Implications

ofGreater

Relianceon

NaturalGas

forElectricity Generation

July 2010

Prepared For
Implications of Greater Reliance on 

Natural Gas for Electricity Generation

Prepared For

The American Public Power Association

July 2010
Aspen Environmental Group Page i

Implications of Greater Reliance on Natural Gas for 

Electricity Generation

Table of Contents

Executive Summary.......................................................................................................................................1

Introduction ..................................................................................................................................................5

Definitions and Scale.....................................................................................................................................6

Natural Gas Demand.....................................................................................................................................8

Natural Gas Supply......................................................................................................................................25

The Role of LNG ......................................................................................................................................27

Uncertainty about Shale Production ......................................................................................................28

Price Impacts...........................................................................................................................................36

Natural Gas Delivery Infrastructure............................................................................................................40

Natural Gas Storage ....................................................................................................................................57

Cost to Build and Use Storage.................................................................................................................65

Impediments to Adding Storage .............................................................................................................68

Operational Considerations........................................................................................................................72

Nominations and Balancing ....................................................................................................................72

Curtailment.............................................................................................................................................75

Hurricane Risk to Supply and Prices........................................................................................................79

Staff Expansion........................................................................................................................................85

Retrofitting Coal Plants to Burn Natural Gas..............................................................................................87

Conclusion...................................................................................................................................................93
Implications of Greater Reliance on Natural Gas for Electricity Generation 

Aspen Environmental Group Page ii 

List of Figures 

Figure 1: Natural Gas Demand by Sector Since 2001 ...................................................................................8

Figure 2: Illustrating Peak Nature of Monthly Natural Gas Demand ..........................................................10

Figure 3: Annual Natural Gas Demand and Supply since 1930 ...................................................................11

Figure 4: Timeline for Potential EPA Rules Affecting Electric Power Plants ...............................................12

Figure 5: Location of Existing U.S. Coal-Fired Generation (By County).......................................................21

Figure 6: U.S. Annual Proved Reserves of Dry Natural Gas ........................................................................26

Figure 7: Shale-Deposited Gas Supply Basins .............................................................................................29

Figure 8: Three New OCS Lease Areas Opened for Offshore Drilling .........................................................35

Figure 9: Gas Production per New Well ......................................................................................................36

Figure 10: Implied Natural Gas Supply Curve Through 2007 ......................................................................37

Figure 11: U.S. Natural Gas Transmission Pipelines ...................................................................................41

Figure 12: Total Interregional Pipeline Capacity 1990 to 2008...................................................................46

Figure 13: Regional Basis Differentials ........................................................................................................48

Figure 14: Interstate Pipeline Capacity Utilization if An Individual State Switched its Coal-Fired 

Generation to Natural Gas ..........................................................................................................................54

Figure 15: Geographic Distribution of Underground Gas Storage Facilities ...............................................58

Figure 16: How Storage Balances Seasonal Demand with Monthly Production .......................................60

Figure 17: Existing Coal-Fired Generation Located In Same County as Underground Gas Storage ...........64

Figure 18: Hurricane Impact on Production ...............................................................................................81

Figure 19: Katrina and Rita Impact on Monthly Natural Gas Production and Demand .............................83

Figure 20: Katrina and Rita Impact on Natural Gas Prices ..........................................................................84

Figure 21: Dispersion Model Receptor Grid Used for Proposed EPA 1-hour NOx NAAQS .........................92

Figure 22: Total Cost to Implement Switch from Coal to Natural Gas ........................................................94

List of Tables 

Table 1: Comparison of Various Studies’ EG Resource Mix and Resulting EG Gas Burn ...........................14

Table 2: Range in Projected EG Natural Gas Burn and Total Demand ........................................................18

Table 3: Natural Gas Demand if All Coal-Fired Generation Replaced with Gas at Current Electricity 

Market Size/No Growth ..............................................................................................................................20

Table 4: Comparison and Extension of Demand Cases to Determine New Gas Pipeline Requirements...45
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page iii 

Table 5: Gas Burn by State* if Existing Coal-Fired MW Converted to Natural Gas ...................................53

Table 6: Storage Summary .........................................................................................................................57

Table 7: Storage Working Inventory and Daily Deliverability Capability by Region ..................................62

Table 8: Illustration of Consumer Costs to Use Underground Gas Storage...............................................67

Table 9: Effective Cost of Storage ..............................................................................................................68

Table 10: North American Energy Standards Board Gas Nominating Windows ........................................74

Table 11: Interstate Pipeline Balancing Periods .........................................................................................75

Table 12: 2005 and 2008 Hurricane Oil and Gas Damage Summary ..........................................................80
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page iv 

This report was prepared by Aspen Environmental Group (Aspen) 

for the American Public Power Association, with financial support 

from the Utility Air Regulatory Group and other electric utilities. It 

does not necessarily represent the views of any of the study 

sponsors or their members. Aspen prepared the report as an 

independent analysis, with some technical support from the 

sponsors, but primarily relying on Aspen’s best professional 

judgment and analysis of publicly-available data. Such data is not 

within the control of Aspen Environmental Group and we are not 

responsible for its accuracy. Any use of this report constitutes 

agreement that Aspen Environmental Group accepts no liability for 

consequences arising from said use. 

Aspen provides independent, objective analysis of environmental 

and energy economics issues, including environmental compliance, 

impact assessment, and mitigation services for energy and 

infrastructure projects particularly for power plant siting, in 

addition to electricity resource planning. The firm has offices in 

San Francisco, Sacramento, Agoura Hills, and Las Vegas. 

The principal investigator for this report is Senior Associate 

Catherine M. Elder. Ms. Elder has more than 25 years of 

experience in the natural gas and electricity industries. She has 

reviewed fuel plans and prepared natural gas market assessments 

for more than 40 natural gas-fired power projects around the 

country, forecast natural gas prices, negotiated contracts for 

natural gas supply and transportation, and evaluated proposed 

greenhouse gas policies for their effect on electric utilities and 

their customers.
Aspen Environmental Group Page 1

Implications of Greater Reliance on Natural Gas for 

Electricity Generation

Executive Summary

This report—Implications of Greater Reliance on Natural Gas for Electricity Generation—examines the 

impacts on natural gas and deliveries to electric utilities should rules limiting utility emissions of carbon 

or other pollutants result in a shift away from coal towards using more natural gas to generate 

electricity. It was commissioned by the American Public Power Association (APPA), with financial 

support from the Utility Air Regulatory Group (UARG) and other electric utilities. 

The report begins with a review of the natural gas industry for those who are less familiar with it. It then 

covers demand, supply, transmission and storage infrastructure, and operational changes that will need 

to be made by units switching from coal to gas. This report also examines the economics of switches 

from coal to gas. An understanding of these issues is needed if the electricity industry should need 

substantially more gas than several studies have suggested. If substantially more gas is needed, then a 

number of changes will need to be made by both the gas and electricity industries: changes such as 

massive infrastructure additions, changes to nominating and balancing services, changes to curtailment 

rules, and changes to subscription levels on interstate pipelines, for starters. The ultimate purpose of 

the study is to identify those implications so that policy makers can take them into account in deciding 

what regulations to adopt, and utilities can take them into account in making selections about what 

resources to use in providing electricity to their customers. 

Demand

Demand for natural gas now is approximately 23 Trillion Cubic Feet (Tcf) per year in a market split 

roughly equally between serving the residential and small commercial, industrial, and electric 

generation sectors. Current demand is only slightly higher than the industry’s prior peak of 22 Tcf in 

1972. During that time industrial demand fell off, to be replaced by demand by electric generators. 

Several studies have looked at what future natural gas demand might be if carbon emissions were 

regulated. Their answers range considerably, depending on what the studies’ authors assumed about 

the availability and cost of other generating resources. None of these studies appears to have looked at 

the full range of regulations that might affect electric generators and might lead to larger numbers of 

units to be converted from coal-burning to gas-burning. If all existing coal fired generation were to 

switch to gas today, overall natural gas demand would total 36 Tcf per year, or half again as much as 

today. Two-thirds of the natural gas produced in the U.S. would serve electric power plants, 

compared to just under one-third today.
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 2 

Natural Gas Supply

This report largely takes as a given the expansion of natural gas production arising from shale-based 

supply and the idea that the industry could provide enough natural gas supply. Yet there remain issues 

and uncertainty that could affect this supply, as well as its price.

Expanding production of shale-deposited gas is attracting environmental concern and in some cases 

local opposition to gas drilling due to its use of a technique known as hydraulic fracturing. Fracturing 

injects large amounts of water and chemicals into a well to crack open rock formations and then hold 

the cracks open so that natural gas can flow up the well. EPA and others are studying the potential 

adverse impacts of hydraulic fracturing. 

Even if fracturing continues, serving a much larger market will require even more drilling that is already 

at record levels. The implied supply curve reflecting the cost of new reserve additions developed herein 

suggests natural gas prices in the range of $10 per MMBtu to replace the reserves consumed last year. 

The Energy Information Administration’s AEO 2010 projects a gas price in 2036 of $8 per MMBtu with 

production not much higher than in 2000; a study for the Interstate Natural Gas Association of America 

includes a Base Case that projects $6.96 per MMBtu ($ 2008) with production in 2030 of roughly 27 Tcf. 

In other words, these studies show relatively high natural gas prices at demand levels generally more 

modest than reviewed herein. With these observations in mind, it seems unwise to expect to serve 

demand levels that are potentially very much higher than today without sending prices to much higher 

levels.

Transmission Infrastructure

To deliver the 60 or so Bcf we use each day from the supply basins where gas is produced to the 

end-users who will burn it, we use 300,000 miles of natural gas transmission pipelines and associated 

facilities that provide 130 Bcf per day interregional transfer capability. Nearly half the capacity we have 

today was built AFTER the industry achieved its previous peak demand of 22+ Tcf in 1972. The new 

capacity was needed in part to increase flexibility and to serve shifting regional markets, but primarily it 

was needed because old supply areas depleted and new ones were developed in other regions. 

Estimates of new pipeline capacity required range from $106 Billion to $163 Billion in one industry 

study. This study escalates those estimates to $348 Billion should all coal-fired generation need to be 

replaced with natural gas-fired generation. In looking at existing capacity, 21 states would find the 

interstate pipeline capacity coming into their state insufficient to serve existing demand plus the 

demand that would result from converting existing coal-fired generation to gas. These kinds of 

infrastructure investments are typically financed and recovered in rates over an extended period of time 

and are expected to continue being used and producing revenue for the owners for years after that. 

The magnitude of the investment that would be needed (as described in this report) seems inconsistent 

with the oft-touted idea of natural gas as a temporary “bridge” fuel. 
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Storage Infrastructure

For the electricity industry to broadly switch its coal-fired units to natural gas, it will also need more gas 

storage capability. Geology limits opportunities to build storage where the market would prefer it. 

Because of that, the current 400 or so storage facilities are not distributed evenly across the country and 

many of those facilities are single season reservoirs—rather than higher deliverability salt cavern-based

facilities. 

Areas without much storage include: Nevada, Idaho and Arizona, the Central Plains states, Missouri 

and virtually the entire East Coast (except far upstream in western New York, western Pennsylvania 

and West Virginia). Pipelines that have little access to storage include: Florida Gas Transmission, Kern 

River Gas Transmission, Southern Natural, Transco, Iroquois, Maritimes & Northeast, Alliance, Gas 

Transmission Northwest, Northern Border, Trailblazer, Transwestern, El Paso Natural Gas, and Williston 

Basin Pipeline. Scaling storage up to meet double the current electric generation (EG) gas burn implies a 

need to add 1.4 Tcf of storage. Adding this amount at the average $9 Billion per Tcf derived from a 

study done for the Interstate Natural Gas Association of America (INGAA) would thus cost close to $12.5 

Billion.

Operational Considerations

The natural gas industry operates using a lot of conventions developed to serve primarily residential, 

commercial and industrial customers. For example, natural gas is scheduled, or “nominated,” many 

hours before electric dispatch decisions are made. Tariff provisions that require transporters to match 

nominations to their usage (i.e., keep their deliveries into a pipeline in “balance” with the amount of gas 

they actually use) are not customized to provide the additional flexibility electric generators need. 

Canada’s Province of Ontario helped electricity generators and the gas pipelines develop innovative

ways of addressing these issues. Such innovations need to be considered in the U.S. if we are to burn 

much more gas for electricity generation. 

Also to be considered is the issue of curtailment. Curtailment halts delivery of natural gas: large 

customers like electricity generators are typically looked to by local gas distributors’ gas control 

operations as the first to curtail should supply or pipeline capacity run short. Those that are located 

along pipelines where capacity is tight often have back-up fuel capability, usually diesel fuel or residual 

fuel oil that they plan to be able to burn for only a few days. Most generators, however, do not have 

alternate fuel capability. 

Hurricanes present another consideration. Even small storms cause crews to be evacuated from 

offshore drilling and production platforms. Traders bid up prices anticipating damage. Massive storms 

can cause significant damage to natural gas production infrastructure in the Gulf. For example, as a 

result of Hurricanes Katrina and Rita in 2005, 80% of U.S. offshore production (which is approximately 

10% of U.S. total production) remained shut-in for a couple of weeks after Katrina, and again after Rita. 

Two key studies, including one by Sandia National Laboratories’ National Infrastructure Simulation and 

Analysis Center, state that the disruption from the storms was not to consumer deliveries, but was 

absorbed by a reduction in deliveries to gas storage. Those studies, however, do not assess how that 
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 4 

impact could be different if coal-fired generation switched to natural gas. It also turns out that winter 

2005-2006 was extraordinarily mild; had a normal cold or colder-than-normal winter occurred, gas 

consumers in the Midwest, MidAtlantic and Northeast might have experienced winter month natural 

gas curtailments. 

Finally, many electric utilities today burn little or no natural gas to generate electricity and don’t have 

trained staff on hand to address these matters. They will need to obtain trained staff or purchase 

external expertise to manage natural gas procurement, plan their interstate pipeline capacity 

commitments, and much more closely follow natural gas market developments. They will need staff to 

“carry the pager” to manage daily nominations and imbalances. They will need to deal with price 

volatility and risk management on a scale that most have never done before.

What Retrofitting Coal Plants to Burn Natural Gas Means 

The electricity industry can theoretically switch to natural gas either by retrofitting existing coal-fired 

units to burn natural gas or by closing the coal plants and building new gas-fired plants. Aspen’s 

research uncovers no instances of coal plant retrofits to natural gas and, in fact, virtually all of the public 

references to conversion of coal to natural gas or repowering turn out instead to be replacements. The 

reason is economics. Even the U.S. Government Accountability Office (GAO), when it looked at this 

issue switching the Capitol Building power plant to natural gas, noted that not only was switching all U.S. 

coal-fired generation infeasible due the gas supply and infrastructure required, but that it would be 

more cost-effective to construct new gas-fired units than to retrofit existing coal-fired units to burn 

natural gas. Combined-cycle gas-fired generation costs roughly $1 million per MW, installed. Replacing 

335,000 MW of coal-fired generation thus should cost in the range of $335 billion. 

Additionally, even if gas-fired units are built to replace existing coal-fired units, many utilities likely still 

have outstanding debt service on the coal plants that must be covered. Most plants are financed over a 

20- or even 30-year period and roughly 30% of the existing fleet is 30 years old or less. The need to 

complete paying off this debt and the impact on utility cash flow needs to be recognized as part of the 

cost of replacement.
Aspen Environmental Group Page 5

Implications of Greater Reliance on Natural Gas for 

Electricity Generation

Introduction

This report—Implications of Greater Reliance on Natural Gas for Electricity Generation—was 

commissioned by the American Public Power Association (APPA), with financial support from the Utility 

Air Regulatory Group (UARG) and other electric utilities.1 

The report provides a review of the natural gas industry for those who are less familiar with it. It will 

outline the range of and characteristics of current natural gas demand and how demand might change 

under different regulatory scenarios, particularly those under which it will be increasingly difficult for 

electric generators to operate their coal-fired generation. This report will largely take as a given the 

expansion of natural gas production arising from shale deposits; however, it will highlight uncertainty 

and environmental issues associated with this supply. It will review gas transmission and distribution 

infrastructure with an eye towards changes required to utilize that infrastructure to serve more demand 

and demand with characteristics different than it was built to serve. In that vein, it will describe some of 

the obstacles that electric generators face in managing the services they need in order to burn natural 

gas in power plants. These issues vary regionally, depending on the infrastructure available regionally 

and the flexibility or non-flexibility of that infrastructure to serve electric generation load. The gas 

system was not designed or built to serve electric generators. As will be seen later herein, many 

jurisdictions have not yet confronted the fact that electric generation remains the first off the system 

should a constraint or curtailment arise, which as we rely more heavily on natural gas to generate 

electricity could affect electricity reliability. The study provides information for policy makers and 

potential new users of natural gas about what kind of equipment would be needed to switch current 

coal-fired generation to natural gas: what would it cost to make the switch; what is the feasibility of 

such a switch; and how much natural gas would be required. 

 

1

 APPA represents public power utilities across the country. UARG is a voluntary, nonprofit, unincorporated 

ad hoc group of individual electric utilities and trade associations; UARG’s general purpose is to participate on 

behalf of its members collectively in the rulemakings of the Environmental Protection Agency and related 

litigation. 
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Definitions and Scale

A number of terms that may be unfamiliar or that 

are hard to mentally picture as to scale will be used 

herein. Natural gas demand when expressed 

annually will typically be in trillion cubic feet (Tcf). 

Daily demand is annual demand divided by 365 and 

will be expressed in billions of cubic feet (Bcf) per 

day or million British Thermal Units (MMBtu) per 

day. Cubic feet are a unit of volume, whereas Btus 

are a unit of heat. The heat content (or, Btus per 

cubic foot) varies by the source of the gas such that 

different pipelines will carry gas with a slightly 

different heat content. For the sake of simplicity, all 

calculations in this study will use 1.05 Btu per 

thousand cubic feet (Mcf). 

Prices for natural gas are expressed in the 

wholesale market and in most gas purchase agreements as $ per MMBtu. Most consumers will see on 

the bill from their local gas company a price expressed in cents per therm.2Some consumers will see 

the wholesale cost of gas broken out separately on their bill from distribution and margin and some will 

not. 

Another industry convention is to express pipeline capacity in terms of MMcf per day delivery capability. 

The bottom line is that the industry prices and buys gas in $ per MMBtu but usually measures capacity 

to deliver it in MMcf. Quantities more than 1,000,000 MMBtu will typically be expressed as Billion Cubic 

Feet (Bcf) and then Trillion Cubic Feet (Tcf). Bcfd means Billion Cubic Feet per day. MWs is MegaWatts 

of capacity available to generate electricity; MWh is energy, or the number of MWs times the number of 

hours those MWs were delivered. Last, but not least, in the gas business M means 1,000 but in the 

electricity business it means Mega, or one million. 

Some hints and comparisons of scale:

 Average household consumption of natural gas is 69 MMBtu (Dth) per year, or 5.75 MMBtu per 

month. 

 A new combined-cycle natural gas-fired power plant (NGCC), in contrast, typically uses between 

7 and 7.5 MMBtu to generate a MWh of electricity. In other words, the NGCC generates a single 

MWh using about 1.3 times what a household uses in a month.

 Annual U.S. natural gas consumption is in the range of 22 to 23 Tcf per year, depending on 

weather. 30% of that natural gas is used to generate electricity.

 A standard 36-inch large-diameter natural gas pipeline typically delivers 1 Bcf per day.

 

2

 Some gas utilities bill in hundreds of cubic feet, or ccf, instead of therms.

Useful Conversions: 

10 therms = 1 Decatherm (Dth) 

1 Dth = 1 MMBtu 

10,000 MMBtu = 10 MMcf/1.05 

Ex: 80 MMcf ... add three zeros and 

multiply by 5% = 84,000 

 The only real difference between an 

MMBtu and an Mcf is the heat 

content of the gas (1.05) and the 

number of zero’s (scale).
Implications of Greater Reliance on Natural Gas for Electricity Generation

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 That same pipeline can serve roughly six 1000 

MW gas-fired plants if the plants operate all at 

full output all 24 hours in a day. 

 Current coal-fired electric generating capacity 

in the U.S. totals approximately 335,000 MW. 

That capacity operated in 2008 at an average 

72% load factor to produce 1,985,801 GWh of 

electricity.3

 A new 1000 MW gas-fired combined-cycle 

power plant that operates all 24 hours in a day 

(i.e., at a 100% load factor) will consume 

approximately 168,000 MMBtu per day. That’s 

enough gas to serve 890,000 households for a 

day. 

 Using new combined-cycle gas-fired units to 

replace the 1,985,801 GWh generated with 

coal in 2008 would have required 13.2 Tcf 

more natural gas – more than half again what we consume now.

4

 

3

 Sourcewatch showed 335,840 MW for 2005 (its latest available); EIA shows 337,300 nameplate capacity versus 

313,200 net summer capacity in 2008. We rounded to 335,000 MW. 

