ 106 btu.

(e) Summer gas substitution model set to 30% deposition reduction.

(f) Calculated from Morrison and Rubin (1985).

41

7.2

6.9 0.641

------------------------------------------------------------------

Table 8. State-Level Average Costs for Achieving Reductions in504 Deposition via Seasonal Gas Substitution in ElectricPower Plants in the 31 Eastern States and DC

25% DePosition ReductionAvg. Cost

Dep. Red.

(109 $ perkg 504 he- I)

.828(a)

-.882.777

-1.0721.115.968.854.911.837.128.814.995.949.859.473.066.724.796

-.403.830

-.2351.023.707

30% Deposition ReductionAvg. Cost

Dep. Red.

(09 per

kg S04 h( 1)

.8511.187

-.882.777

-1.0721.130.9681.0241.009.840.128

.814

.995

.961

.859

.473

.066

.768

.842-.403

.873-.2351.106.806

(a) CT is not included at the 25% deposition reduction level.

42

State

AL

CT

DC

DE

FL

GA

IAIL

IN

KY

MA

MD

MI

MO

NH

NJ

NY

OH

PA

RI

TN

VAWI

WV

Table 9. Natural Gas Deliveries to Residential, Commercial, andElectric Utility Consumers in 31 Eastern States and DC

State SummerVolumea

(bcf)

ALAR

CT

DE

DC

FL

GA

[L

IN

IA

KY

LA

MEMD

MA

MI

MN

MS

MO

NH

NJ

NYNC

OH

PA

RI

SC

TN

VT

VA

WV

Wl

21.937.920.2

8.19.7

112.443.8

202.565.635.628.5

233.70.5

33.673.8

152.346.649.851.32.7

129.3256.1

18.2141.1111.4

10.110.621.10.9

24.116.1

48. 1

Wintervolumeb

(bcf)

55.468.739.89.5

20.9109.1107.9510.5173.096.678.4

234.71.1

71.9115.1370.0134.359.6

137.06.1

208.6410.547.2

377.6282.2

16.125.763.52.2

51.543.2

119.1

Winterless Summer

(bcf)

33.530.819.61.4

11.2-3.364. 1

308.0107.461.049.911.00.6

38.341.3

217.787.79.8

85.73.4

79.3154.4

29.0236.5170.8

6.015.142.4

1.327.427.171.8

Summer Volume

as a Percent ofWinter Volume

405551

8546

1034140383736954547644135843744626239373962413342473740

Total 2007.6 4057.6 2050 49

Source: EtA, 1984b

(a) Summer--April through September(b) Winter--October through March

Note: Industrial gas consumption is not included here as the data is not yet reported by theEnergy Information Administration. Exclusion of this component probably causes the ratio ofsummer to winter volume to be slightly overstated here.

43

Table 10. Natural Gas Substituted for a 25% Reduction in Deposition

Gas (Bcf)

51

1

!9144

32073

61

59405025

911

30137

143

1841

41

3

2

68

SufficientSurplus(a)

N

Y

N

N

Y

Y

Y

N

N

N

Y

Y

Y

N

Y

Y

Y

N

Y

Y

Y

Y

N

1176

(a) The difference between winter and summer volume of sales in used asan approximate measure of summer capacity. If Table 9, column 4 isgreater than the incremental demand shown above, then Y.

44

State

AL

DC

DE

FL

IA

IL

IN

KY

MA

MD

MI

MO

MS

NH

NJ

NY

OH

PARI

TN

VA

WI

WV

Table 1 1. Summer and Winter Gas Sales Volume(a)

a. Interstate Pipeline Companies Summer Volume as aPercent of Winter Volume

Algonquin 86Columbia Gas 50Consolidated Gas 65East Tennessee 65El Paso 95Florida Gas 90Great Lakes Gas 177

Michigan Consolidated 46Midwestern Gas 83Natural Fuel 47Natural Gas Pipeline 70Northern Natural 50Panhandle Eastern 57Southern Natural 65Tenneco Inc. 86Texas Gas Transmission 73Transcontinental 72Trunkline Gas 58United Gas 82

b. Selected Distribution Companies

Northern Illinois Gas (IL) 41Peoples Gas (IL) 38K Indiana Public *efvice (IN) 60Indl*ia Gas Comny (IN) 47Louisville Gas and Electric (KY) 39Columbia Gas of KY 34Boston Gas Company (MA) 85Michigan Consolidated (MI) 46Consumers Power Company (MI) 44PSE&G (NJ) 43Brooklyn Union Gas (NY) 65Consolidated Edison (NY) 54

(a) From EIA ( 1 984b) and State Utility Commissions

45

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(1L4/68)NOIlWSOd3C 13M VOS

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" 140M 130

= 120- 110

- 100m 90S-a, 80

706050403020100

J FMAMJ JASOND J FMAMJ JASONO J FMAMJ JASOND1983 1984 1985

Figure 4a. Natural Gas / Coal Price Differentials

m

0._

0-.W

V --10 --20 --30 -

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3F -lt~f~f~~E1BM~ tlt~EiE~Et-

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J FMAMJ JASOND JFMAMJ JASOND1983 1984

Figure 4b.

I I I I I I I I I I I I

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Natural Gas / Oil Price Differentials

49

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N

APPENDIX A

Data for Coal- and Oil-Fired Electric Utilities

in the 31 Eastern States and DC

Guide-

Column:

(1) Company name

(2) Plant name

(3) State where plant is located

(4) Annual coal consumption in thousands of tons

(5) Coal price Si 106 btu

(6) Coal price S/ ton

(7) Sulfur content of coal, percent by weight

(8) Coal heat content, btu per lb.

(9) Annual oil consumption, thousands of barrels

(10) Oil priceS/ 106 btu

( 11) Oil price $/ barrel

(12) Sulfur content of oil, percent by weight

61

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APPENDIX B:

Price Differentials for Plants and States

Guide-

Column:

(1) Company names organized by state

(2) Plant name

(3) Type of fuel burned. C=coal and O-oil

(4) S per million btu price differential between the

state-average natural gas price (from Table 4)

and the price of coal or oil burned at each plant

(5) Billions of btus of coal or oil displaced. or

conversely gas substituted. at each plant

(6) Weighted (by Total BBtu) average price

differential ($/106 btu) for each state

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APPENDIX C:

Output of Seasonal Gas Substitution Model

Guide-

Column:

( 1) State where plant is located

(2) Company name

(3) Plant name

(4) Coal displaced by gas substitution at plant. thousands of

tons

(5) Cumulative coal displacement, thousands of tons

(6) Oil displaced by gas substitution at plant. thousands of

barrels

(7) Cumulative oil displacement, thousands of barrels

(8) Gas/coal or gas/oil price differential at each plant,

calculated from gas prices in Table 4 less coal and oil

prices in Appendix A.

(9) Billions of btus of coal or oil displaced, or conversely, gas

substituted at each plant

(10) Cumulative gas substituted, millions of cubic feet

(11) Cumulative emissions of S02 removed. millions of tons

(12) Reduction in deposition of S04 at Adirondack receptor as a

result of gas substitution at each plant, kg S04 ha- y-

(13) Cumulative reduction in sulfate deposition at Adirondack

receptor, kg S04 ha- y- 1

(14) Percent change in sulfate (S04) deposition as measured

from 27.5 kg S04 ha- 1 base

(13) Cost in millions of dollars per kg S04 ha- 1 reduced for

each plant, i.e. the marginal cost with respect to

deposition of seasonal gas substitution

(16) Total cost in millions of dollars for gas substitution

17) Cumulative cost in millions of dollars

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