4

 The 2008 net generation from coal is taken from EIA’s Electric Power Monthly, Table 1.1., Net Generation by 

Energy Source.

A new 1000 MW combined-cycle 

gas-fired unit that operates all 24 

hours in a day will burn 168,000 

MMBtu per day.

Converting to annual Tcf ...

120,960 MMBtu per day x 365 days 

=

44,150,400 MMBtu per year

=

42,048 MMcf per year

=

0.042048 Tcf per year
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Natural Gas Demand

The U.S. used approximately 23 trillion cubic feet (Tcf) of natural gas in 2009. Sectorally, the 23 Tcf 

breaks down roughly to 30 percent each consumed by i) residential and commercial consumers, ii) 

industrial consumers and iii) electric generators. The remaining 10 percent is consumed by 

miscellaneous uses such as fuel to operate processing facilities, pipeline and distribution system 

compressors, and as natural gas vehicle fuel. Annual natural gas demand by sector back to 2001 is 

shown in Figure 1.

Residential demand is highly seasonal. It is often projected 

largely on the basis of number of households and projected 

heating degree days. Residential demand per household has 

been trending slightly downward over time owing to more 

energy efficient new home construction standards and 

weatherization retrofits to existing homes.5 Without growth in 

the number of households, total residential natural gas demand 

would be falling.

Figure 1: Natural Gas Demand by Sector Since 2001

Source: EIA Natural Gas Annual

 

5

 According to EIA’s Residential Energy Consumption Survey, of the 111 million U.S. households in 2005, 69.4 

million used some amount of natural gas.

0.00

5.00

10.00

15.00

20.00

25.00

2001 2002 2003 2004 2005 2006 2007 2008 2009

Trillion Cubic Feet

Residential Commercial Industrial EG Other

A box large enough for a 

basketball or kickball can 

hold close to 1 cubic foot of 

natural gas. The average 

home uses 66,000 of those 

boxes worth of natural gas 

in a year. 
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Residential natural gas demand is not particularly sensitive to price, as confirmed by numerous studies; 

it may be as low as -0.12, meaning that a 1% increase in price produces a 0.12% decrease in demand, 

although the elasticity varies some regionally.6 In the West and South, annual total gas bills are a very 

small portion of consumer household budgets. Customers rarely get real-time price signals owing to the 

timing of billing periods relative to when the local distributor purchased the gas. In many jurisdictions, 

the local distributor may not be able to change the cost of gas seen on the customer bill without 

regulatory approval; surprisingly, not all utilities even have pass through mechanisms on their gas costs. 

Even during periods of relatively high spot prices, residential demand appears to be more weather 

responsive than price responsive. The key driver for residential demand is weather-related demand 

associated with space heating. 7

Commercial demand is similar to the residential sector. It is weather-sensitive since it is largely a 

function of floorspace and due to efficiency increases doesn’t show large changes over the long-term. 

Demand by industrial and electric generation (EG) customers has changed more than that of residential 

and commercial sectors. Industrial demand tends to not vary by season but was sufficiently price 

sensitive that it has declined significantly over time. Higher natural gas prices beginning around 2000 

eliminated considerable industrial demand. At roughly the same time, the use of natural gas to 

generate electricity began to grow with the move to deregulated markets and the rise of merchant 

generators who could relatively quickly site, finance and build combined-cycle natural gas generating 

stations. Industrial demand declined by nearly 20% from 2000 to 2009 (from 7.3 Tcf down to 6 Tcf). 

During the same period EG demand rose, picking up the most of difference, rising from 5.3 Tcf in 2000 to 

6.8 Tcf in 2009. EG demand typically causes a slight secondary peak each July and August (on the Pacific 

Coast it is more August and September). The increase in air conditioning load during summer heat 

waves can also be enough to move natural gas prices, either regionally or at Henry Hub.8 Hot weather 

combined with other events such as a nuclear outage, pipeline outage, or dry hydro-electric conditions 

(usually either the Pacific Northwest or California) can cause larger price spikes. 

Residential and commercial demands make natural gas a winter-peaking market. Transportation and 

distribution capacity (covered in Section 4) is adequate to serve current winter peak demand. Figure 2 

shows how the highly seasonal residential and commercial sector demands drive the peak in total 

 

6

 See, for example, M. Bernstein and J. Griffin, “Regional Differences in the Price-Elasticity of Demand for Energy,” 

Prepared for the National Renewable Energy Laboratory, Subcontract Report NREL/SR-620-39512, February 2006. 

Bernstein and Griffin estimated short-run residential sector elasticities of -0.03 for the West South Central census 

region and -0.18 for the Pacific Coast census region. The American Gas Association (AGA) recently published 

updated short- and long-term price elasticity estimates based on data from its members but it is only available to 

non-members for a fee.

7

AGA, INGAA and others sponsored a highly-publicized study arguing that increased direct use of natural gas will 

reduce primary energy consumption, consumer energy costs, and national CO2 emissions. The study can be found 

at: 

http://www.gastechnology.org/webroot/app/xn/xd.aspx?it=enweb&xd=GTISolutions/ClimateChange/reducingcar

bonemissions.xml .

8

 Henry Hub is a location in Louisiana where the Sabine Pipeline interconnects with as many as twelve other 

pipelines and gathering systems. It is used by the New York Mercantile Exchange as the physical delivery point to 

settle gas futures contracts. The Henry Hub price is recognized as a national benchmark price.
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 10

demand across the months. The Figure’s blue line is total demand, including the industrial and EG 

sectors (which are not otherwise shown, for emphasis). EG’s slight summer uptick is also readily visible 

in the “total” line. 

Figure 2: Illustrating Peak Nature of Monthly Natural Gas Demand

Source: EIA Natural Gas Monthly

Today’s annual total demand is only slightly higher (1 Tcf, or 4.5%) than the previous peak set in 1971 of 

22 Tcf. Natural gas demand declined substantially after the 1970’s Energy Crisis; schools and factories in 

Indiana, Ohio and Illinois spent days closed in the winter of 1976-1977 because gas was unavailable due 

the winter season in general or because the back-up fuel they had selected was unable to reach them 

due to bad weather. People were told that there wasn’t enough natural gas; in 1978 Congress enacted 

new laws to encourage efficiency, preclude the use of natural gas as a boiler fuel in new facilities, and 

deregulate wellhead prices.9Recession and higher prices for natural gas also influenced fuel choices. By 

1981, natural gas demand was less than 75% of what it had been in 1971. From the peak in 1971 it took 

nearly 25 years for the industry to get back to its prior annual peak.

A key purpose of this study is to raise awareness about how demand for natural gas could change with 

the possible promulgation and implementation of new regulations. The most prominent and most often 

studied is carbon regulation, but carbon is only one of the regulations electric utilities expect to have to 

address between now and 2017. Other pending regulations pertaining to “conventional pollutants” 

such as sulfur dioxide, nitrogen oxides, particulate matter, mercury, coal ash, etc., will also impose 

 

9

 These included the Fuel Use Act, the Public Utilities Regulatory Policy Act, and the Natural Gas Policy Act.

-

500,000 

1,000,000 

1,500,000 

2,000,000 

2,500,000 

3,000,000 

Jan-01

Jul-01

Jan-02

Jul-02

Jan-03

Jul-03

Jan-04

Jul-04

Jan-05

Jul-05

Jan-06

Jul-06

Jan-07

Jul-07

Jan-08

Jul-08

Jan-09

Jul-09

Monthly MMcf Delivered

Commercial Residential
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 11

compliance costs. Compliance with these regulations could require control equipment ranging from 

scrubbers, activated carbon injection, baghouses, and electrostatic precipitators, depending on the unit. 

The range of potential regulations is summarized in Figure 4, a graphic (not produced by Aspen) that has 

been extensively circulated amongst the electric utility industry and regulators.

Figure 3: Annual Natural Gas Demand and Supply since 1930 

Source: EIA Natural Gas Annual

While this study will not further evaluate those regulations or the associated potential compliance costs, 

utilities are already talking about how the costs to retrofit existing coal-fired units (with the scrubbers, 

baghouses and electrostatic precipitators mentioned above) in order to comply with these regulations

will cause utilities to consider whether to make the retrofit or instead switch to an alternative source of 

generation. In particular, the utilities are typically comparing the cost of retrofitting coal-fired 

generation to meet any one of these regulations with switching to natural gas.10 Compliance with these 

rules, cumulatively, even before considering carbon regulation, is more likely to change the relative 

economics of electric generation; as coal-fired generation becomes more costly relative to others, 

utilities will modify the mix of resources they use to meet customer load.

 

10

 For examples of comparative economics among control technologies see, J. Cichanowicz, “Current Capital Cost 

and Cost-Effectiveness of Power Plant Emissions Control Technologies,” Prepared for the Utility Air Regulatory 

Group, January 2010; or Woods, et. al., “Cost and Performance Baseline for Fossil Energy Plants,” National Energy 

Technology Laboratory, August 2007. 

0

5

10

15

20

25

193019331936193919421945194819511954195719601963196619691972197519781981198419871990199319961999200220052008

Trilion Cubic Feet

Dry Production Consumption
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 12

Figure 4: Timeline for Potential EPA Rules Affecting Electric Power Plants

Source: Provided by APPA
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Exactly what changes will be made by utilities—and how they will drive demand for natural gas—will 

depend on what assumptions electric generators make concerning the level of electricity load growth 

they think they will see, the amount of energy efficiency they think they will achieve, how much success 

they think they will have in adding generation from renewable sources, and how much new nuclear 

capacity will be built. It also depends on whether one believes that geologic carbon capture and 

sequestration (CCS) will be commercially deployable and available to utilities in locations with diverse 

geology, the price at which CCS will be available, whether one allows the models to retrofit old units to 

accommodate CCS technology, and the level of any carbon emissions caps. If a cap and trade program is 

adopted via legislation, gas demand will be affected by the number of allowances granted, by the 

number of offsets available, and by any restrictions that are placed on the use of offsets and allowances

in achieving compliance with carbon limits. 

Table 1 summarizes the results of five different studies done over the last two years that contain 

projections of the electricity industry’s generation resource mix, including natural gas demand. The 

studies reach different conclusions about natural gas demand because they make very different 

assumptions about likely future load growth, how much can be achieved by increases in energy 

efficiency, how much generation will be produced by renewable energy sources (Renewables), and how 

much new nuclear generation will be built.

11 All of these things have an impact on how much natural 

gas the industry will burn to generate electricity.

The first and second studies—done in 2008 and 2009—are EPA analyses of S. 2191, Senators Lieberman 

and Warner’s cap and trade bill, and of H.R. 2454, passed by the House of Representatives and 

sponsored by Representatives Waxman and Markey. EPA’s analyses looked at the impacts of cap and 

trade for carbon emissions. It is unclear whether EPA also assumed implementation of the proposed 

Clean Air Interstate Rule (CAIR) but it does not appear to have assessed the possible effects of other 

regulations identified in Figure 4 that might affect electric generators in the foreseeable future. EPA’s 

S. 2191 analysis (denoted EPA L-W in Table 1) contains load growth of 0.8%.12 This is roughly half the 

actual load growth experienced on average over the last twenty years. EPA allowed new nuclear 

generation and increased renewable generation. Coal-fired generation is displaced and by the end of 

the study period about two-fifths of what remains is retrofit with CCS.13 Natural gas-fired generation 

increases, both in relative and absolute terms, to represent 25% of the resource mix as compared to its 

 

11

 Renewable energy sources generally means generation using wind, solar thermal, solar photovoltaic, 

geothermal or biomass resources. As discussed in more detail later herein, each of the studies turns out to use 

different assumptions as to which Renewables make up the bulk of the renewable generation they assume to be 

available. 

12

 “EPA Analysis of the Lieberman-Warner Climate Security Act of 2008,” March 2008 found at 

http://www.epa.gov/climatechange/downloads/s2191_EPA_Analysis.pdf. The published analysis went only to 

2025; in extending it to 2030 Aspen recognized that nuclear and Coal CCS had met their resource limits, thus 

requiring new generation added to meet load be gas-fired. While Aspen tends to refer herein to load growth as an 

“assumption,” we well understand that the models typically iterate back and forth between prices and load to 

reach an equilibrium result. They may employ an assumption about energy efficiency but some of the change in 

demand is also price response. EPA’s later analysis of Waxman-Markey attempted to better tease out of the 

analysis the difference between conservation and price response.

13

 CCS is first deployed by 2015 and reaches its maximum availability limit by 2025.
Implications of Greater Reliance on Natural Gas for Electricity Generation

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current 21%, using an additional nearly 4 Tcf of natural gas per year. This represents an increase in the 

use of natural gas to generate electricity of approximately 60%. (If the projected use of the “tools” used 

to reduce emissions, including allowances and offsets, nuclear generation, Renewables, CCS or control 

of load growth turns out to be unachievable, then natural gas use would theoretically be higher.)

Table 1: Comparison of Various Studies’ EG Resource Mix and Resulting EG Gas Burn

2008 EPA L-W EPA W-M AEO 2010

Duke 

CCPP

INGAA

(Base)

Annual Load Growth 1.5% 0.8% 0.41% 1.00% 0.2% 1.4%

Share of 2030 Load Served By:

 Nuclear 20% 24% 23% 17% 20% 21%

 Renewables 3% 13% 11% 11% 20% 8%

 Coal 48% 18% 37% 44% 13% 40%

 Coal CCS 0% 12% 3% 0% 20% 2%

 Natural Gas 21% 25% 19% 21% 21% 23%

 Petroleum 1% 2% 2% 1% 1% 1%

 Hydroelectric 6% 5% 6% 6% 6% 5%

Total Resources14 100% 100% 100% 100% 100% 100%

Gas Burn for EG in 2030 (Tcf) 6.915 9.3 6.8 8.3 6.0 9.8

Gas Burn for EG in 2036 (Tcf) 6.9 10.7516 7.7 8.8 7.4 n/a

Total U.S. Gas Demand 22.9 26.7 23.7 24.8 23.4 28

 Source: Aspen Analysis

EPA’s analysis of H.R. 2454 (denoted EPA W-M in Table 1) shows even smaller load growth, only 0.41%.17

Such lower load growth combined with the number of domestic and international offsets allowed under 

Waxman-Markey, combined with the purchase of allowances at relatively low prices, led EPA to 

conclude that the industry would be able to meet its emissions targets with far less drastic changes to 

the resource mix. Nuclear generation increased to 23% of the portfolio and Renewables to 11%. Much 

less coal was retrofit with CCS, only 3% of the coal-fired fleet, but up to its assumed capacity limitation. 

Coal was not displaced as much as under the S. 2191 analysis, with the overall result that natural gas’ 

market share did not increase and in fact was reduced to 19% of the portfolio. While a reduction in 

relative terms, this 19% still represents an increase in natural gas demand by electric generators of 

approximately 0.8 Tcf per year by 2036. Should the low load growth, access to offsets and low 

allowance prices not occur, the gas burn would presumably be higher unless other more economic 

 

14

 Totals may not add to exactly 100% due to rounding.

15

 6.9 Tcf is the 2008 natural gas burn for electricity generation.

16

 EPA’s study of Lieberman-Warner contained projections out to 2025; the 10.75 Tcf is taken from a simple 

projection extending that analysis.

17

 “EPA Preliminary Analysis of the Waxman-Markey Discussion Draft,” April 2009 found at 

http://www.epa.gov/climatechange/economics/pdfs/WM-Analysis.pdf
Implications of Greater Reliance on Natural Gas for Electricity Generation

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options were available to reduce emissions. The H.R. 2454 analysis does not appear to have included 

other EPA regulations affecting electric utilities that were identified in Figure 4.

The third study—EIA’s latest Annual Energy Outlook (AEO 2010)—projects increased natural gas use in 

electric generation of about 2 Tcf by 2035 and total U.S. natural gas demand of approximately 24 Tcf. 

Notably, EIA’s analysis did not assume regulation of carbon emissions or the adoption by EPA of other 

regulations limiting emissions from fossil-fired generation such as those shown in Figure 4. Nonetheless, 

the Outlook’s increase in gas use is attributable “to growing concerns about GHG emissions [that] make 

[gas] more attractive than coal and because new natural gas-fired plants are much cheaper to build than 

new renewable or nuclear plants.”18 In other words, anticipation and discussion of potential regulation 

leads utilities to switch some of their resource decisions away from coal-fired generation. 

The fourth study—done by Duke University’s Climate Change Policy Partnership at the Nicholas School 

of the Environment (Duke CCPP)—used the same National Economic Modeling System (NEMS) used by 

EIA but updated some assumptions about natural gas supply to see what impact that might have on the 

natural gas market, including demand for electric generation.19 The key update was perhaps not the 

oft-cited update to the assumptions about shale-deposited natural gas: the shale gas update turns out 

to be relatively minor in that Duke CCPP merely updated the reserves available from the Haynesville 

Shale to assume they would ultimately match those known to exist in the Barnett Shale.20 Assumptions 

regarding other shale-deposited reserves and production were not updated. The Duke CCPP study also 

constrained LNG imports and updated generation construction costs relative to EIA. The biggest change 

from EIA’s modeling was to obtain from NETL an add-on to NEMS that allows NEMS to evaluate the 

economics of carbon capture and sequestration retrofits to existing coal-fired generation.21 In addition, 

Duke CCPP shows very little load growth: only 0.2% per year. The Duke CCPP study modeled ten 

scenarios, including a business-as-usual case with no carbon regulation, carbon regulation with the 

updates described above, and then various combinations of higher and lower gas extraction technology 

and electric generation technology development. 

The general result—which did not consider what the impact on electric generators would be if EPA were 

to adopt the other new regulations depicted in Figure 4 from coal generating units—was only a small 

increase in demand for gas-fired generation. Nuclear generation remained relatively constant, owing to 

its high cost relative to alternatives. Coal-fired generation decreased and was replaced by Renewables, 

most of which are biomass. Approximately 60% of the coal-fired generation that remained in place was 

 

18

 EIA, AEO 2010 Early Release, Report #: DOE/EIA-0383(2009), p. 10. EIA says it assumes only existing laws in 

preparing the AEO but Administrator Newell explained in a March 1 presentation to the OECD in Paris that a 

premium was added to the capital cost of CO2-intensive technologies to reflect market behavior in advance of 

possible CO2 regulation.

19

 Hoppock, Dave, Patrick Bean and Eric Williams (Duke University, Climate Change Policy Partnership), The 

Influence of Technology and a Carbon Cap on Natural Gas Markets, 2009.

20

 The Haynesville shale is located largely in Louisiana; the Barnett shale in Texas. Figure 7 shows all of the U.S. 

shale-deposited gas supply production areas.

21

 Op. cit., p. 13
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assumed to be retrofit with CCS technology.22 The net result is little change in the amount of natural 

gas burned to generate electricity: 0.5 Tcf. Duke CCPP did prepare a scenario in which it assessed the 

possibility that CCS, either new CCS or retrofit to existing coal- and gas-fired units, might not be available 

or deployable until after 2030. That scenario shows change increase in the gas burn relative to the main 

S. 2191 case but it also assumed low natural gas technology development. Duke CCPP’s “High natural 

gas technology development/low electric technology development” case shows a 2030 gas burn nearly 

30% higher than in its main S. 2191 case, or just over 9.5 Tcf.

The fifth study—which the Interstate Natural Gas Association of America (INGAA) released in October 

2009—was performed on INGAA’s behalf by ICF International.23 ICF, via Energy and Environmental 

Analysis (acquired by ICF in 2007), has long provided demand, supply and infrastructure projections to 

INGAA, the American Gas Foundation and the former Gas Research Institute (now Gas Technology 

Institute). It also performed a good portion of the modeling reported in National Petroleum Council 

studies dating back to 1992. ICF uses its own Gas Market Model (GMM). 

The INGAA study assumed electricity load growth more consistent with the recent past than the EPA, 

EIA or Duke CCPP studies: 1.4%. The base case adds 25,000 MW of nuclear generation yet its share of 

the generation portfolio on a percentage increases only slightly, owing to load growth. Renewable 

capacity triples, but only contributes 8% of the portfolio. Coal adds 40 GW and the new coal is fitted 

with CCS; on a percentage basis, however, its share of the resource portfolio shrinks from 48% today to 

42% by 2030. Natural gas adds 260 GW of capacity and operates in more hours of the day to increase its 

load factor; its share of the electric resource portfolio grows to 23% from 21% today. Because the 

overall electricity market is larger due to the assumed level of load growth, this seemingly small 2% 

increase in natural gas’ market share represents an increase in annual natural gas demand of nearly 4 

Tcf over current levels: 6.9 Tcf in 2008 versus 9.8 Tcf in 2030, which represents nearly a 40% increase in 

the EG gas burn. Total U.S. gas demand winds up at approximately 28 Tcf, or 20% higher than today.

Some interesting observations can be drawn by comparing these studies. For example: 

 EPA’s analysis of Waxman-Markey sets load growth at about half what the agency assumed a 

year earlier when they analyzed Lieberman-Warner. In fact, the much lower gas burn projected 

 

22

 Duke CCPP added CCS to about 160,000 MW of the 262,000 MW of coal-fired capacity projected to exist in 

2030, but did not break out in the results the MWh generated by CCS capacity versus non-CCS coal-fired capacity. 

(Compare Duke CCPP Figure 12 to Figure 13A.) In addition, Duke CCPP shows a total of 220,000 MW of capacity 

implementing CCS. Given that the study projects only 160,000 MW of that to be on coal-fired generation, the rest 

must be presumed to be applied to natural gas-fired generation.

23

 ICF International, “Natural Gas Pipeline and Storage Infrastructure Projections Through 2030,” INGAA 

Foundation, October 2009. Found at http://www.ingaa.org/cms/31/7306/7828.aspx. We will come back to the 

INGAA study when we discuss infrastructure additions; the study represents analysis performed on behalf of the 

interstate gas pipelines as to capacity additions required to serve expected gas load. Its demand scenarios are 

conservative relative to some that we will evaluate in contemplation of switching coal-fired generation to natural 

gas and thus is only a starting point for the required gas transmission and storage capacity additions.
Implications of Greater Reliance on Natural Gas for Electricity Generation

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under Waxman-Markey appears due primarily to the difference in the load growth 

assumption.24 

 Duke CCPP’s analysis assumes virtually no load growth (0.2%): that and increased Renewables 

leads to little change in the gas burn but a big change in the contribution by coal. No reader 

should doubt the significant impact that the load growth assumption makes on the need for 

portfolio additions and how much gas must be burned. Note that none of the studies, largely 

due to its assumed cost, add very much nuclear power with the exception of EPA’s original 

analysis of S. 2191, which added virtually a plant per year. 

 INGAA has load growth most consistent with historical reality, which also means it didn’t allow 

much in the way of energy efficiency. Its higher load growth combined with a much more 

conservative addition of Renewables to the portfolio results in a gas burn that is almost as high 

as under EPA’s analysis of Lieberman-Warner. Of course, that analysis would show a still higher 

gas burn than either it does or INGAA does if it increased load growth from the assumed 0.8% to 

the more historically consistent 1.4% INGAA uses while holding all other resource assumptions 

constant. 

The point of comparing these studies is that one needs to not 

look only at the conclusions the studies reach about the gas 

burn, but look at how the studies reached that conclusion. 

Many, if not most, of the resource mix assumptions embedded 

in the studies are highly uncertain; some may not be 

achievable in terms of the availability of certain resources or 

access to carbon offsets and allowances. In fact, it is unlikely 

that any one of these cases will turn out to match reality. Even 

the natural gas industry’s own analysis of its future (as 

embodied in the work of the National Petroleum Council) has 

varied considerably as reality turned out to be different from 

the industry’s assumptions as to its resource base and other 

factors.25 Again, these analyses by and large do not consider 

the effects of the other regulations depicted in Figure 4 that electric utilities may face.

 

24

 The other reason Waxman-Markey shows less of an increase in the natural gas burn is because it allows 

regulated entities to use domestic and international offsets to help achieve carbon compliance. This study will 

define the role of offsets in more detail later herein. If those offsets are not available or if electric utilities cannot 

obtain them, in the quantities assumed, then the gas burn may well be higher.

25

 Note, for example, the marked change in tone from the 1999 National Petroleum Council Study touting the 

natural gas industry’s ability to serve a 31 Tcf market albeit needing to face some “challenges” in order to do so 

(not the least of which was its complaints about federal land off limits to drilling), to the 2003 study “Balancing 

Natural Gas Policy,” and then to the 2007 study “Facing the Hard Truths About Energy” that natural gas supply is 

declining with little hope of increasing production. Of course, then came shale production and a new radically 

different view of production possibilities. 

Without the combination of 

low load growth, high 

Renewables, the availability of 

geologic CCS and use of 

allowances and offsets, it 

looks impossible to meet 

carbon targets without 

burning much more natural 

gas. If those assumptions do 

not hold, the resulting EG gas 

burn is much higher.
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 18

Table 2 provides five additional scenarios developed by Aspen that are designed to further highlight the 

point that different assumptions about the electricity resource mix drive the projected natural gas burn. 

The additional scenarios evaluate different combinations of some of the resource mix results shown in 

the Table 1 studies. Accordingly, the five additional scenarios do not necessarily represent economic 

dispatch of electricity generating plants or economic resource additions. Rather, they are merely “what 

if” scenarios represented in an annual energy balance built initially from the mix EPA projected in its 

analysis of Waxman-Markey as shown in Table 1.26 Nuclear and renewable resources are typically 

changed first, then coal-fired resources. Natural gas is “on the margin” and picks up whatever remaining 

difference might exist between supply and demand so that all demand is met. To reiterate, the analysis 

says nothing about cost; the point was to recognize that the resource assumptions reflected in the 

studies summarized in Table 1 may not hold and to see what kind of changes to the mix—without 

worrying about what could cause those changes or how probable they might be—would create much 

higher natural gas burns.

Table 2: Range in Projected EG Natural Gas Burn and Total Demand

Alternative Resource Mix Comparisons

1 2 3 4 5

Annual Load Growth 1.00% 0.41% 0.41% 0.41% 0.41%

Share of 2030 Load Served By:

 Nuclear 19% 23% 23% 23% 23%

 Renewables 9% 20% 20% 20% 20%

 Coal 31% 35% 28% 13% 5%

 Coal CCS 2% 3% 3% 3% 3%

 Natural Gas 33% 12% 19% 35% 43%

 Petroleum 2% 2% 2% 2% 2%

 Hydroelectric 5% 6% 6% 6% 6%

Total Resources 100% 100% 100% 100% 100%

CO2 Emissions in 2030 (million tons) 2,669 2,082 1,912 1,574 1,344

Gas Burn for EG in 2030 (Tcf) 11.9 4.1 6.8 11.0 13.8

Gas Burn for EG in 2036 (Tcf) 13.8 5.1 7.7 12.5 15.1

Total U.S. Gas Demand 29.8 21.1 23.7 28.5 31.1

 Source: Aspen Analysis

Scenario 1 is built starting with the load-resource mix projected by EPA in analyzing Waxman-Markey. In 

that analysis EPA assumed load growth of 0.41%. We tested what the mix looks like if load growth is 

instead assumed to be higher: 1%. 1% is higher than what EPA assumed but still lower than the 

historical average of 1.5%. We left all other resources at the levels projected in EPA’s analysis but 

increased gas, as our assumed marginal resource, to pick up the increased load. The percentages 

 

26

 An energy balance merely stacks up hours generated by available sources and compares the total resource 

hours available to energy demanded. It shows whether resources are sufficient to meet all demand and 

summarizes how that demand will be met.
Implications of Greater Reliance on Natural Gas for Electricity Generation

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contributed by each resource are slightly lower than shown in Table 1 for the EPA W-M scenario 

because these are the percentages that result in 2030, which reflect that 1% load growth. The resulting 

EG gas burn is 13.8 Tcf (compared to 6.9 Tcf in 2008).27 

Scenarios 2 through 5 revert to the 0.41% load growth used by EPA. In Scenario 2 we pushed 

Renewables to 20%.28 No other non-gas resources were changed; their relative percentages shift 

slightly because of the lower load growth assumption. With the lower load growth and the increase in 

Renewables, resulting gas burn is 5.1 Tcf. In short, lower load growth and serving 20% of that load with 

Renewables cut the EG gas burn from 13.8 Tcf to 5.1 Tcf, a vast difference. Emissions are lower than 

either what EPA projected or in Scenario 1, but still use offsets (that may not ultimately exist) to achieve 

carbon compliance. 

Scenario 3 tries to get emissions lower. It does that by 

keeping the load growth, nuclear generation and 

Renewables the same, but switches some coal for natural 

gas. In fact, the reduction in coal-fired generation it tests is 

5% per year. This brought natural gas use back up to 

7.7 Tcf to match what EPA showed in its Waxman-Markey 

analysis, but carbon emissions from the electricity industry 

are too high, meaning that generators would have to buy 

lots of allowances in order to achieve compliance under 

this resource mix. Scenario 4 cuts out more coal-fired 

generation and replaces it with gas. Other resources hold 

their respective resource portfolio market shares. The gas 

burn increases to 12.5 Tcf but the emissions are finally low 

enough (1,600 million tons) that generators would not 

have to buy so many allowances to achieve carbon 

compliance.

29 Scenario 5 goes further still, cutting out most but not all coal. With all other assumptions 

the same, the natural gas burn goes to 15.1 Tcf. (CO2 emissions would fall to 1,344 million tons.)

We need to ask another question. What would the gas burn be if all existing coal-fired units were 

required to switch to natural gas? Scenario 5 did not address quite that question because it still left 5% 

of the existing coal-fired capacity in place (and allowed load growth). The electric industry has 

approximately 335,000 MW of existing coal-fired capacity. These plants are located as shown in Figure 

5. Switching all 335,000 MW to gas (at an assumed heat rate equal to that of a new NGCC and running 

the NGCCs at the 72% load factor of the existing coal-fired fleet – slightly more than 16 hours per day)

 

27

 This scenario actually produces carbon emissions in 2030 that are higher than EPA projected as compliant with 

the caps so either the industry has to obtain a lot of offsets or some further change would need to occur to reduce 

the carbon emissions, likely some sort of further substitution of Renewables or nuclear to back out some coal.

28

 Aspen selected 20% for illustrative purposes; it is somewhat consistent with a potential national Renewable 

Portfolio Standard and is the same figure used by Duke CCPP. 

29

 The point is not that buying allowances is a “bad” way to achieve compliance but to highlight the tradeoff 

between gas burns and allowance prices. 

Gas Burn if All Coal-Fired 

Generation Switched to Gas: 

335,000 MW * 7 

MMBtu/MWh * 24 hours * 

365 days ...

* .72 Capacity Factor

Now convert to TCF by 

dividing by 1.05 MMBtu/cf

and 1,000,000,000 

= 14.1 Tcf
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 20

results in a natural gas requirement of 14.1 Tcf.30 Add to that the gas being burned in the gas-fired units 

that exist today—another 6.9 Tcf—and total natural gas demand for electric generation ends up at 21.0 

Tcf. Adding in other sectors’ gas demand yields a total natural gas demand of 37.1 Tcf per year, half 

again (or more precisely, 61%) more than current annual natural gas demand of 23 Tcf. This result is 

captured in Table 3.

Table 3: Natural Gas Demand if All Coal-Fired Generation Replaced with Gas at Current Electricity 

Market Size/No Growth

Tcf

2008 EG Gas Burn 6.9

EG Gas Burn if All Existing Coal-Fired Generation Replaced31 14.1

 Subtotal EG Gas Burn 21.0

All Other Sectors 16.1

Total Annual Natural Gas Demand if All Existing Coal-Fired Generation 

Replaced 37.1

Source: Aspen Analysis

 

30

 This is lower than the 15.1 Tcf gas burn estimated in Scenario 5 because Scenario 5 allows load growth. 

Scenario 5 would be even higher if it removed all coal.

31

 Assumes load factor of 72%, equal to what EIA reported for coal-fired generation’s 2008 load factor. Using 

generated GWh instead of MW of capacity and simply multiplying by a gas-fired unit’s heat rate also yields a 

required gas burn of roughly 14 Tcf.
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Figure 5: Location of Existing U.S. Coal-Fired Generation (By County)

Source: EIA (http://www.eia.doe.gov/cneaf/electricity/page/capacity/capacity.html)
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 22

There is another factor in addition to the resource mix changes that is at play in the analyses that 

consider carbon regulation but project little increase in the natural gas burn. Note that not all of the 

scenarios in Tables 1 or 2 necessarily get the electric industry down to its so-called pro rata “share” of 

carbon reductions.32 The gas burn estimated in the analysis of Waxman-Markey, in particular, relied 

heavily on the purchase of additional allowances and offsets, as Waxman-Markey allowed as many as 

2 billion tons worth of domestic and international emissions 

offsets to count towards carbon compliance. (By way of 

background, in a cap and trade-type program one can think 

of allowances as essentially “tickets,” given out by a 

government implementing cap and trade, allowing one to 

emit. A utility can emit as much CO2 as it has allowances to 

cover. If it doesn’t have enough allowances it can choose to 

either reduce its emissions or purchase allowances thirdparties.33) Offsets provide additional “tickets” from outside 

the cap and trade program and are an important tool in 

trying to make sure that emissions reductions are achieved 

from the most cost-effective sources. They can be created 

when one takes an action NOT required by regulation that 

has the effect of reducing CO2 emissions. Planting trees to 

take up CO2, for example, could create an offset. The offset is verified by a third-party and documented 

on a piece of paper and, of course, must meet the conditions of being permanent and incremental to 

other actions; it is given value because some governments will count it towards carbon compliance like 

an allowance. Thus, activities outside the CO2 regulatory program can reduce emissions, thereby 

defining offsets that emitters can theoretically either create or buy, and then “turn in” along with their 

allowances to cover their carbon responsibility. The more offsets available, the lower the price of 

allowances (since an offset is a substitute method for achieving carbon compliance). The lower the price 

of allowances, the less economic it is and the less need for a utility to switch away from burning coal and 

the lower the cost of implementing carbon regulation. 

The purpose of highlighting the role of allowances and offsets is to emphasize that if a final cap and 

trade program does not allow offsets or if the electricity industry cannot get the offsets because other 

industries obtain them first, then more drastic resource mix changes would be needed in order for the 

electricity industry to achieve carbon compliance. These more drastic resource mix changes, such as 

those shown in Mix 4 and 5 of Table 2, entail much higher natural gas burns than assumed in other 

analyses of the impacts on the industry of carbon regulation. To repeat: if the offsets do not materialize 

or utilities cannot get them, then allowance prices will be higher and the gas burn will be higher.

 

32

 EPA’s analysis of Waxman-Markey showed a reduction in carbon emissions from the electricity industry of only 

10%, to 2,180 tons, by 2025 and relatively low allowance prices. See, Executive Summary, page 6, found at 

http://www.epa.gov/climatechange/economics/pdfs/WaxmanMarkeyExecutiveSummary.pdf

33 A utility should buy allowances and continue to emit CO2 when the cost of allowances is less than its cost to 

reduce emissions. From an economists’ perspective, the purpose of cap and trade is to create a market so that 

utilities and parties can compare the cost of emitting versus reducing emissions and transact to achieve the leastcost mix of emissions and reductions.

Many of the analyses looking 

at carbon regulation had lots 

of offsets, which pushed the 

price of allowances down, and 

the electric utilities achieved 

compliance by buying these 

lower-prices allowances and 

offsets. If those assumptions 

do not hold, the industry will 

likely achieve compliance by 

burning more gas.
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 23

Some of the gas-fired merchant generators have argued that carbon emissions could be reduced 

immediately if we simply directed the utilities to turn down coal-fired generation in favor of gas-fired 

merchant capacity that has been built but that is not currently being dispatched.34 These are largely 

combined cycle plants not operating at full capacity. The Congressional Research Service (CRS) 

performed a study of this question and released its results in January 2010.35 CRS found that the 

underutilized existing natural gas combined cycle (NGCC) plants operated at an average capacity factor 

of 42% in 2007. Doubling that capacity factor to operate at 85% could theoretically displace 32% of 

2007’s coal-fired generation. But then CRS asked about the locations of the plants: are the gas-fired 

plants located near the coal-fired plants they would be replacing? This pertains to whether the gas-fired 

plants could deliver their output to the same markets as the coal-fired plants they are replacing without 

adding new transmission capacity.36 CRS found that 60 of the 298 plants coal-fired that met its study 

criteria were located with 10 miles of one of the underutilized gas-fired plants. (Those 298 plants 

represented 98% of 2007’s coal-fired output and the 60 plants located within 10 miles of an 

underutilized gas-fired plant represented 5% of 2007’s coal-fired output.) 9% of the coal-fired units 

were located within 25 miles of one of the underutilized coal-fired plants.37 The emissions that would 

be eliminated by backing down those coal-fired units and operating the gas-fired units at a higher 

capacity factor total 3% to 5% of CO2 emissions from coal-fired generation. 

Overall, Aspen concludes that it is important to understand how the various studies, largely focused 

solely on carbon cap and trade, arrived at their conclusions about the amount of natural gas likely to be 

burned by electric generators. Whether it be expectations about constructing nuclear capacity, the 

amount of Renewables added, how much energy efficiency is achievable and how consumers will 

change their load patterns in response to higher prices, or whether geologic or other CCS will be 

available and how much it will cost, and whether the electric industry can purchase enough allowances 

or offsets, each constitutes a critical assumption subject to uncertainty. Aspen’s analysis shows that 

even in a scenario with low load growth and 20% Renewables, the combination of no new nuclear 

power and lack of CCS, means that for the electricity industry to reach emissions of around 1,500 million 

tons by 2030 it will have to burn a lot more natural gas than any of the major studies has projected. 

 

34

 Merchant generators are plants, usually NGCCs, built by an independent generator rather than a utility for the 

purpose of selling electricity via bilateral contracts or into competitive market exchanges. 

35

 Kaplan, S. “Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants,” Congressional 

Research Service, January 2010.

36

 The author’s experience working on financing of merchant power plants is that while many may not have firm 

supply or transportation contracts to support operations at an 85% capacity factor, most likely have delivery 

interconnections that are physically sized large enough to deliver that much gas and at least looked at being able 

to meet load equal full output for 24 hours on an interruptible basis. Accordingly, additional gas transmission 

capacity to support these plants may not be necessary. Electric transmission, however, would only have been 

assessed or required to deliver power into the control area which is not the same as getting it to the load center of 

the utility phasing out its coal plant. 

37

 Op. cit., p. 17
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Summary Observations Related to Natural Gas Demand

1. Current natural gas market size is 23 Tcf.

2. 30% is consumed by the residential and commercial, industrial, and electric 

generation sectors, respectively. 

3. Residential demand is highly seasonal; demand per household is declining but the 

growing number of households keeps annual use for the sector fairly constant. 

4. Space heating use during winter months by the residential and commercial sectors is 

responsible for the seasonal shape of natural gas demand. 

5. Virtually all expected growth in natural gas demand will occur in the EG sector.

6. EG causes a small upward blip in summer natural gas demand; summer heat waves 

change demand by enough to move prices.

7. The EG sector burned 6.9 Tcf of natural gas in 2008.

8. EIA’s AEO 2010 projects EG natural gas demand to increase by approximately 2 Tcf 

by 2030 even if carbon regulation is not adopted.

9. Other projections of natural gas demand in 2030 for the electricity sector range 

from 6.8 Tcf to 10.7 Tcf.

10. These electricity sector demand projections—which generally did not consider the 

additional regulations under consideration by EPA that will also encourage fuelswitching—are highly dependent on assumptions about electricity load growth, 

whether new nuclear power is built, the amount of renewable generation, whether 

CCS is commercially demonstrated and deployable for new plants or retrofits, and 

the number of offsets allowed to count towards carbon responsibility.

11. Changing these assumptions results in estimates ranging from 4.1 Tcf to 13.8 Tcf in 

2030.

12. Switching all 335,000 MW of existing coal to natural gas today would create 

additional natural gas demand of 14.1 Tcf; EG demand, including existing gas-fired 

generation, would total 21.0 Tcf. 

13. Adding in other sectors creates a 2030 natural gas requirement of 37.1 Tcf, some 

61% larger than with the current electric resource portfolio.

14. The potential for additional EPA regulation of other hazardous pollutants and 

construction costs are encouraging some utilities to switch to gas now.
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Natural Gas Supply

Natural gas supply consists of reserves in the ground and the ability to produce flowing supply from 

those reserves. EIA reports estimates of proved reserves each year based on the results of producer 

surveys. “Proved” reserves are determined based on drilling into a formation and represent an estimate 

of what could be produced with reasonable certainty at current prices and regulation.

38

 Those 

estimates are usually, but not always, conservative relative 

to what the formation ultimately produces. Proved 

reserves grow when drilling information allows additions to 

reserves in excess of that year’s production. As shown in 

Figure 6, annual proved reserves fell from 1973 until the 

mid-1990s but have grown every year since. At the end of 

2009 EIA reported proved reserves of dry natural gas of 245 

Tcf. 

Probable, possible and speculative resources are tracked by 

the Potential Gas Agency at the Colorado School of Mines 

and the U.S. Geological Survey. The Potential Gas Agency 

announced in June 2009 year-end 2008 probable, possible 

and speculative resources of 1,836 Tcf.39 Probable, possible 

and speculative reserves are categories of increasing 

uncertainty found in existing fields, new fields, and frontier 

areas with little prior drilling, respectively. They are 

additive to the proved reserves reported by EIA, but unlike proved reserves the market prices needed to 

drill these reserves is unknown. One should understand that changes in market prices affect the 

estimate of proved reserves: higher prices allow probable reserves to move into the proved category. 

The corollary of this point is that the resource base is vast: producing enough gas is only a matter of 

being willing to pay the price needed to drill and process it ready to flow into a pipeline.

Turning reserves into flowing supply rests with individual producer decisions to drill production wells. 

Individual producers tend to specialize their investments into geologies and technologies to produce 

from a certain geology. Devon Energy, for example, was a pioneer in producing the Barnett Shale. 

Encana specializes in tight gas formations in the Rockies. Other companies tend to specialize in the deep 

water Gulf, for example. 

 

38

 Proved reserves are defined by the Securities and Exchange Commission (SEC) in Rule 4-10 of Regulation S-X. 

The definition was revised slightly January 1, 2010. For a detailed discussion of the changes, see SEC Release No. 

33-8995.

39

 The press release can be found at http://www.mines.edu/Potential-Gas-Committee-reports-unprecedentedincrease-in-magnitude-of-U.S.-natural-gas-resource-base. Approximately one-third of the total is shale-deposited 

gas.

Proved reserves are those that 

have been drilled enough to 

allow reasonable certainty in 

the eyes of accountants and 

engineers that they can be 

produced at current prices. 

U.S. proved reserves are 

enough to last ten years if we 

continue to use what we used 

last year.

Probable reserves require 

more drilling to confirm the 

size of the deposits and 

production rates.
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Drilling decisions are generally cyclical. That is, when prices are high, producers have higher profits and 

spend more on drilling. When prices are low, profits are lower and producers cut back on drilling. 

Exxon-Mobil’s retired chairman Lee Raymond said that the oil and gas business is all about technology. 

Technology drives the ability to understand formation characteristics and the drilling techniques applied 

by producers. Technology improvements allow production to increase at lower cost. Technology 

improvements also allow reserves that were only probable to be “proved up” and brought into 

production. This is what has happened with the shale formation gas now being produced. New 

technologies were tested and developed successfully in the Barnett shale in Texas and are now being 

applied to shale formations across the continent. Among these technologies is the application of 

horizontal drilling (diagonally across pay zones instead of straight down) combined with new ways of 

fracturing the shale rock and then propping it open to allow gas to collect and flow through the crack 

and up the well bore.

Figure 6: U.S. Annual Proved Reserves of Dry Natural Gas40

Source: EIA, U.S. Crude Oil, Natural Gas and Natural Gas Liquids Annual Report 2008 

Producers face anti-trust penalties for sharing too much information among themselves, not to mention 

their technologies, and lease acreage positions are at the core of what they see as a proprietary “leg-up” 

on competitors. As a result, producers do not share strategies or drilling plans. Being optimistic risktakers by nature, producers tend to believe that they possess the next great formation that will be a 

great winner for their company. They ALL believe that. And they believe they can beat the producer 

down the road at the next leasehold or in the next basin and get their production to market first. The 

result is that when prices are high, producers collectively over drill; eventually the industry ends up with 

 

40

 Dry reserves are the most common reference; they are reserves with the small amount of associated water and 

petroleum liquids removed.
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more gas than is demanded. This is what transpired in 2008 and 2009. Combine that in 2009 with the 

onslaught from the recession, and you have lower demand at the same time you have higher 

production. The result is that prices then fall. This effect is seen looking at monthly natural gas spot 

prices: from the peak price in July 2008 of $13.98 per MMBtu prices fell to $1.98 per MMBtu in late 

September 2009.

The Role of LNG

The story about large quantities of proved and probable 

reserves that exist and the logic about drilling them into 

production is as true world-wide as it is in the U.S. It is also

true that producers drill where they possess technological 

and geological expertise, looking for the least-cost 

opportunities worldwide. The rush to build terminals so 

that liquefied natural gas (LNG) could come to the U.S. was 

driven by the fact that world-wide, producers had gas in 

excess of what they could market, some of it from 

geographic locations in which there was no indigenous 

market or insufficient indigenous market to use all of the 

gas. At the same time, shipping costs and liquefaction 

costs declined such that it became possible to chill into 

LNG, transport it in a ship (generally known as “transship”), 

regasify it (i.e., heat it back to ambient air temperature so 

it returns to its gaseous state) and inject into a U.S. 

pipeline where there was a market with transparent, liquid 

and reasonably well-understood prices. 

While developers worked to build terminals in the U.S. and terminals in Canada and Mexico that could 

reach the U.S. or local markets (several were built) three things happened. The first is economic growth 

in Asia such that markets there contracted for large portions of the LNG. The second is that various 

events (e.g., an accident to a supply train in Algeria, the postponement of liquefaction construction in 

Indonesia, delays in investment in Australia due to cost increases) reduced the quantity of LNG expected 

to be available. The third is the current “excess” of supply relative to demand in the U.S., driven by the 

recession combined with the increase in production, that has pushed prices lower. U.S. natural gas 

prices have sunk lower than prices at the U.K. National Balancing Point (which drives Atlantic LNG) and 

have opened up a significant gap on a Btu basis relative to crude oil (which drives Pacific LNG).41 The 

apt observation is that LNG could become relevant in the U.S. again if the relationship between U.S. 

 

41

 The U.K. National Balancing Point is akin to Henry Hub in the U.S. in that it is the most liquid gas trading point in 

Europe and creates a benchmark price. It is used as the pricing and delivery point of the Intercontinental Exchange 

gas futures contract but is a virtual, rather than actual physical interconnection location.

While on the subject of LNG, 

note that this study’s sponsors 

have members located in 

places where there is no or 

very limited natural gas. These

include Puerto Rico, American 

Samoa, the Virgin Islands, 

Guam and Hawaii. (Alaska’s 

Cook Inlet region has local 

natural gas production but 

declining production is making 

it difficult for electric utilities to 

get natural gas.) For coal-fired 

plants in these locations to 

switch to gas they would need 

that gas to arrive as LNG. 
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natural gas prices, crude oil, and the U.K. National Balancing Point narrowed. Should U.S. production 

falter, those price gaps should indeed narrow and LNG would become more relevant to the U.S. market. 

Uncertainty about Shale Production

While it is clear that there are plenty of natural gas reserves in the U.S. that can be produced, we don’t 

know for the probable reserves what price it will take or what technology will be required to bring them 

into production. Even for the shale-deposited gas that has the industry abuzz there are issues that could 

make its production less, rather than more, certain.

Extraction Technology

As indicated above, shale production depends on use of a technique known as hydraulic fracturing, or 

simply “fracing.” Shale is a sedimentary rock that is porous enough to hold gas but not permeable 

enough for the gas to move through the rock very well. Drilling horizontally across the formation 

exposes maximum gas-containing rock to the well bore. Then water and chemicals (known as fracing 

liquid) are pumped down the well bore at high pressure to fracture open cracks through the shale. In 

the next stage sand and compounds with latex-like properties are injected to hold the cracks open for a 

long period of time.42 The cracks then allow the gas to flow towards the well bore and ultimately up the 

well.43 Figure 7 shows the location of major geologic basins containing shale gas deposits. 

 

42

 The liquid used to hold or “prop” the fractures open for the gas to flow are known as “proppants.” 

43 The actual fracturing is done by what is known as a well services company. Halliburton, Schlumberger, and 

Baker-Hughes are examples of well-known well services companies. Different companies that do fracturing use 

different chemicals and additives to the injection fluid. These different chemicals and their properties are 

considered proprietary, much like a given producer’s geo-technical expertise about a given geology is considered 

proprietary. Press reports sometimes compare the proprietary nature of the recipe to the concept of protecting 

the secret recipe for Coca-Cola.
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Figure 7: Shale-Deposited Gas Supply Basins
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Environmental Concerns

The Final Impact Assessment Report produced for the New York City Department of Environmental 

Protection (NYCDEP) cited the fracturing process involving “pumping three to eight million gallons of 

water and 80 to 300 tons of chemicals into *a+ well at high pressure over the course of several days.” 44 

Half or so of the injected solution returns back up the well. The water that flows back up the well also 

tends to contain hydrocarbons and dissolved solids such that it must be disposed of via underground 

injection or industrial treatment (i.e., conventional wastewater treatment is not feasible). The injection 

water is usually trucked in. The NYCDEP study estimated 1,000 or more truck trips per well to haul in 

water and equipment and then haul out wastewater. In addition, as production from a given well falls 

off, the fracturing process is repeated. Some shale gas production wells require refracturing every 5 

years, and the useful life of a well may be 20 to 40 years such that fracturing will be an ongoing process 

rather than something that occurs only when the wells are originally drilled. 45

What worries residents and others about hydraulic fracturing is that it uses a fair amount of water, 

causes lots of truck trip activity over the life of the well to bring in water and take some of it back out, 

and that it injects chemicals underground at high pressure. The chemicals that are added contain some 

amount of materials that may be toxic and residents are fearful that these chemicals might migrate and 

potentially contaminate drinking water supplies.46 Some of the production areas are closer to urban 

areas (such as Dallas/Fort Worth‘s location in the heart of the Barnett Shale) or to their water supplies 

(such as New York City’s long-standing preservation and use of the Marcellus Basin watershed for 

drinking water). There are also stories like the one of a couple in Colorado whose water well exploded, 

emitting flames out of the top of the well, after fracturing was done on several area wells.47 

Increasingly, residents seem to be opposing local drilling. 

While New York City’s environmental concerns seem most related to the quality of its Marcellus basinsourced drinking water, other regional water resource agencies indicate concern about the quantity of 

water used to support shale-deposited gas production. The industry points out that the water used to 

bring up well drilling mud (“mud,” comprised of sand, water and chemicals, that lubricates the drill bit 

and carries rock cuttings and debris up the well bore as drilling continues) is less than for other sources 

 

44

 New York City Department of Environmental Protection, “Final Impact Assessment Report,” December 2009, p. 

ES-1.

45

 One difference between shale-deposited gas wells and conventional wells is their production profile. Both 

shale, tight gas and coalbed methane formations produce more of their gas in the first few years, then taper off to 

very low levels for a long period of time. Conventional wells exhibit a similar but much less pronounced decline 

pattern. 

46

 Similar concerns are often raised about carbon dioxide injection. The drilling techniques are largely the same 

technology, whether used for shale-deposited gas, CO2, or geothermal but applied to different geology. Different 

companies tend to be expert at understanding different geologies and formations, which leads to protection as to 

what exact techniques are being used. With respect to fracing, the composition of chemicals used and their 

proportions relative to each other are considered trade secrets. 

47

 “Drilling Process Causes Supply Alarm” The Denver Post, November 17, 2008 found at 

http://www.denverpost.com/breakingnews/ci_11001835 or see Amos’ complete story at 

http://www.earthworksaction.org/cvLauraAmos.cfm .
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of energy, per MMBtu produced, and that it is less than other regional uses.48 A Fact Sheet put out by 

natural gas producer Chesapeake Energy (Chesapeake) refers to using an average shale gas well 

requiring as much as 600,000 gallons of water and an average of 4.5 million gallons over the life of the 

well. 5 million gallons is the amount of water New York City uses in seven minutes. Chesapeake notes 

that the water used for developing shale-deposited gas represents a 1.5% increase in water use in each 

shale area. Use of the water is said to not represent a 

long-term commitment of the resource in contrast to the 

case with most other uses of water. Chesapeake points 

out that the water used is purchased and where required, 

permitted, which ensures that it does not interfere with 

the supply of water available to other users. 

The National Energy Technology Laboratory (NETL)

produced in 2009 what it called “a primer” on shale gas 

development. It cited 3 million gallons of water as most 

commonly needed for drilling and hydraulic fracturing of horizontal shale gas well, noting that the 

volume can vary substantially between wells.49 Wells in the Barnett shale take the least amount of total 

water to drill and fracture (2.7 million gallons per well) while wells in the Marcellus take an estimated 

3.9 million gallons. NETL also noted that the volume of water per foot of wellbore may be decreasing 

with development over time of new technologies to produce shale-deposited gas. 

Even Texans, who are known for being tolerant of inconveniences and impacts created by oil and gas 

drilling, have some complaints about drilling in the Barnett Shale. The Texas Commission on 

Environmental Quality (TCEQ) conducted tests in December 2009 in response to resident complaints of 

toxic emissions and odors from wells drilled into shale deposits. Some of the emissions were allegedly 

benzene and tests paid for by the Town of Dish in Denton County found benzene emissions five times 

the long-term exposure limit.50 TCEQ’s own tests reportedly found no emissions over limit but the 

testing and discussion continue.

The 2005 Energy Policy Act exempts fracing from regulation under the Safe Drinking Water Act (SDWA). 

Fracing isn’t just used to produce shale-deposited gas but is also used in the “tight” gas formations 

common to producing areas in the Rockies supply area (generally Colorado, Wyoming, and eastern 

Utah) and in producing coal-bed methane. In 2004 EPA reviewed studies about the impacts of fracing 

and concluded it was safe.51 EPA also entered into a Memorandum of Understanding with Halliburton, 

 

48

 Chesapeake Energy, “Water Use in Deep Shale Gas Exploration,” Fact Sheet March 2010. Found at 

http://www.chk.com/Media/CorpMediaKits/Water_Use_Fact_Sheet.pdf

49

 “Modern Shale Gas Development in the United States: A Primer,” U.S. Department of Energy National Energy 

Technology Laboratory, April 2009, p. 64. Another useful briefing paper is available from the California Energy 

Commission: “Shale-Deposited Natural Gas: A Review of Potential,” CEC 200-2009-005-SF, February 2010.

50

 Fort Worth Star-Telegram, “Tests Find Emissions of Fort Worth Drilling Sites Don’t Exceed Standards,” January 

12, 2010. 

51

 The study is available at http://www.epa.gov/ogwdw000/uic/wells_coalbedmethanestudy.html. Aspen has not 

reviewed it in detail but notes that it applies to coal bed methane wells and that carbon dioxide is sometimes used 

as part of the proppant.

Wells to produce shale-deposited 

gas are fractured upon initial 

production and then may be refractured five or six times over the 

life of the well to keep production 

going. These wells often produce 

50% or more of their gas early in 

their first year of production. 
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Schlumberger and other well services companies (who are the ones that actually provide the fracturing 

services) providing that the companies would stop using diesel fuel as part of the fracturing liquid in 

coal-bed methane wells. Concerns about fracing and its exemption from the SDWA have led to the

introduction in Congress of legislation to repeal that exemption in what is known as the Fracturing 

Responsibility and Awareness of Chemicals (FRAC) Act.52 In addition, EPA announced in early 2010 that 

it will conduct a $1.9 million peer-reviewed study with significant stakeholder input into the potential 

adverse impacts of hydraulic fracturing. Without a comprehensive study it is difficult to assess whether 

the concerns are valid and what impact they might have on access to natural gas. 

Seismic Events

Hydraulic fracturing has been associated with some amount of increased seismic activity. Complaints 

about earthquakes believed to be caused by hydraulic fracturing have arisen in California, Texas and 

Switzerland. The California drilling occurred in an earthquake prone area 100 miles north of San 

Francisco. A Swiss project was found to have caused a magnitude 3.4 quake near Basel in 2006, also the 

site of previous significant seismic activity (a 6.7 magnitude quake in 1356 is said to have severely 

damaged Basel). The drilling in both these cases was related to geothermal energy projects in which the 

fractures would be used to pump water down to hot rock which would return to the surface as steam.53 

The information reviewed in preparing this report did not indicate what kind of proppants would be 

used to hold open the cracks created by the fracturing. 

Similar relatively small quakes have been reported in the Barnett Shale near Dallas-Fort Worth, an area 

unknown for seismicity. Seismologists at Dallas’ Southern Methodist University and the University of 

Texas, Austin issued a report in March 2010 finding those quakes to have been caused plausibly by the 

reinjection of water into a disposal well that activated a fault thought to be inactive.54 The quakes are 

said to have stopped once injection into the disposal well stopped. The scientists say they do not 

understand why other disposal wells did not cause similar quakes nor do they have a good 

understanding of the region’s underlying seismicity, presumably because of the infrequency of such 

events in north Texas. They also cited a lack of complete information about the subsurface structure in 

the area, including the porosity and permeability of the rock and the potential fluid path. A second 

study looking at quakes in and around Cleburn, Texas (located in the Barnett Shale, near Dallas/Fort 

Worth) remains underway.

 

52

 Exxon-Mobil’s agreement to purchase independent producer XTO Corp contains a clause allowing Exxon-Mobil 

to walk away if the FRAC Act passes. XTO’s production and expertise is largely in shale-deposited gas. The FRAC 

Act, among other things, requires disclosure of the chemicals used to fracture rock formations for producing gas. 

On April 13, 2010 Exxon-Mobil came out in support of public disclosure of fracing liquid compounds in a further 

effort to avoid legislation that would limit fracing.

53

 See, for example, “Geothermal Project Review Underway,” Lake County News, July 26, 2009. Found at: 

http://lakeconews.com/content/view/9681/764/ or “Deep in Bedrock, Clean Energy and Quake Fears,” New York 

Times, June 24, 2009. Found at: 

http://www.nytimes.com/2009/06/24/business/energy-environment/24geotherm.html . 

54

 Frolich, C., et. al., “Dallas-Fort Worth Earthquakes Coincident With Activity Associated With Natural Gas 

Production,” The Leading Edge, Volume 29, p. 270. Found at 

http://smu.edu/newsinfo/pdf-files/earthquake-study-10march2010.pdf
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Some suggest that production of shale-deposited gas will increase carbon dioxide emissions. It isn’t that

the methane (CH4) produced from shale deposits is not chemically different from other methane. 

Rather, the stream of compounds produced from a natural gas well actually contains a number of 

hydrocarbons besides pure methane. Those other hydrocarbons can be butane (C4H10), propane (C3H8), 

ethane (C2H6), pentane (C5H12), and others. The more of those heavier hydrocarbon molecules are 

contained in the gas stream, the higher the carbon content, which would create higher emissions. The 

relative mix of the different hydrocarbons varies by formation. Often, the heavier hydrocarbons (which 

are produced from the well as either a liquid or are easily condensed out of the gas stream, hence, they 

are known as “natural gas liquids” or condensates) are processed out of the gas stream and sold 

separately. Higher prices for natural gas liquids, all else equal, encourage producers to drill where the 

liquids content of the gas is higher.55 If markets for those products are not favorable or if little 

processing capacity is available, producers may leave some or all of the higher Btu-content substances in 

the gas stream. Combusting that gas would then emit more CO2 than average for natural gas. 

Natural gas production from shale formations is suggested by some to cause more CO2 emissions than 

production from conventional natural gas because of the water and hydraulic fracturing liquids being 

trucked into, and then away from, the drilling site. Cornell University’s Dr. Robert Howarth, for example,

has encouraged further study of this, pointing out that if we added to the standard estimates of CO2

emitted by combustion of natural gas the emissions associated with “development, processing and 

transportation of natural gas (due to the use of fossil fuels to build pipeline, truck water, drill wells, 

make the compound used in drilling and fracturing, and treat wastes and the loss of carbon-trapping 

forests) ...” as well as gas leaked “during production, transport processing and use,” then natural gas 

may not be “significantly better than coal in terms of the 

consequences for global warming.”56 An economy-wide program 

would seem to capture those emissions and one would expect the 

fugitive emissions should be calculated in the “Inventory of U.S. 

Greenhouse Gas Emissions and Sinks” compiled by EPA; Aspen has 

not found evidence that shale-deposited gas produces higher 

fugitive emissions than other natural gas production. This study 

highlights the point only to highlight that if such concerns turn out 

to be valid, they could become an impediment to production at 

high levels or acceptance of the use of shale-deposited natural 

gas.

Other issues around drilling contribute to uncertainty about our willingness to produce potentially much 

higher quantities of natural gas. 1999’s National Petroleum Council report indicated the natural gas 

 

55

 Casually, one does hear anecdotes that some of the current shale-deposited drilling is occurring in order to 

obtain the value of the higher liquids-content gas. 

56

 Howarth, Robert. “Preliminary Assessment of the Greenhouse Gas Emissions from Natural Gas obtained by 

Hydraulic Fracturing.” Found at 

http://www.technologyreview.com/blog/energy/files/39646/GHG.emissions.from.Marcellus.Shale.April12010%20

draft.pdf. To be fair, cap and trade programs proposed to date certainly do not ignore all of those emissions but 

have tended to deal with them outside the electricity sector.

If the Deepwater Horizon 

blowout and leak does 

not scuttle plans to drill in 

the OCS, production from 

any new wells that result 

from expanded OCS 

leasing is unlikely before 

2017.
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industry could serve a 30 Tcf market but that it needed federal lands off limits to drilling (including the 

Outer-Continental Shelf, or OCS) made available and the industry continues to deliver that message. 

While there are signs drilling may be expanded, other signs suggest otherwise. On January 6, 2010 

Interior Secretary Ken Salazar announced the Bureau of Land Management (BLM) would more carefully 

scrutinize applications for oil and gas drilling on federal lands and he reversed the approval of more than 

30 leases in Utah that many groups felt the Bush administration had rushed through approval without 

sufficient regard for the proximity to Arches National Park or other sensitive lands. 

President Obama and Secretary Salazar, on the other hand, announced on March 31, 2010 a 

Comprehensive Strategy for Oil and Gas Development and Exploration (Strategy). The Strategy would 

open some of the OCS to oil and gas drilling, including the southern portion of Minerals Management 

Service (MMS) Lease Area 181 off Florida’s Destin Beach and areas off the Mid and South Atlantic as well 

as areas off Alaska’s North Slope.57 Despite the Board of Supervisors in Santa Barbara County (the

location of an oil spill in 1968) having passed a resolution in 2009 in support of new oil and gas drilling 

off its own coast, California and the entire Pacific Coast remain protected as does Bristol Bay in 

southwestern Alaska. (See Figure 8.) The President’s Strategy will allow lease sales for the opened areas 

only after geologic and environmental studies are completed, not before 2012. As a result of the April 

20, 2010 Deepwater Horizon platform 50 miles off the Louisiana coast, current OCS drilling is on hold, 

safety reviews of existing rigs are underway, and the scoping meetings for the Virginia OCS lease sale 

were postponed (see Department of Interior May 6 press release). When the reformed MMS does get 

back to holding lease sales, it seems reasonable to expect greater scrutiny and analysis of environmental 

impacts and safety equipment as a result of the accident and the subsequent safety reviews. It remains 

to be seen if the spill will change public reaction and expectations about offshore drilling or drilling in 

general. One might also ask if any of the safety issues are pertinent to wells drilled for geologic CCS.

Notably, off-shore drilling is more technically complicated such that it is regarded as “unconventional” 

irrespective of whether the underlying rock formation is shale or tight sands or whatever it might be. In 

addition, the seismic data on these potential reserves is 30 years old, gathered before off-shore 

moratoria took effect, and until exploratory drilling is complete there is no way of knowing whether the 

reserves will produce profitably at current prices. Actual production is unlikely to occur before 2017. 

The intent is not to criticize off-shore drilling but simply to point out that the industry has made a point 

of saying it needed the OCS opened up in order to serve higher demand. Whether such drilling will 

occur is uncertain and it is unclear what new sorts of compliance mechanisms or their costs might be. 

 

57 MMS estimates put the technically recoverable undiscovered reserves made available if OCS exploration goes 

forward at 210 to 250 Tcf. Technically recoverable means that technology exists to produce the reserves but does 

not indicate at what price doing so would be economic. EIA prepared an “OCS Access” case in AEO 2007 and 

updated it for AEO 2009. Assuming virtually no change to regulations that affect the electricity resource mix, EIA 

projected access to off-shore resources would increase U.S. gas supply by a mere 3% compared to its Reference 

Case projections. Found at http://www.eia.doe.gov/oiaf/aeo/otheranalysis/ongr.html.
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Figure 8: Three New OCS Lease Areas Opened for Offshore Drilling (pending Deepwater Horizon review)
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Price Impacts

Natural gas prices are likely to rise as demand increases to work off the supply bubble created by the 

recession and recent over-drilling. Longer term, prices will depend on how much gas we need and the 

technology available to meet that demand. Over the past ten years prices generally rose (subject to 

temporary impacts from weather or economic conditions). In economists’ parlance, this largely 

occurred because we moved “up” the supply curve with enough new technology to replace production 

but not quite enough to shift the supply curve “out.” During that time, the data showed a pronounced 

decrease in production per new well (see Figure 9). The widespread application of techniques 

developed in the Barnett Shale to other shale formations, likely encouraged by 2007 – 2008’s higher 

natural gas prices, has reversed that, thus seeming to have finally shifted the curve out. Put differently, 

stagnant technology seems to result in falling production per new well and prices increase as a result; 

major technology improvements, on the other hand, allow production per new well to increase and the 

industry can produce more gas at previous price levels.58

Figure 9: Gas Production per New Well

Source: Aspen Analysis of EIA data from Natural Gas Annual

Using data reported to EIA for natural gas cost per well drilled for 2000 through 2007, Figure 10 shows 

the implied aggregate supply curve that results from simply plotting the trend line of the data. The 

suggestion is that proving up an additional 25 Tcf of reserves should cost well over $10 per MMBtu. The 

pattern at which higher levels of proved reserve additions increases is striking. Assuming U.S. gas supply 

 

58

 It is possible to use information about current well depletion rates (production from existing wells falls every 

year) and production per new well to compute how many wells must be drilled to achieve a given level of 

production. Aspen has not performed that calculation here; however, all else equal, a need to drill more wells 

implies higher natural gas prices.

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

1975 1980 1985 1990 1995 2000 2005 2010

Bcf per New Well
Implications of Greater Reliance on Natural Gas for Electricity Generation

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needs in the range of 30 Tcf, roughly consistent with scenarios 1 or 5 of the alternate resource mix 

scenarios presented in the Demand section of this study (or the 28 Tcf in the INGAA study’s Base Case), 

it seems hard to not advise consumers they should expect prices to return to the $10 MMBtu range.59 

By way of comparison, EIA’s AEO 2010 put prices at approximately $8 per MMBtu to produce 24 Tcf in 

2035 (see Table 1 of the Early Release). Note that it projected only a 2 Tcf increase to be needed over 

current production levels. Most of that increased production will consist of shale-deposited gas, along 

with North Slope gas transported via a new pipeline from Alaska. Imports, composed of pipeline gas 

from Canada and LNG, will decline.

The INGAA study’s Base Case put its U.S. benchmark price at $6.96 per MMBtu (in $ 2008) for U.S. 

production of approximately 27 Tcf. Its High Case put prices lower, at approximately $6 per MMBtu, 

but it did so assuming that the additional supply is produced with more Arctic gas, more LNG, OCS 

drilling, and that the decline in conventional supply levels out. One must surmise that the modelers 

assumed such sources would cost less than current conventional and unconventional supplies.

Figure 10: Implied Natural Gas Supply Curve Through 2007

Source: Derived by Aspen using EIA Reported Cost per Well Drilled

 

59

 $10 per MMBtu is more than double current prices, which are “low” due to the recession’s impact on demand 

combined with higher drilling and production.

-

2.00 

4.00 

6.00 

8.00 

10.00 

12.00 

14.00 

- 5,000 10,000 15,000 20,000 25,000 

Cost per Mcf Added ($2008)

Annual Reserve Additions (Bcf)
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Even with the ability to produce potentially plentiful natural gas supplies from shale deposits, the large 

amounts of shale-deposited reserves were added in a high price environment. Should the U.S. need to 

add proved reserves every year in the 25 to 35 Tcf range—more than the industry has ever added 

before—it simply does not seem credible to expect that prices would not return to the $7 to $10 per 

MMBtu range absent further cost-lowering technology improvements or unusual events. 
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Summary Observations Related to Natural Gas Supply

1. U.S. proved reserves of natural gas currently total 245 Tcf, enough to meet 2009’s 

annual demand of 23 Tcf for 10.6 years.

2. Proved reserves have increased by more than enough to cover annual production for 

each of the last 15 or so years.

3. Probable, Possible and Speculative reserves total 1,836 Tcf, enough should all of it 

become producible to meet 2009’s annual demand for nearly 80 years

4. Drilling investment increases when oil and gas prices are higher.

5. Producers collectively tend to overdrill when prices are high, leading to price cycles.

6. LNG deliveries to the U.S. are driven by the relationship between U.S. natural gas 

prices versus the U.K. National Balancing Point (Atlantic LNG) and crude oil prices 

(Pacific LNG).

7. Should U.S. natural gas production falter, those price gaps should narrow and LNG 

would again become relevant to the U.S. market.

8. Production of shale-deposited gas relies on a technique called hydraulic fracturing 

that is attracting increasing environmental concern and, in at least a few cases, some 

local opposition to natural gas drilling.

9. EPA announced in March 2010 that it is commissioning a peer-reviewed 

comprehensive study of the potential adverse impacts of hydraulic fracturing.

10. It is unclear how limits on drilling on federal lands, greater scrutiny in the review of oil 

and gas drilling applications by BLM or some opening up of the OCS to drilling will be 

addressed and whether they will increase or decrease natural gas drilling.

11. Production per new well has fallen virtually every year since 1975. The number of 

wells drilled and production pattern from shale-deposited gas may have stemmed the 

decreases, at least temporarily.

12. Production per new well and the rate of depletion of existing wells versus demand 

and imports is what determines how much natural gas the U.S. must produce.

13. The implied aggregate supply curve for 2000 through 2008 suggests that adding 

proved reserves of more than 25 Tcf per year requires natural gas prices of $10 per 

MMBtu or higher.

14. AEO 2010 projects a 2036 gas price of $8 per MMBtu (with production only 1 Tcf more 

than in 2009).

15. The INGAA study’s Base Case projects $6.96 per MMBtu ($ 2008) with production in 

2030 of roughly 27 Tcf. Even with access to shale deposited-gas, Aspen remains 

dubious of the ability to produce more gas prices lower than $6 per MMBtu without 

further cost-lowering technology improvements.
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Natural Gas Delivery Infrastructure

Natural gas is transported from producing areas to end-users all over the country through pipelines. 

Large-diameter, high-pressure trunklines use compression to push natural gas through the pipelines to 

the “citygates” of local distribution companies and large, direct-connect customers. Except in cases 

where natural gas is produced and transported to customers entirely within the state in which the gas 

was produced, natural gas is transported through interstate pipelines regulated by the Federal Energy 

Regulatory Commission under the Natural Gas Act.60 FERC does not regulate commodity natural gas 

prices but mandated beginning in the late 1980’s (culminating in Order No. 636) that interstate pipelines 

completely separate the function of selling natural gas from the function of transporting natural gas.61 

Pipelines must also facilitate the liquidity and transparency of a market for firm pipeline capacity by 

posting on a public bulletin board their list of shippers and offers by those shippers to buy and sell firm 

capacity. FERC does regulate transportation rates, the terms and conditions of all aspects of 

transportation service, and grant certificates of public convenience and necessity to construct new or 

expanded transportation capacity. Nearly two-thirds of states produce less natural gas than they 

consume and are therefore dependent on the interstate pipeline system to bring gas to their local 

distribution systems and end-users.

The natural gas pipeline system began its existence when two oil pipelines were built in 1943, known as 

the "Big Inch" and "Little Big Inch;" these pipelines were built to move oil via land from Texas to the 

Midwest and eastward to serve areas around New York City and Philadelphia, avoiding German U-Boats 

along the East Coast. The two systems were sold as war surplus to became Texas Eastern Transmission 

Corporation (TETCO) and converted to natural gas service in 1947.62 Today, the U.S. is served by more 

than 200 pipeline companies that own more than 300,000 miles of pipe delivering gas to all regions of 

the country, the configuration of which are shown in Figure 11. EIA reports that at least half of this 

capacity was built in the 1950s and 1960s. At that time most gas was produced in Texas, Oklahoma and 

the Gulf Coast; most pipelines originated there and delivered gas from there to the Midwest and 

Northeast. 

 

60

 Transmission pipelines that do not cross state lines and that are regulated by their respective states are known 

as “intrastate” pipelines. Most demand is served in Texas, for example, via intrastate pipelines. California’s large 

local distribution companies take a portion their gas supplies directly from local producers and transport it to 

end-users. Michigan Consolidated (MichCon) is directly hooked to local gas production. Intrastate pipelines are 

almost always regulated in some manner by a state regulatory commission.

61

 This was known as elimination of the “merchant” function of U.S. pipelines. To the extent that a pipeline 

continues to sell natural gas it must do so from a separate affiliate and the FERC imposes strict rules about what 

information can be transferred between the two companies. The purpose was to make transportation of natural 

gas a competitive, non-discriminatory service and remove any ability by the pipeline to force shippers to purchase 

gas from the pipeline.

62

 Handbook of Texas Online, found at http://www.tshaonline.org/handbook/online/articles/BB/dob8.html

(accessed March 12, 2010).
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Figure 11: U.S. Natural Gas Transmission Pipelines

Source: U.S. Department of Energy
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Most natural gas customers take service from a local distribution company (LDC). However, very large 

gas users, such as industrial facilities or electric power plants are often directly connected to a 

transmission pipeline. To some degree, whether a power plant is connected directly to a pipeline or 

instead to an LDC depends on which region of the country it is located. Plants in the West and newer 

merchant generator plants tend to be directly connected, while older plants and those in the East tend 

to be behind LDC citygates. In some cases, the LDC provides more flexibility in addressing imbalances or 

variation in gas use than available from the interstate pipeline. Importantly, while there are 

commonalities among the services offered by the various pipelines or LDCs, each is different. To 

understand what services and rules apply in a specific location, one must look at the tariffs of the 

specific pipeline or LDC in question.

As discussed earlier in this report, natural gas demand increased from 5 Tcf in 1947 to 22 Tcf by 1972. 

After that demand declined and did not match that 1972 peak again until the late 1990s. (See Figure 3.) 

During that time the natural gas industry was deregulated; natural gas commodity prices are now set by 

the market and the value of interstate pipeline capacity (not its cost, but its value) is also set by the 

market, measured in what the industry calls a “basis differential.”

63

 Efforts to encourage combined heat 

and power facilities led to the interest in electric industry deregulation and the rise of merchant 

generators. Natural gas demand has finally returned to its previous peaks largely due to the merchant 

generators’ business model, which is based on ease of financing, lower capital cost of gas-fired plants, 

modular sizing, better ability to ramp operations up or down to follow load, and relative ease of 

obtaining permits to site and operate gas-fired generation. 

Domestic production of natural gas also peaked in 1972. The gap that subsequently grew between 

supply and demand of domestic natural gas was met largely with gas from Canada’s prolific Western 

Canadian Sedimentary Basin. In addition, as production waned in old fields some new U.S. gas fields 

were developed: the Rockies and San Juan basins are examples of producing areas that were developed 

or expanded after the peak. These expansions required the addition of new pipeline capacity to bring 

these new supplies to market. Note that virtually all of the capacity added since 1972 has been to 

deliver increased supply from new production areas or to serve demand that moved from one region to 

another, all while U.S. aggregate demand has not grown much past the 1972 peak. The key observation 

is that new pipeline capacity has to be built whether demand increases or not as the producing areas 

change. The corollary should be that the ability to have added this capacity says nothing, necessarily, 

about the ability of the industry to build capacity to serve potentially massive new demand. 

Total existing pipeline capacity is large enough to meet peak day gas requirements. That means that on 

most days of the year, some pipeline capacity goes unused. Average pipeline utilization, for example, 

for the thirty largest U.S. pipelines in 2007 (latest year reported) was 59%.64 Each pipeline has a 

 

63

 FERC allows the secondary trading of interstate pipeline capacity on a transparent, non-discriminatory basis. 

Sometimes capacity trades for more than its tariffed cost and/or we see commodity price spreads between two 

locations open up that are more than the cost of transportation. When pipeline capacity carries an “economic 

rent,” we see the pipeline or other new entrants hold Open Seasons to propose new capacity.

64

 Calculated from EIA data found at 

http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/MajorInterstatesTable.html
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 43

certificated capacity that represents the quantity of gas it can deliver under all conditions. In other 

words, there are certain conditions under which the pipeline can deliver more than its certificated 

capacity. Under cold temperature conditions, for example, gas molecules shrink and compress together, 

allowing the pipeline to deliver a little more gas. The pipeline, however, cannot do that under all 

conditions and pipeline operators will not promise to be able to do so. FERC allows a pipeline to sell as 

firm capacity only its certificated capacity. “Firm capacity” is capacity that shippers reserve for their use 

each and every day of the year.65 Shippers pay for the right to have first call on that capacity. Should a 

pipeline sell capacity as firm and then curtail service, shippers have recourse to FERC. 

When firm shippers leave capacity unused, then it becomes available to “interruptible” shippers; i.e., 

shippers who cannot count on it being available each and every 

day because someone else has first rights to it. On a pipeline that 

is seldom full, interruptible capacity might be available on many or 

most days. Some pipelines are full in winter and not in summer. 

Our analysis found that 8 of the 30 largest U.S. interstate pipelines 

had 2007 load factors of more than 80% and 12 had load factors 

over 70%. Florida Gas Transmission, Kern River Gas Transmission, 

Columbia Gulf, Natural Gas Pipeline of America, and Northern 

Border operated at close to 90% or higher load factors. Those 

pipelines represent about 10% of total U.S. pipeline capacity but 

could be much more than that into a specific state. Florida Gas 

Transmission, for example, represents about 60% of the pipeline 

capacity into Florida. 

Pipelines may offer the summertime excess capacity under a service known as “seasonal firm.” Seasonal 

firm is available each and every day with certainty during the season in which it is offered: usually 

summer plus some of the shoulder months. Seasonal firm service is commonly offered on some of the 

pipelines that serve the Midwest and Northeast. On some of those pipelines year-round firm service to 

new shippers is simply not available. 

As demand grows new transmission capacity is needed. One question is how much new transmission is 

needed to deliver natural gas to meet the magnitude of demand that could occur if natural gas is relied 

on to reduce the electricity industry’s carbon emissions. To answer that, Aspen went back to the INGAA 

study representing the industry’s own projections of potential required capacity additions. We report 

those in Table 4 and compare the INGAA study’s projection of new capacity to a selection of the EG 

demand cases developed in the demand section of this report. 

Notably, the INGAA study projects a need to increase pipeline capacity by more than 16% over current 

capabilities even if demand shrinks. This occurs because of a projected shift in production to resources 

in locations that are not currently connected to the natural gas pipeline grid. Note the projected cost: 

a 16% expansion accumulates to a cost of $108 Billion, or, about $5 Billion per year.

 

65

 Some pipelines offer an additional service that is firm only for a given season.

Most of the new pipeline 

capacity added in the last 

30 years has been to deliver 

new supply to existing load 

or load that has shifted 

regionally. Both INGAA and 

EIA expect that trend to 

continue as existing 

production is replaced with 

supplies from new supply 

areas.
Implications of Greater Reliance on Natural Gas for Electricity Generation

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INGAA’s Base Case calls for a 20% increase in gas transmission 

capacity. This would provide 25 Bcf per day of new pipeline capacity 

(compared to the 130 Bcf per day existing today). Consisting of 

38,000 miles of pipe and associated compression horsepower, the 

cost projected to add this capacity is $129 Billion. In annual terms, 

that equates to $6.5 Billion per year. The High Case ramps the new 

pipeline capacity requirement up to 37 Bcf per day and a cost of 

$163 Billion. It would serve incremental EG sector gas demand 

equal to nearly what current EG demand is, allowing EG demand to just about double over current levels 

(around 13 Tcf). The annual investment is $8.1 Billion per year.

INGAA’s modeling focuses on interregional flows, or, capacity needed to move gas from supply basins to 

market areas in general corridors that don’t necessarily capture every individual pipeline and certainly 

do not capture LDC-level transmission.66 Those projections of new regional capacity include the 

following corridors:

 Rockies to Northeast (not New England)

 Rockies to California

 Mid-Continent and East Texas to Northern Louisiana

 Western Canada to Chicago

 Gulf Coast to Florida

The High Case adds still more capacity from Western Canada, more from Rockies, more from 

Mid-Continent and East Texas, and considerable capacity to accept OCS gas. A comparison of Figure 4,

showing the locations of current coal-fired generation, to Figure 9, showing natural gas transmission, 

suggests many more regional pipelines needing expansion were all coal need to be replaced with natural 

gas. Columbia, Transco, Sonat, Tennessee, Trunkline, Panhandle Eastern, ANR, Alliance, Guardian, 

EPNG, Colorado Interstate Gas, and Wyoming Interstate Gas are all examples. In addition, while Alaska’s 

Cook Inlet (sometimes known as the “Railbelt”) is struggling to get enough natural gas to meet current 

needs, other portions of Alaska, including Fairbanks, currently do not have access to local production or 

pipeline natural gas. Some routes for an Alaska pipeline might provide access for consumers in those 

markets, but completion of that pipeline remains at least ten years away. 

AEO 2010, by comparison, had projected a much smaller increase in EG demand. It doesn’t give specific 

projections on new pipeline capacity needed. It does, however, indicate that most new (Lower-48) 

natural gas supply will be shale-deposited gas and that a pipeline from Alaska would be in service by 

2022.67 Consistent with the INGAA study, EIA noted that new pipeline capacity is needed to deliver new 

 

66

 This is easily seen by comparing Figure 9 showing natural gas transmission pipelines in this study to Figure 56 in 

the INGAA study.

67

 An on-going joke among gas industry analysts is that a pipeline from Alaska is always “ten years out.” That is to 

say that in any given year we can look back at projections that assumed a pipeline from Alaska would be in service 

roughly ten years from the date of the forecast. If that pipeline is not built, then the associated gas supply would 

need to come from Canadian imports, lower-48 production or LNG.

8 of the 30 largest U.S. 

interstate pipelines had 

2007 load factors of 

more than 80%; 5 of 

those 8 had load 

factors of close to 90% 

or more.
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supply to existing markets: “*s+hale and other unconventional resource development will drive pipeline 

expansions for the foreseeable future.”68 

Table 4: Comparison and Extension of Demand Cases to Determine New Gas Pipeline Requirements

Case

2030/ 2036

Incremental 

EG Gas 

Demand69

Equivalent 

Number of 

1000 MW 

Coal-Fired 

Plants70

Pipeline 

Transmission 

Capacity 

Requirement

Miles of 

Pipe

% Increase 

Over

Current 

Interregional 

Flow

Cumulative 

Cost

INGAA Low - 0.5 Tcf 21 Bcf per day 28,900 

Miles 16% $108 Billion

INGAA Base 3.8 Tcf 88 25 Bcf per day 37,700 

Miles 20% $129 Billion

INGAA High 6.6 Tcf 153 37 Bcf per day 61,600 

Miles 28% $163 Billion

AEO 2010 1.9 Tcf 44

Alt 1 6.9 Tcf 160 Note that this is virtually identical to INGAA’s High Case

Convert 

Existing 

Coal

14.1 Tcf 328 70 Bcf per day $348 Billion

Source: Aspen Compilation

The INGAA estimates assume a 2010 cost per inch-mile of $60,000 and that costs escalate at slightly less 

than inflation, which the INGAA study assumed would be 2.5 percent per year.71 INGAA allowed 

construction costs to vary by region and included both pipe and compression costs. In the base case, 

half the additions are said to be for laterals to connect supply or storage or power plants to a mainline, 

but we believe the consultants’ model did not specifically model new downstream delivery capacity 

required because the model would not have generated or been fed the location of specific sites for new 

gas-fired generation needed to make such an estimate. 

The INGAA estimates may be a little low: the base case and high case assume LNG imports of 5.0 Bcf per 

day and 4.4 Bcf per day, respectively. Those figures are roughly a quintupling over 2008 LNG imports, 

 

68 Presentation by D. Gaul. Office of Oil and Gas to 2nd North American Pipelines Conference in Calgary, Alberta 

February 2009. Found at 

http://www.eia.doe.gov/pub/oil_gas/natural_gas/presentations/2009/pipelinedynamics/pipelinedynamics_files/fr

ame.html

69

 The INGAA cases go out to 2030; the other cases either went out to 2036 or the data was extended to 2036. The 

“Convert Existing Coal” case is simply the gas burn that would result today if existing coal-fired generation were 

replaced with new, efficient combined-cycled gas-fired generation.

70

 At 72% capacity factor U.S. coal-fired plants operated at in 2008.

71

 An inch-mile is a standard expression that captures both pipeline diameter and length of the pipeline. A larger 

diameter pipeline uses more steel as does a longer pipeline.
Implications of Greater Reliance on Natural Gas for Electricity Generation

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which have been low due to U.S. natural gas prices being lower 

than world LNG prices. The pipeline capacity required to replace 

that LNG would be of longer mileage, owing to the fact that some 

of the LNG import terminals are located closer to market demand 

than would be the domestic production that would replace the 

LNG. 

Adding new interstate natural gas pipeline capacity is relatively 

easy in terms of infrastructure investments. EIA notes that from 

announcement date to commercial start of operations averages 

three years.72 Many in the electric industry will readily observe 

that new electric transmission capacity is much more difficult to 

permit or site, attracts much more objection, and can take as 

many as ten years to site and construct. That is not to say that 

adding capacity is easy everywhere; there are clearly portions of the U.S. where objections have arisen 

and delayed projects, such as the Northeast, the Lake Michigan south shore, and other heavily 

urbanized areas. And objections seem to be increasing: Rockies Express encountered objections from 

rural land owners in Ohio concerned about the location of river crossings and the like. 

Figure 12: Total Interregional Pipeline Capacity 1990 to 2008

Source: Aspen Analysis of EIA data (1991 to 1993 missing from the EIA source data)

 

72

 Found at http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/develop.html

0

20

40

60

80

100

120

140

1990199119921993199419951996199719981999200020012002200320042005200620072008

Bcf per Day

Building new pipeline 

capacity is much easier 

than electric transmission 

capacity. From 

announcement date to 

commercial operation 

averages three years. Of 

course, pipelines routinely 

survey the market via 

nonbinding Open Seasons 

to assess market interest in 

new pipeline capacity.
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Aspen Environmental Group Page 47

According to EIA data, interstate pipeline capacity capable of delivering approximately 53 Bcf per day of 

natural gas was added between 1990 and 2008. (See Figure 12.) This is more than in INGAA’s High Case 

but less than the 70 Bcf per day that would be required in our case in which all existing coal-fired 

generation is replaced with natural gas. (Depending on if or when geologic CCS becomes available, 

access to build and finance some of this natural gas delivery capacity might compete with construction 

of CO2 pipelines.)

The relative ease with which interstate pipeline capacity can be added is a testament to the well-oiled 

facilities approval mechanism developed by FERC and clear market signals. Pipelines earn profit, via an 

allowed rate of return, on their rate base. More pipe in the ground, if you can sell the space in that pipe, 

means more revenue. The pipelines constantly watch market price differentials between regions 

(known as “basis” differentials) because the basis differentials measure the value of pipeline capacity 

between two locations. Figure 13 provides an example from a recent FERC Office of Market 

Enforcement briefing showing regional natural gas wholesale prices and basis differentials. Existing 

pipelines as well as potential new entrants watch this data carefully, looking for corridors for which the 

basis differential exceeds the cost of constructing additional capacity. Basis differentials will also change 

seasonally. Sometimes the winter basis between two locations shoots up dramatically while in summer 

the basis is unremarkable. Thus, large basis differentials are an indicator that capacity into a given 

region is constrained. Basis can also show when capacity exiting a supply basin in constrained: Rockies 

prices have long exhibited this phenomenon and have risen relative to other U.S. prices since Rockies 

Express entered service.
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Figure 13: Regional Basis Differentials

Source: http://www.ferc.gov/market-oversight/mkt-gas/overview/2010/03-2010-ngas-ovr-archive.pdf
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 49

When the value of capacity approaches the cost to add new capacity, the pipelines begin holding what 

are known as “Open Seasons.” An Open Season is an invitation to indicate to the pipeline that you are 

interested in holding and paying the annual reservation charge for firm capacity. Pipelines frequently 

hold Open Seasons just to test the waters, knowing that he who moves first often wins, and they may 

approach the market several times over a long period of years before enough shippers commit to 

signing contracts to pay for the pipeline.73 When the pipeline calculates that it has enough commitments 

that it can make the debt service on financing of the construction cost while earning an acceptable rate 

of return on equity, it will apply to the FERC for a Certificate of Public Convenience and Necessity 

(CPCN). FERC will conduct any necessary environmental analysis and assess the project for compliance 

with FERC rules. Under the “let-the-market-decide” policy adopted in the early 1990s, FERC does not 

require all of the capacity to be contracted and it will not choose between competing projects intended 

to serve the same markets. Rather, FERC assumes that a pipeline willing to take market risk constitutes 

a showing of “need” for the facility and certificates it with appropriate environmental conditions. With 

a CPCN in hand and contracts to cover enough capacity to make debt service, obtaining financing is 

routine.74

Creation of new delivery points, taps, and laterals to serve new large load is even easier. Notably, FERC 

does sometimes require the costs for new facilities to be recovered in what are called “incremental 

rates.” Incremental rates cover only the cost of that facility and service using it. Incremental rates are 

typically adopted when the addition of the proposed facilities and associated load would increase rates 

to all other customers. When the new facilities and load would reduce rates to all other customers FERC 

allows the costs to be added to overall rate base.

Different kinds of expansions require different kinds of facilities, implying different magnitudes of cost 

and analysis in siting. That is to say that building a wholly new pipeline in new right-of-way is more 

complicated than merely adding compression to an existing natural gas pipeline or even building a 

second pipeline in an existing right-of-way. Which is required depends on the build conditions of the 

existing pipeline. Some existing pipelines have not been completely optimized for maximum throughput 

and can achieve higher throughput for little incremental cost. Eventually all the “bell and whistle”

improvements have been done and the next capacity addition can only be achieved by adding new 

pipelines and compressors in a potentially new right-of-way. Environmental impacts associated with 

construction, in particular, are minimized when previously-disturbed land is used. More river, stream 

and highway crossings make a project more expensive. 

 

73

 Many of the “potential” projects shown on EIA’s map will not be able to obtain sufficient market commitments 

to proceed such that the map alone should not be taken as evidence of the natural gas market being able to add 

enough capacity to serve all demand. There are clearly markets today in which customers want gas and cannot get 

it because there are not enough such customers to cover the cost of new capacity. 

74

 Projects that are new greenfield pipelines or that parallel existing lines are often undertaken with project 

financing in which the lender has no recourse to the sponsor’s balance sheet; the loan is secured entirely with 

project revenues. In contrast, projects that represent minor increments of capacity that will be rolled into existing 

rates are more likely to be financed with balance sheet capital. 
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 50

Adding LDC capacity will vary state to state. State regulatory 

commissions will be anxious about impacts on existing gas 

ratepayers. In addition, while FERC will grant CPCNs with 

relative ease to add interstate capacity it is not at all clear that 

the sites on which new gas-fired generation would be located 

are either located close enough to existing gas pipelines or 

along a route that would yield demand sufficient to support 

financing. 

It is also worth noting that the contracts firm shippers must 

sign to support financing are typically twenty-year agreements 

needed to support a twenty-year financing term. Some 

pipelines will present to their lenders a market study assessing 

the potential for long-term market developments with respect 

to throughput, competition from other pipelines, and changes 

in basis differentials, but lenders do not always require such a 

study and the results of the study would virtually never be 

used by lenders to support speculative investment. 

This raises a related point about site selection. For new, greenfield gas-fired generation, a developer 

looks for a location within a few miles of a gas pipeline or large distribution line (greater than 12 to 16 

inches) with excess capacity, water for cooling, and a substation into which it can deliver its electrical 

output without overloading circuits.75 California may not be representative of the rest of the country on 

this point, but in a search on behalf of a developer in 2007, very few sites were found to be left available 

in the northern two-thirds of the state where all three requirements were present. Existing coal-fired 

plants obviously have access to a substation, they undoubtedly have water and they likely even have a 

rail right-of-way in which a natural gas pipeline lateral could potentially be constructed. But it is not 

clear that a gas transmission line with sufficient excess capacity is located close enough to each plant to 

provide gas service. 

Aspen has not done for this study a review of each coal plant’s location to determine how far it is to a 

natural gas pipeline or if that pipeline has excess capacity currently available.76 As a proxy for that 

detailed analysis we have looked at a couple of different areas.

First, recall that the CRS study cited earlier found that 60 coal plants were located with 25 miles of one 

of the underutilized merchant NGCC plants. We take that as an indication that gas is accessible within 

25 miles – clearly, the NGCC plants are connected to natural gas service. Those plants represent 28% of 

generation from existing coal-fired plants.77 Second, we can compare Figure 5 identifying the location of 

coal-fired generation to Figure 11 that displays the natural gas transmission grid. Upon inspection, it 

 

75

 A greenfield project site is one at which no prior industrial development has occurred. 

76

 The CRS study mentioned earlier herein suggested that Congress may want to consider chartering such an 

analysis. Op. cit., p. 24.

77 CRS, op. cit., p. 17

Existing coal-fired plants 

already have access to 

electric transmission, water, 

a rail right-of-way and even a 

small gas line to feed 

start-up ignition. We do not 

yet know how many would 

need to construct longer 

laterals to obtain the high 

pressure gas transmission 

service needed to support a 

large gas-fired power plant. 

We do know that 60 coalfired plants are located 

within 25 miles of an underutilized gas merchant plant.
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 51

appears there are plants along the coast in the Carolinas 

that may have trouble with access to gas, as would

northeastern Kansas, western South Dakota, 

northwestern Montana, northern Nevada, central Utah, 

northwest New Mexico, the extreme northwestern corner 

of Alabama, the Appalachian ridge west of Transco 

Pipeline, Maine, Rhode Island (or just across into 

Massachusetts), and coastal Virginia. The plants located 

in these areas would require more extensive work to the 

natural gas pipeline grid in order to provide them with 

gas. The best way to make this assessment, of course, 

would be with geographic information giving longitude 

and latitude for the coal-fired plants and the pipelines. 

Such information is not publicly available and access is 

subject to Homeland Security constraints.

Third, we have taken the GWh generated with coal in each 

state and determined the amount of natural gas that 

would be required if the state had to replace that coalfired generation with output from a new combined-cycled 

gas-fired unit. 

Our results are presented in Table 5. The total gas burn 

equates to the 14.1 Tcf EG gas burn estimated earlier to 

replace the MWh generated with coal. Table 5 shows in 

which states the replacement of existing coal-fired 

generation would require more gas than the state burns 

now. The table is sorted in order of which state uses the 

most coal for electricity generation currently. Texas 

generated the most MWh with coal so it appears first. 

Converting the Texas coal burn to natural gas equates to 

25% as much natural gas as Texas burns now. For 16 

states located primarily in the Midwest and West, 

generating their coal-fired electricity with natural gas 

would use more gas than the state uses now – meaning 

that converting coal-fired generation to natural gas would more than double that state’s natural gas use. 

Table 5 also shows the resulting load factor in a peak demand month for pipeline capacity coming into 

each state. This calculation takes natural gas flows into a state in a peak month and adds to it the gas 

Case Study: South Dakota 

South Dakota has about 481 

MW of coal-fired generation 

located inside the state. 

Converting that to natural gas 

would increase its gas 

requirement by about 30% over 

current levels. 

But South Dakota imports a 

large amount of electricity from 

Wyoming and Nebraska, some 

coal-fired and some nuclear. 

Our analysis assumed utilities 

would build gas-fired generation 

at the site of the existing coal 

plant. That means, first, that 

South Dakota’s coal generation 

is actually located in Wyoming. 

Second, utility managers would 

have to figure out how to 

replace generation coming from 

a different state. If utilities 

have to build gas-fired 

generation it is not clear that 

they would make the decision 

to participate in plants at the 

same locations, owing to the 

relative ease of siting gas-fired 

plants and vastly different size 

and scale requirements to build 

coal-fired generation, among 

other things. 
Implications of Greater Reliance on Natural Gas for Electricity Generation

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demand for converting that state’s coal-fired generation to natural gas.78 Twenty-one states would find 

the interstate pipeline capacity coming into their state insufficient to serve existing demand plus the 

conversion of coal to gas in their state. Another eight states would have load factors over 80%. These 

states are identified in Figure 14. As indicated previously herein, Hawaii and the territories would only 

have access to LNG. Alaska has indigenous gas produced in the Cook Inlet but price keeps that supply 

from expanding.

 

78

 Of course, one would also like to know the capacity utilization assuming that state and all the others 

downstream of it convert to coal, but that calculation would require detailed modeling that is not available to the 

author.
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Table 5: Gas Burn by State* if Existing Coal-Fired MW Converted to Natural Gas

State 2008 Gas Use

Additional Use If

Existing In-State Coal 

Converted to Gas

Coal Use As % of 

Current Gas Use

Pipeline Load Factor 

Into State If Convert 

Coal to Gas

Texas 3.546 0.893 25% 55%

Ohio 0.792 1.002 126% 130%

Indiana 0.551 0.906 164% 120%

Pennsylvania 0.750 0.861 115% 91%

Illinois 1.001 0.739 74% 126%

Kentucky 0.225 0.694 308% 116%

West Virginia 0.111 0.646 580% 123%

Georgia 0.425 0.614 144% 92%

North Carolina 0.243 0.558 230% 119%

Missouri 0.296 0.497 168% 104%

Michigan 0.779 0.542 70% 119%

Alabama 0.404 0.533 132% 49%

Florida 0.943 0.479 51% 105%

Tennessee 0.230 0.433 188% 68%

Wyoming 0.143 0.259 182% 41%

Wisconsin 0.409 0.299 73% 109%

Arizona 0.400 0.246 62% 104%

South Carolina 0.170 0.272 160% 86%

Oklahoma 0.670 0.241 36% 39%

Utah 0.224 0.214 95% 126%

Colorado 0.505 0.223 44% 76%

Virginia 0.299 0.261 87% 76%

Iowa 0.320 0.274 85% 145%

Kansas 0.283 0.230 81% 118%

Minnesota 0.401 0.238 59% 161%

New Mexico 0.247 0.184 75% 49%

North Dakota 0.063 0.179 283% 154%

Maryland 0.196 0.220 112% 76%

Arkansas 0.235 0.166 71% 72%

Louisiana 1.239 0.158 13% 37%

New York 1.180 0.180 15% 93%

Nebraska 0.168 0.134 80% 80%

Nevada 0.265 0.116 44% 111%

Montana 0.076 0.107 140% 131%

Mississippi 0.355 0.113 32% 66%

Massachusetts 0.374 0.075 20% 68%

New Jersey 0.615 0.094 15% 101%

Washington 0.298 0.061 21% 74%

Delaware 0.048 0.045 94% 50%

New Hampshire 0.071 0.026 36% 73%

Connecticut 0.167 0.026 15% 83%

Oregon 0.268 0.025 9% 66%

California 2.450 0.018 1% 66%

South Dakota 0.064 0.020 31% 138%

Hawaii 0.003 0.009 316% N/A

Maine 0.061 0.004 7% 56%

Alaska 0.342 0.005 1% N/A

Idaho 0.089 0.001 1% 115%

Rhode Island 0.089 0.000 0% 82%

Vermont 0.009 0.000 0% 68%

Total 23.09232 14.1214

* States Sorted in Order of Highest to Lowest EG Coal Use, which is NOT shown in the Table

Source: EIA Coal-Fired MW by State and Aspen Analysis
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Figure 14: Interstate Pipeline Capacity Utilization if An Individual State Switched its Coal-Fired Generation to Natural Gas

Source: Aspen and APPA
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 55

Having said that adding natural gas infrastructure is relatively easy, while noting the large investment 

required if coal-fired generation switches to gas, requires an additional note. There continues to be talk 

of potentially using natural gas as a “bridge fuel.”79 The notion is that switching to gas would be 

temporary, allowing us to reduce reliance on coal until other 

technologies were available. While the natural gas industry 

is clearly adept at adding new transportation capacity, it is 

still the case that the costs of these kinds of infrastructure 

investments are recovered over a relatively long period of 

time. Most financing or bond payback periods are twenty 

years or more. The useful life of a gas-fired power project is 

often assumed to be 40 years or more. It may turn out that 

these investor and cost recovery expectations are not 

compatible with the idea of using natural gas merely as a 

bridge fuel. In other words, making the investment needed to switch all or a large portion of the coalfired fleet to natural gas may require thinking about natural gas as more than a bridge fuel. 

 

79

 For a more recent treatment see Brown, et. al. “Natural Gas: A Bridge to a Low-Carbon Future?” Resources for 

the Future, Issue Brief 09-11, December 2009.

Making the investment 

needed to switch all or a 

large portion of the coal-fired 

fleet to natural gas may 

require thinking about 

natural gas as more than a 

bridge fuel.
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Summary Observations Related to Natural Gas 

Transmission Infrastructure

1. The U.S. is served by 300,000 miles of natural gas transmission capacity.

2. More than half of it was built more than 40 years ago as the industry grew from a 5 Tcf 

market to a 22 Tcf market.

3. While the market is only 1 Tcf or so bigger than its prior peak in 1972, much new pipeline 

capacity has been built since then, primarily to deliver gas from new supply regions or as 

markets shifted regionally.

4. Pipelines are always looking for market opportunities that will justify adding rate base; 

obtaining FERC certificate approvals to construct is relatively easy. 

5. Opposition to natural gas pipelines has been limited to highly urbanized, sensitive locations 

but appears to be growing.

6. Some pipelines are proposed multiple times and take years before the market will support. 

7. INGAA’s Base Case projects 25 Bcf new pipeline capacity will be needed at cost of $129 

Billion.

8. Even the INGAA case with demand lower than today’s estimates a need to spend $108 

Billion for capacity to move supply from new producing areas.

9. The Alternative 1 Demand Case is similar to INGAA’s High Case but as it is high for different 

reasons and may result in different facilities being needed.

10. Scaling up from the INGAA projections to the new gas demand should all existing coal be 

converted to gas implies a need for as much as 70 Bcf of new pipeline capacity at a cost of 

$348 Billion.

11. The industry added 53 Bcf of pipeline capacity from 1990 to 2008.

12. Some plants are likely to be served from interstate pipelines and others from LDC systems.

13. Twenty-one states would find the interstate pipeline capacity coming into their state 

insufficient to serve existing demand plus demand from their state’s conversion of coal to 

gas.

14. Some, but not all, existing coal-fired generation generally looks like it may be located 

relatively near existing natural gas pipeline infrastructure; however, a detailed GIS study 

should be conducted in order to refine this estimate.

15. It is not clear that pipeline projects designed to serve those locations would attract 

sufficient load to be economic. 

16. Making the investment needed to switch all or a large portion of the coal-fired fleet to 

natural gas may require thinking about natural gas as more than a bridge fuel.
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Natural Gas Storage 

One of the assets the industry will need to add to serve higher EG load is natural gas storage. Gas 

storage is very useful in providing flexibility to support gas burns by electric generators. Storage lets a 

power plant operator: 

 ramp up or ramp down operations quickly;

 manage its imbalances; 

 potentially hold less firm pipeline capacity; and

 maintain reliability. 

As of April 2009 EIA reported roughly 400 underground gas storage fields in operation.80 These fields, 

shown in Figure 15, provide 4 Tcf of working gas capacity and a total maximum daily withdrawal 

capability of approximately 88 Bcf per day.81 92% of the fields in current operation are reservoir or 

aquifer storage where gas is generally injected during the summer months and withdrawn during winter 

to serve seasonal demand (with certain exceptions); 8% are high-deliverability salt cavern facilities. 

Most, but not all, of the salt cavern storage is located along the Gulf Coast. Table 6 summarizes the key 

characteristics of U.S. natural gas storage.

Table 6: Storage Summary

Type Reservoir/Aquifer Salt Cavern

Characteristic Single Turn Multi-Turn

Owner LDC or Pipeline Independent

User LDC Marketers

Purpose Seasonal Demand82 Arbitrage or Daily Peak

Price COS Option Value

Sites 369 31

Working Gas (Bcf) 3,918 173 

Maximum Daily Withdrawal (MMcf/d) 74,523 13,703 

Source: Aspen Compilation of EIA Data

 

80

 This excludes the roughly 100 small LNG needle peaking operations that exist for meeting peak day demands in 

specific locations where there is no underground gas storage and pipeline capacity into the region is lower than

peak day demand. 

81

 Terminology: cushion (sometimes called pad or base gas) is gas intended to stay in the formation to maintain 

field pressures sufficient to achieve desired withdrawal levels; working gas is the amount of gas that can be 

injected into or withdrawn from the field and still be able to fill it in a given period of time; withdrawal capability is 

the amount of gas that can be withdrawn in a given period, usually a day; the withdrawal capability is higher when 

the field is filled with more gas and achieves maximum field pressures; injection capability is the amount of gas 

that can be injected in a given period, usually a day; the injection capability falls at the field is filled and operating 

pressures rise.

82 Some reservoirs can be configured for multi-turn high-deliverability storage. The Lodi and Wild Goose facilities 

in northern California are examples of reservoirs that provide multi-turn storage. 
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Figure 15: Geographic Distribution of Underground Gas Storage Facilities
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Most existing storage was built before the trend towards more use of natural gas to generate electricity 

and tends to be located where a pipeline or a local distributor chose to build based on the accident of 

geology and the economics of revenue recovery.83 Pipelines that are not connected to storage tend to 

impose stricter balancing rules. Stricter balancing rules make it harder or more costly for electric 

generators to operate.

Fundamentally, storage balances demand against production. We use it particularly to allow producers 

to operate their wells on a relatively levelized basis: when demand is lower than production, the excess 

gas goes into storage. We then withdraw it when demand exceeds production. Figure 16 provides an 

illustration of this concept. Storage also allows local demand to be met with gas stored near the load 

center, thus reducing the need to size trunkline transmission capacity into the load center large enough 

to meet peak day demand. Some types of storage also lend themselves to either medium-term price 

arbitrage or to intraday peaking service.84 Another use of storage is to remedy imbalances between 

deliveries into a pipeline against the quantity of gas burned by end-users. As explained elsewhere in this 

paper, those two quantities often differ. They often differ by fairly large amounts for electric power 

plants. When they differ by more than the pipeline operator can address with linepack or offsets by 

other shippers, the excess or shortage of gas must be addressed with gas in or out of storage.85

 

83

 New storage being added today tends to be added by local distributors who can make incremental investments 

to existing facilities or by independent merchant storage providers who charge market-based rates for storage 

service assuming several cycles, or turns, of gas are made through the inventory space. 

84

 It used to be common for summer natural gas prices to be lower than winter prices; thus, LDCs would purchase 

gas under levelized take contracts and store the excess gas until winter. Even recognizing the carrying cost on the 

inventory, consumers routinely benefited from these transactions. With the kind of price volatility that exists 

today, however, that can result in winter prices being lower than summer prices, these seasonal transactions 

cannot be sure to provide price benefits. Instead, we see marketers using short-term storage to capture the 

intrinsic and extrinsic, or real option value of storage. The intrinsic value is based on the cost of spot gas today 

versus today’s forward value. One can buy gas, inject into storage, and assure a profit spread by locking in today 

the sale upon withdrawal. The extrinsic value is based on changes one might realize due to the future movement 

of prices until the gas is withdrawn, e.g., actual spot prices being higher or lower than the purchase price or the 

locked-in forward price on the day of purchase. 

85 Linepack is an amount of “extra” gas in a pipeline or distribution line relative to maximum anticipated load. It 

can be increased by using a compressor to squeeze a line’s gas molecules more closely together. Gas distribution 

companies routinely pack their lines at night or in advance of predicted cold weather to meet higher demand in 

the morning when furnaces and hot water heaters are more heavily used. Linepack can be thought of as a 

system’s first form of temporary gas storage. 
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Figure 16: How Storage Balances Seasonal Demand with Monthly Production86

Source: Aspen 

Three different types of geologic formations are used to 

provide storage service: a) depleted oil or gas reservoirs, b) 

underground aquifers, or c) salt formations. The different 

formation types are depicted using different types of marker 

symbols in Figure 15: the stars are depleted reservoirs, 

triangles are aquifers and circles are salt caverns. 

As a general rule depleted reservoir or aquifer storage 

operates on a single-turn basis in which the reservoir is filled 

over the course of the summer and the gas is withdrawn 

over the course of the winter. Reservoirs that can operate at 

higher field pressures can be fitted with additional injection 

compressors or withdrawal wells to provide multi-turn 

service, but most of the reservoir storage in operation today 

is single-turn storage that is filled and drained once over the 

course of a calendar year. This storage tends to be used

 

86

 Note that the injections do not exactly equal the withdrawals; this difference ends up as left-over gas inventory 

at the start of the next annual cycle. This outcome is not that uncommon. 

600

800

1000

1200

1400

1600

1800

2000

Apr May Jun July Aug Sep Oct Nov Dec Jan Feb Mar

Monthly Bcf 

Production Demand

Inject Gas into Storage

Withdraw Gas

from Storage

Electricity generators can benefit 

from multi-turn storage by 

subscribing, for example, to

enough storage to meet its total 

gas requirements for the five 

days that might be the maximum 

likely interruption in the case of a

gas curtailment. The generator 

could use the space to inject or 

withdraw gas to cover its daily 

imbalances or for price arbitrage 

in the meantime. Multi-turn 

storage costs more, but most of 

the costs are fixed, so the more 

times the generator cycles gas in 

and out, the lower the amortized 

cost per MMBtu.
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 61

most by local distributors or pipelines and is priced on a cost-of-service basis.

Salt formation storage, either salt cavern or salt dome, can withstand higher operating pressures and 

therefore operates on a multi-turn basis.87 It is most often developed by merchant storage providers 

who seek an unregulated rate of return and price the service on a value-of-service basis, meaning 

market-based rather than cost-based rates if they can show no ability to exercise market power. 

Storage that is more flexible is of greater use to electric generators, but investors providing merchant 

storage understand the value of their service and are in business to capture that value from customers.

Figure 15 shows that storage is not evenly distributed, either geographically or relative to demand 

around the country. Most storage is used relatively close to the region in which it is located, and 

geology does not always provide sites where they are needed. Certain pipelines and regional markets 

currently don’t have access to underground gas storage at all. 

Figure 15 plainly shows that Nevada, Idaho and Arizona have 

none. The Central Plains states and Missouri have virtually 

none. The entire east coast has none other than far upstream 

in western New York, western Pennsylvania and West 

Virginia. (The above-ground storage tanks at the LNG 

terminals located at Elba Island, Georgia; Cove Point, 

Maryland; and Everett, Massachusetts do provide some 

important storage peaking benefits but are operated more for 

the benefit of the LNG tanker and regasification schedule 

management than to provide storage service to pipeline 

shippers. These facilities are not shown in Figure 15 in any 

case.) To the extent that there is a small amount of storage in 

the Southeast, Figure 15 shows that none of it is in the 

eastern coastal states.88

As can be seen in Table 7, roughly one-third of U.S. gas storage is located in the Midwest, virtually all in 

reservoir storage; of 121 Midwest storage facilities, 2 are salt caverns or domes. The two salt caverns 

are located in Michigan along with 43 reservoir fields; together Michigan possesses more than half the 

region’s total withdrawal capability. Illinois has 29 sites, but they are much smaller fields, on average, 

offering only 6 Bcf of combined withdrawal capability. Indiana has almost as many fields but they are 

even smaller, adding to provide less than 1 Bcf combined withdrawal capability. Ohio’s fields are 

captured in the Midwest totals but are all in the eastern half of the state.

 

87

 To reiterate, single-turn storage is used to inject and withdraw generally once per year; multi-turn storage 

allows several cycles of injections and withdrawals over the course of the year. Reservoir storage is generally 

single-turn storage, but certain reservoirs can be developed to provide multi-turn service. Salt cavern storage 

generally provides multi-turn service.

88 The states without storage now are largely without the depleted reservoirs or salt formations that can 

economically be turned into storage. 

Figure 15 shows areas without 

easy access to underground gas 

storage to include:

 Central Plains states (except 

Kansas)

 Missouri

 Wisconsin

 Arizona

 Nevada

 Idaho

 Southeastern states

 Most of Mid-Atlantic

 Northeastern states
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Table 7: Storage Working Inventory and Daily Deliverability Capability by Region

Total By Region Average Field Size

Region

Number

of Sites

Working

Gas 

Inventory

Daily

Deliverability

Working

Gas 

Inventory

Daily

Deliverability

Bcf MMcf per day Bcf MMcf per day

Central 49 557 6,224 11 127

Midwest 121 1,200 28,524 10 236

Northeast 110 796 15,203 7 138

Southeast 33 195 6,850 6 208

Southwest 66 1,040 23,203 16 352

West 20 303 8,222 15 411

Total (Avg) 399 4,091 88,226 10 221

Source: Aspen Analysis of EIA Data

The average salt cavern/dome facility is twice as large as the average reservoir storage facility. They 

tend to cost roughly 20% more to develop than reservoir storage. They contain gas at much higher 

pressure, allowing greater deliverability from a smaller inventory. They also require virtually no cushion 

gas. A downside is that the caverns are created by dissolving the salt in water. This creates a brine that 

must be disposed of properly. Development of some potential sites has been foregone due to the 

disposal issue. 

In very rough terms, the 4 Tcf of working capacity versus total 

natural gas demand of 23 Tcf implies a nearly 6:1 ratio of 

annual market demand to storage working gas capacity. 

Crudely applying this ratio to a 31 Tcf market implies the 

nation needs 5.4 Tcf of working storage capacity, or that we 

need to add 1.4 Tcf to existing storage working capacity in 

order to maintain the current ratio between total demand 

and storage working capacity. The idea that this ratio must 

be maintained may be overly simplistic because we know that 

the industry has served this level of demand before, with far 

less storage; storage working capacity in 1972, when U.S.

demand last reached the 23 Tcf range, was approximately 

2.4 Tcf.

Another approach would be to look at growth in storage 

relative to the shift towards greater use of gas for electric 

generation over the last ten or so years. Over that period, EG 

demand grew from 5.34 Tcf in 2001 to 6.85 in 2008, or 

approximately 1.5 Tcf. Storage working capacity, in that 

Pipelines that appear to have no 

access to storage along long 

portions of their route include:

 Florida Gas Transmission

 Kern River Gas Transmission

 Southern Natural

 Transco

 Iroquois

 Maritimes & Northeast

 Alliance

 Gas Transmission Northwest

 Northern Border

 Trailblazer

 Transwestern

 El Paso Natural Gas

 Williston Basin Pipeline 

Virtually all of these pipelines 

would end up with new gas-fired 

load if utilities had to switch 

existing coal over to gas.
Implications of Greater Reliance on Natural Gas for Electricity Generation

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period, grew by only about 0.3 Tcf. Applying that implied relationship to a projected EG demand 

increase of say, 8 Tcf, also yields an estimate of 1.4 Tcf more storage needed to support higher EG gas 

burns. Of course, both these approaches assume existing storage is adequate to serve existing gas-fired 

EG demand, which may not be true. At an average working gas field size of 11 Bcf, that translates to 127 

new gas storage fields needing to be added.

Notably, ICF’s 2009 study on behalf of INGAA, estimated 2030 natural gas EG demand in a base case 

4 Tcf higher than today’s and a high case EG demand 8.1 Tcf higher than today. The associated 

increases in storage working capacity are 0.45 Tcf and 0.6 Tcf, far lower than the ratios calculated above 

imply the industry might need. The National Petroleum Council’s 2003 study “Balancing Natural Gas 

Policy” projected a need for 1 Tcf of storage to meet higher demand by 2030, some 0.7 Tcf of which they 

estimated needed to be new storage additions after optimizing use of existing capacity.89 Note that 

because storage cannot necessarily be built where the new demand will be located, additional storage 

necessitates additional pipeline capacity in order fill that storage and deliver from it to local distribution 

company citygates.90

Given that storage provides electric generators with more flexibility this study considered how close 

existing coal-fired units are to underground gas storage. The data publicly accessible to answer this 

question is rudimentary in that it is only identifies the county in which the storage facility is located. 

Using that as an inexact proxy for distance between a coal-fired unit and a gas storage facility, Figure 17 

identifies the coal-fired units for which a gas storage facility is located in the same county. Aspen’s 

count is that approximately 70 coal-fired plants are located in the same county as an underground gas 

storage facility. A more refined estimate should be developed using facility-specific geo-positioning 

satellite data.

 

89

 Volume V, Transmission and Distribution Task Group Report, p. T-55. 

90

 A citygate is an interconnection between a pipeline and a local distribution company. 
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Figure 17: Existing Coal-Fired Generation Located In Same County as Underground Gas Storage
Implications of Greater Reliance on Natural Gas for Electricity Generation 

Aspen Environmental Group Page 65

Cost to Build and Use Storage 

ICF’s INGAA study estimated its forecast storage additions to cost $4.0 to $5.2 billion, respectively. The 

estimate was based on 2007 costs for actual storage projects built between 1997 and 2007, with costs 

other than cushion gas escalated from 2007 at 2% per year.91 Scaling up from the 0.45 and 0.6 Tcf ICF 

found needed, implies a cost for additional storage working capacity of $8.9 Billion per Tcf added, 

although costs will differ by field type. The 1.4 Tcf additional 

storage working capacity estimated herein translates to a 

capital cost of $12.5 Billion. 

Black & Veatch (B&V) did a study released in late 2009 (but 

actually done in 2007 for the California Energy Commission’s 

Public Interest Energy Research Program) that contained 

capital cost estimates for storage. B&V looked at costs for 

relatively recent storage projects in California. These reservoir 

projects are configured for high-deliverability, multi-turn use. 

B&V came up with a capital cost, again excluding cushion gas, 

of $37 million for an 8 Bcf working gas, three-turn per year 

field. Ignoring the multi-turn aspect, this translates to 

$4.6 Billion per Tcf added, or $6.5 Billion for the 1.4 Tcf 

estimated here as needed. 

Note again that costs to develop storage are unique to the 

reservoir or salt formation and the optimal combination of 

injection compressors, withdrawal wells, dehydration 

equipment, distance to interstate pipeline or LDC lateral cost 

and so forth. 

A natural gas storage user would evaluate the costs to use storage as shown in the example presented in 

Table 8. The table works out the cost per MMBtu for both single-turn reservoir storage and highdeliverability storage. There are essentially four fees associated with use of storage: a) reservation 

charge; b) injection charge; c) withdrawal charge; and d) compressor fuel charge. The reservation 

charge to “rent” or reserve the storage space is paid once, for each MMBtu of space reserved. In the 

example, the provider of simple reservoir charges $0.40 per Dth per month to reserve storage space. 

The high deliverability storage costs more than twice that, $1.00 per Dth.92

 

The next two fees are for injection and withdrawal. The provider charges an additional fee is paid for 

every MMBtu the customer injects into the storage inventory space and again for every MMBtu later 

withdrawn. In the example the injection and withdrawal fees shown are the same for both injection 

 

91

 ICF INGAA, page 73. 

92

 A 2004 FERC report entitled “Current State of and Issues Concerning Underground Gas Storage” reviewed tariff 

filings for jurisdictional storage facilities (p. 34). It found 100% load factor rates ranging from $0.21 per MMBtu to 

$0.96 per MMBtu. This wide range is indicative of how the different field characteristics and equipment 

configurations affect consumer cost.

The impact that use of storage 

or subscribing to more firm 

pipeline capacity will have on 

utility electricity rates depends 

on how those costs change 

the utility’s weighted average 

cost of gas (WACOG).

To convert $ per MMBtu to 

cents per kWh on a ballpark 

basis, multiply the WACOG by 

the utility’s system’s average 

heat rate per MWh and divide 

by 1000. 

A $1 per MMBtu increase in 

the WAOCG for a utility with a 

10 MMBtu per MWh heat rate

will change rates by $0.01 per 

kWh.
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and withdrawal and for the two types of storage: $0.02 per Dth. This is not always true, as some 

providers will have incurred slightly different costs in terms of the number of withdrawal wells or 

injection compressors installed. The key point is that there is usually a big annual fee to rent the space 

and then a small fee for entry and exit.

Now suppose the customer is a 500 MW NGCC that wants to reserve inventory space to satisfy 5 days 

worth of gas requirements. That unit, operating all 24 hours per day at an assumed heat rate of 

7 MMBtu per MWh would consume 84,000 MMBtu per day.93 5 days worth of gas would be 

420,000 MMBtu. For reservoir storage, the annual reservation fee for inventory space would add up to 

$2 million. (An annual reservation fee is paid each year, regardless of whether the space ends up being 

used or not.) For the reservoir storage, the customer’s gas will be injected over the 180 days of summer 

(April 1 to October 31) and withdrawn during the 120 days of the winter season (November 31 to March 

31) – basically the customer is going to pay 2 cents to inject 420,000 MMBtu (spread over a 180-day 

period) and then 2 cents for each MMBtu as it is withdrawn. Spreading the reservation charge and the 

injection and withdrawal charges over the 420,000 MMBtu creates an average cost per Dth to use the 

reservoir single cycle storage of $4.84 per Dth. If the customer reserved 420,000 MMBtu of inventory 

space but only injected 15,000, its reservation charge would remain unchanged, but its total injection 

and withdrawal fees would be lower. 

Switching over to the high deliverability storage, the annual reservation fee for the same 420,000 Dth of 

inventory space works out to $5 million. This time the customer might put the 420,000 MMBtu (recall 

that a Dth and MMBtu are equivalent) in and withdraw it five times per year. That means that the 

customer spreads the $5 million over 420,000 MMBtu. It still has to pay the 2 cents for every MMBtu 

injected and every MMBtu withdrawn. The total cost averaged over using the 420,000 MMBtu of space 

five times is $2.41 per MMBtu. The other charge listed was the compressor fuel charge. It is usually 

delivered “in-kind,” meaning that the customer delivers enough extra gas to cover that needed to run 

the injection compressor. Some providers will roll this into the injection charge. 

 

93

 500 MW * 7 MMBtu/MWh *24 hours = 84,000 MMBtu
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Table 8: Illustration of Consumer Costs to Use Underground Gas Storage

Assumption Reservoir High 

Deliverability

Annual Reservation Charge ($ per Dth per Month) $0.40 $1.00

Injection Fee $0.02 $0.02

Withdrawal Fee $0.02 $0.02

Compressor Fuel94 1% 1%

No. Days of Injection to Fill Inventory 180 20

No. Days of Withdrawal to Deplete Inventory 120 10

No. of Cycles per Year 1 3 to 5

Assume Reserve 5 days Worth of Supply (420,000 MMBtu per 

Day) Inventory Capacity

Total Fixed Cost $2,017,105 $5,042,763

Total Variable Cost $16,800 $16,800

Average Cost per MMBtu $4.84 $2.41

Source: Aspen Analysis

A further example will illustrate the implications for an electric generator. Assume the same 500 MW 

unit with a heat rate of 7 MMBtu per MWh, resulting in a daily gas requirement of 84,000 MMBtu per 

day. Assume again that the unit purchases enough inventory to meet its full 24-hour gas requirement 

for five days, or 420,000 MMBtu. Different storage providers may offer service at substantially different 

fees, owing to the unique characteristics of the facilities they own, how they have structured their 

services and how their respective regulators allow them to recover costs for storage service. Table 9 

shows the inventory, injection and withdrawal charges for three large gas local distribution companies 

with fairly large amounts of underground storage that they offer to customers, including electric 

generators, in three different regions of the country: Pacific Gas and Electric Company, Union Gas of 

Ontario, and Dominion People’s.95 

In the example of the electric generator reserving 420,000 MMBtu, the reservation charge for the same 

quantity provided by these three representative companies differs hugely: $680,000 for PG&E versus 

$3.3 million for the same quantity of space from Dominion. PG&E doesn’t have an injection or 

withdrawal fee (nor does Union Gas) but Dominion’s is a nickel per MMBtu injected or withdrawn. The 

cost for reserving and using a single cycle on PG&E works out to $1.62 per MMBtu but nearly $8 per 

 

94

 The compressor fuel is excluded from the calculation for the sake of computational simplicity. It would be 

charged typically as a % of the MMBtu injected. Some providers allow it, like pipeline compressor fuel, to be paid 

with an in-kind delivery of additional gas molecules while others require a cash payment. The cost of the fuel or 

value of the cash payment will vary as the price of natural gas varies.

95

 Union Gas does sell storage service to U.S. customers from its vast storage pool at Dawn Hub located in and 

around Windsor, Ontario.
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MMBtu on Dominion. There is no a one-size-fits-all for the fees electric generators will incur to use 

storage: they vary considerably and generators will have to learn to “do the math.”

The illustration highlights not only how different effective per Dth storage costs are going to be to 

different electric generators, depending on the costs of the storage they can access, but that the annual 

fixed costs for even a small amount of storage inventory amount to several million dollars per year and 

represent a significant commitment on the part of the generator.

Table 9: Effective Cost of Storage 

PG&E Union Gas Dominion

Inventory Charge (per Dth) $ 0.135 $ 0.538 $ 0.650

Resulting Annual Reservation Fee $ 680,400 $ 2,580,000 $ 3,276,000

Injection (per Dth) n/a n/a $ 0.05

Withdrawal (per Dth) n/a n/a $ 0.05

Effective Cost per Dth96 Single Cycle $ 1.62 $ 6.14 $ 7.90

Effective Cost for Five Cycles $ 0.32 $ 1.23 $ 1.58

Source: Aspen Analysis of Utility Tariffs

Impediments to Adding Storage

Storage that connects directly to an interstate pipeline is subject to FERC jurisdiction. FERC applies to 

storage the same “let the market decide” policy that it applies to pipeline capacity: having some of the 

capacity contracted combined with an applicant willing to bear the remaining financial risk is sufficient 

to win FERC certification. A relatively easy showing of market alternatives to storage allows FERC to find 

that the applicant cannot exercise market power so that the project can charge market-based rates. 

Since 2000, FERC has certificated more than 76 projects for a combined 860 Bcf of new working gas 

capacity. 97

Still, the number of storage facilities added in the years post-Order No. 636 and since establishing 

general parameters for allowing market-based rates is not overwhelming. Convincing subscribers to 

commit to pay market-based rates for multi-turn storage is not be as easy as it may look – the rates 

entail a significant commitment to pay firm reservation charges and are high enough that using the 

capacity for a single turn is typically not economic.98 Not only does the cost to use storage add to a 

utility’s overall cost of gas, but the cost of the gas stored imposes a carrying cost and risk that prices will 

have changed between the time the gas is purchased and injected and when it is used. The opportunity 

to cycle provides flexibility but it must be managed carefully to determine when to cycle versus when to 

trade imbalances, when to sell excess gas into the market instead of storing it versus when to rely on 

 

96 This is the effective 100% load factor cost assuming one cycle.

97

 http://www.ferc.gov/industries/gas/indus-act/storage/certificated.pdf

98

 Multi-turn storage allows the user to inject gas in and withdraw it repeatedly during a year.
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short-term “park and loan” services.99 It takes a sophisticated user to manage multi-turn storage in a 

way that assures an economic benefit to the buyer. Electric utilities or generators managing a single or 

only a few gas-fired units are not typically well-positioned in terms of staff or institutional experience to 

closely manage multi-turn storage in a volatile price environment.

In addition, geology matters.100 It takes the right kind of permeability to create field pressures that can 

operate at economic levels of injection and withdrawal while minimizing the amount of cushion gas that 

must remain in the field year-round. Investors have been looking for a suitable field, for example, along 

the Kern River pipeline that runs from southwestern Wyoming through Utah and Nevada to southern 

California since the pipeline entered service in 1993. Whether the old Ten Section field in California’s 

Kern County will finally be configured to work properly and gain market acceptance remains to be seen.

Local opposition has stalled natural gas storage development in some places. Difficulty disposing of salt 

brine is one reason. A salt cavern project in Arizona just outside Luke Air Force Base resulted in state 

law temporarily prohibiting storage development. Opponents argued that the compressor building and 

wells were too close to the runway for safety and feared that an aircraft hitting the building would ignite 

the storage facility. A project in suburban south Sacramento has attracted local neighborhood 

opposition that gas could leak from the storage field and catch fire or explode. Two separate fires 

lasting many days at PG&E’s McDonald Island facility in 1974 and 1993, as well as leaks from Southern 

California Gas fields at Whittier, Montebello and Playa del Vista, along with the highly visible August 

2004 fire that burned for 6 days in Moss Bluff, Texas, increase resident concerns.101

Projects that get certificated don’t necessarily proceed to construction. FERC won’t require a developer 

to have sold all of its capacity before granting a certificate but project finance lenders will want enough 

of the capacity subscribed to demonstrate that revenues will be more than sufficient to cover debt 

service. Even in Florida, which with its dramatically increased gas use and its role there in electric 

generation, a certificated project at Indiantown for above-ground LNG tanks has not proceeded to 

construction because it cannot obtain enough subscriptions to its inventory capacity.102

 

99

 Park and loan can be thought of as short-term storage; some pipelines offer it as a discretionary service on an 

interruptible basis, meaning that if they have capacity to allow the short-term storage they will and if they don’t, 

they won’t.

100

 It should not escape notice that some of the same geologic formations used to storage natural gas 

underground are potential sequestration sites for CO2.

101Weatherwax, R. and Weatherwax M., “California Natural Gas Storage Incidents: A Contemporary History of 

Incidents,” Sierra Energy and Risk Assessment, Inc., 2007. Storage fields that produced both oil and gas seem to 

pose higher risk than ones that produced only gas, both in terms of contributing to the incident and the 

environmental consequences of the incident. 

102 Floridian Gas Storage won its FERC certificate in 2008 with an expected in-service date of 2011. As of March 

2009 construction had not begun and there is no update on the company website indicating when construction 

will begin. 
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In a 2004 presentation to NARUC, independent storage provider Encana noted that most storage in the 

U.S. and Canada had been built during the “dramatic” growth period of the industry from 1950 to 1970. 

In planning for the future it advised that:

“New storage will be increasingly:

in poorer quality reservoirs

farther from ideal locations

using higher cost cushion gas

and therefore more costly to develop and provide service.”
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Summary Observations Related to Gas Storage

1. Storage is used by different market segments for different purposes.

2. Different types of storage suit the intended use of different market segments.

3. Geology limits opportunities to build storage where the market would prefer it; 

accordingly, storage is not distributed evenly across the country and most of it is reservoirbased.

4. Areas without much storage include: Nevada, Idaho and Arizona, the Central Plains states, 

Missouri and virtually the entire East Coast (except far upstream in western New York, 

western Pennsylvania and West Virginia).

5. Pipelines that have little access to storage include: Florida Gas Transmission, Kern River 

Gas Transmission, Southern Natural, Transco, Iroquois, Maritimes & Northeast, Alliance, 

Gas Transmission Northwest, Northern Border, Trailblazer, Transwestern, El Paso Natural 

Gas, and Williston Basin Pipeline.

6. Some high deliverability storage is reservoir-based but most is provided via salt caverns.

7. The capital costs to build new storage are field- and cavern-specific, varying with geology, 

field or cavern pressure and the configuration of injection compressors, withdrawal wells 

and other equipment selected to optimize project economics.

8. Greater reliance on natural gas to produce electricity means we need more storage and 

more flexible storage.

9. Scaling storage up to meet double the current EG demand implies a need to add 1.4 Tcf of 

storage.

10. A recent study for INGAA found a need to add 0.45 to 0.6 Tcf of storage at a cost of 

approximately $8.9 Billion per Tcf. Adding 1.4 Tcf would thus cost close to $12.5 Billion. 

11. The annual fixed costs for even a small amount of storage inventory can amount to several 

million dollars per year and represent a significant financial commitment on the part of the 

generator.

12. Electric utilities or generators managing a single or only a few gas-fired units are not 

typically well-positioned in terms of staff or institutional experience to closely manage 

multi-turn storage in a volatile price environment.
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Operational Considerations

Several operational realities need to be considered as we contemplate additional use of natural gas to 

generate electricity. First is the general disconnect between the way the unbundled natural gas system 

works versus independently-controlled electricity markets. Second is that during circumstances 

demanding interruption (otherwise known as curtailment) of natural gas supplies, large customers 

(including electric generators) are among the first asked to curtail consumption. Third is the risk of 

natural disasters such as hurricanes that can strike the Gulf of Mexico and cause large decreases in 

domestic production.

Nominations and Balancing

Other than in Canada’s Province of Ontario, the North American gas system doesn’t make it easy to be 

an electric generator. Ontario is the exception, having made a decision to replace its coal-fired 

generation with natural gas. It has worked over the last seven years to develop tariffs, services and rules 

to allow its electric generators greater flexibility. These innovative services were developed as a result 

of a proceeding conducted by the Ontario Energy Board known as the Natural Gas Electricity Interface 

Review (NGEIR). If the U.S. seriously intends to use natural gas as a bridge fuel until more renewables or 

CCS are available or if we simply require conversion of the coal-fired fleet to natural gas, the entire U.S. 

transmission and distribution system needs to look seriously at the approach used in Ontario. Notably, 

that approach relies on the vast amount of natural gas storage that exists in and around Union Gas’ 

Dawn Hub. 

Issues include the fact that the “gas day” doesn’t match the “electricity day.” The gas day begins at 

9:00 A.M. Central Clock Time (CCT). The gas industry nominates natural gas a day ahead using four 

nomination windows (except in Ontario where Union Gas allows 13 and TransCanada offers a service 

that allows 96 nomination windows per day).103 Table 10 shows the four nomination windows agreed 

upon by the industry via the North American Energy Standards Board (NAESB). Some pipelines have 

“no-bump” rules. A no-bump rule means that nominations later in the gas day cannot “bump” earlier 

nominations, even if they were from a shipper with interruptible capacity. In other words, it prevents a 

firm shipper who does not nominate all of their firm capacity in the Timely nomination window from 

bumping the interruptible customer who nominated to use that available capacity in a subsequent 

period. It effectively means that a firm shipper who does not nominate to use all of their firm capacity 

when they submit a nomination in the first cycle of the day are not guaranteed access to it in the later 

nomination windows of the cycle. 

The cycle’s initial gas nominations are due in the morning the day ahead of consumption, but the 

generators in competitively-dispatched electricity markets will only generally know how much gas the 

unit will need until they get dispatch orders, often in the afternoon of the day-ahead. Even then, 

ambient temperature conditions can change the efficiency of a gas-fired unit or actual electricity 

 

103

 A nomination for gas can be thought of as placing an order for delivery. It is notification to the pipeline and to 

the supplier of how much gas it should expect to receive for a shippers’ account and how much gas that shipper 

should burn at a facility. 
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requirements the next day such that the actual gas burn is different than the amount of gas the 

generator “ordered” from the pipeline. A difference between what the shipper caused to be delivered 

into the pipeline versus what it accepted at its meter and burned is called an “imbalance.” Shippers who 

deliver more gas than they burn can cause the pipeline operating pressure to exceed maximum design 

levels. Shippers who deliver less gas than they burn can cause the pipeline operating pressure to drop 

too low. (Even when the sum of over-deliveries or under-deliveries do not cause an operating problem, 

per se, leaving too much gas on the pipeline or taking too much out of it is effectively using the pipeline 

as storage.) On most, but not all pipelines, balancing is measured daily, with a tolerance. The tolerance 

is often 10% of monthly usage and is available because of the ability to “pack and draft” a gas pipeline, 

and depends on how much storage is connected to the pipeline system and/or that the pipeline 

operator retains for managing imbalances.104 Similarly, the fact that gas moves through a high pressure 

pipeline at a speed of about 30 miles per hour means that an operator can give shippers more time to 

manage imbalances if storage is more closely located. 

Imbalances outside tolerance must be resolved. Most pipelines allow shippers to trade their imbalances 

with other shippers. When that isn’t feasible, they must usually be managed using storage. There are 

also what are called “cash out” provisions under which a 

shipper may sell its imbalance to the pipeline or buy gas to 

make up an under-delivery from the pipeline. Most 

pipelines also have provisions imposing penalties for failing 

to resolve a balance outside tolerance. Penalties vary by 

pipeline but can be several times the prevailing commodity 

price of gas. Pipelines often also impose an additional 

charge for having “over-pulled” or “under-pulled” that is 

separate from the imbalance charge. A shipper who 

contacts the pipeline and gets his over-pull or under-pull 

authorized will usually face a different charge than one who 

does so on an unauthorized basis. Finally, pipelines and 

some LDCs can call what are called “Operational Flow Orders,” or OFOs. An OFO directs all shippers who 

are out of balance to get into balance immediately or otherwise immediately imposes penalties on all 

imbalances.

Some pipelines, usually those without storage connected to their systems, require hourly balancing. 

Even pipelines that do not require hourly balancing will have a requirement that gas be delivered and 

taken in even hourly increments, usually 1/24th of a shippers’ maximum daily delivery. Again, pipelines 

connected to storage are more likely to offer more flexibility. The sum result of all these provisions is 

that shippers who will bring a variable quantity of gas onto the system or whose takes vary day-to-day 

(like electric generators) have to pay special attention to managing their imbalances. 

 

104

 Pack and draft refers to the ability to use compression to pack gas molecules closer together in the pipeline and 

alternatively, the ability to reduce pressure and spread the molecules apart. Pipeline operators use this as their 

degree of freedom in managing the system.

10% of monthly usage is 

roughly 3 days worth of gas: 

0.1 * 30 days = 3 days

At a speed of 30 miles an 

hour, gas from 2,160 miles 

away could reach a customer 

in those same 3 days. Many 

pipelines require users to take 

gas in even hourly increments.
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LDCs often offer more flexibility than a pipeline because of the diverse load on their systems and the 

fact that they tend to be network systems in contrast to interstate pipelines that tend to be trunklines. 

LDCs, however, often have rate structures in which large customers subsidize the rates of smaller 

customers or other public goods charges are added to the rates. A generator may be able to get more 

flexibility from an LDC but will pay a premium for it. 

Union Gas, in Ontario, offers 13 nomination windows (9 additional plus the four shown below in Table 

10) so that electric generators have more opportunities to match their usage with what they deliver into 

the system. TransCanada Pipelines Limited, also responding to the NGEIR, offers the ability to change 

nominations every 15 minutes. It does so only at delivery points in which load is connected to a single 

meter taking gas off the pipeline which it says is necessary in order for it to manage the system. Union 

Gas also offers specialized services that allow generators the ability to balance a few hours additional 

gas each day, for an additional fee. 

Table 10: North American Energy Standards Board Gas Nominating Windows

Nomination Hour CCT Day

Timely 11:30 AM Day PRIOR to gas flow

Evening 6:00 PM Day PRIOR to gas flow

Intraday 1 10:00 AM Day OF gas flow, effective @ 5pm Day OF

Intraday 2 5:00 PM Day OF gas flow, effective @9pm Day OF

Source: Aspen Compilation

Some U.S. pipelines have moved to daily or hourly balancing unless the shipper buys an enhanced 

service. A survey of 10+ interstate pipelines’ balancing provisions confirms that the provisions vary 

widely, as shown in Table 11. Certainly there is a sense that more constrained provisions arise when 

the pipeline has less physical flexibility to manage imbalances or when the pipeline does not have a 

storage service it wants to sell: priced to cause sufficient pain, more constrained balancing provisions 

push shippers to purchase storage.
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Table 11: Interstate Pipeline Balancing Periods

Pipeline Balancing Period

El Paso Natural Gas Company (EPNG) Hourly unless buy Firm Daily Balancing Service

ANR Pipeline Company (ANR) Daily unless buy Enhancement Service

Florida Gas Transmission (FGT) Monthly

Texas Eastern Transmission Corporation (TETCO) Daily

Transcontinental Gas Pipeline Company (Transco) Daily

Dominion Transmission Company Monthly

Kern River Gas Transmission (KRGT) Daily

Trunkline Gas Company Daily unless aggregate imbalance all shippers < 10%

Panhandle Eastern Corp Daily unless aggregate imbalance all shippers < 10%

Columbia Gas Transmission Company (TCO) Monthly

Northern Natural Gas Company Unclear, rate charged to monthly out-of-balance volumes

Source: Aspen Analysis

Curtailment

Akin to water that flows seeking its lowest altitude spot, natural gas “moves” from higher pressure to 

lower pressure locations. Any valve open to a lower pressure circumstance will allow gas to flow. When 

the pressure inside a pipeline drops to the same pressure as at open valve, the molecules will “float” in 

place and stop flowing towards the valve. Pipeline and LDC operators will seek to curtail service to endusers before this condition occurs. LDC gas control employees are taught to avoid letting low pressure 

“float” conditions occur not only because they view their mission critical duty as being to keep homes 

warm, but also because restoring service means crews must go neighborhood-by-neighborhood and 

house-to-house, closing distribution valves and then reopening at each meter, relighting pilot lights as 

necessary, as they restore service. In some cases they may need to purge distribution lines of air. It is 

time intensive, expensive, inconvenient to home owners, and a burden on crews of a much more 

massive scale than electric service restoration. It is therefore avoided at all costs.

The alternative implemented by gas system operators is to invoke call-ahead curtailments of a few large 

gas users who have knowledgeable staff on-site and who can curtail their own use of gas before the line 

pressures drop precipitously low. In many situations, that one-call customer with a knowledgeable staff 

on-site traditionally has been a gas-fired power plant. In addition, there are locations today in which 

year-round firm capacity is either not available to existing gas-fired power projects or where it would 

not be available to a new gas-fired power project. Sometimes these projects rely on residual fuel oil or 

propane for back-up; in other instances they simply shut down. Calculations of new capacity 

requirements in this report undoubtedly do not consider changes like this that existing gas-fired 

generators might prefer to allow them to operate more securely. 

On the interstate pipelines, firm is firm. That is to say that except with regard to a no-bump rule or 

circumstances that plagued the El Paso Natural Gas system because of its failure to expand its system as 

commitments to “full requirements” customers grew, when a shipper commits to a reservation change 

for firm capacity, FERC requires the pipeline to honor that commitment except in a force majeure
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situation which is one generally caused by an emergency outside the pipeline’s control.

105

 But because 

LDCs have to protect service to “human needs” customers and maintain the integrity of their gas main 

operating pressures, they tend to use a different standard. 106

The National Association of Regulatory Utility Commissioners (NARUC) published in 2005 a technical 

assistance brief prepared by the Institute of Public Utilities at Michigan State University reviewing state 

curtailment rules.107 The review is based on a survey of state utility regulatory commissions; 31 

commissions responded to the survey. The following findings are salient:

 All 31 states responding to the survey provide some 

authority for either the state commission or the 

Governor to respond to a natural gas shortage. 

More put that authority with the Governor than the 

Commission; in many cases the authority is 

collaborative.

 Where there is an adopted curtailment order the 

order varies considerably by state; the emphasis is 

generally on protecting service to residential 

customers. 

 About a third of the states don’t require the LDCs to 

file a gas curtailment plan. Of those that do there is 

no required periodic update to the plans or rules. 

 Only about a third of the states that responded hold 

docketed hearings to review the plans.

 Only a third of the states specify the end-use 

curtailment rules in the LDC tariffs.

 

105

 Full Requirements service is often offered to smaller utilities, which are often municipal utilities, and may be 

less able to predict their usage because it doesn’t make sense for them to hire the staff to maintain the analytic 

data and forecast demand with a high degree of accuracy. The service is a hold-over from the days when pipelines 

purchased gas on behalf of their customers and sold it on a bundled basis with transportation service. While FERC 

does not generally allow pipeline to sell natural gas today (known as the “merchant function”), some independent 

gas marketers will offer Full Requirements service under which the supplier delivers to the customer whatever its 

gas requirements turn out to be. That supplier will usually have reviewed the customer’s historical load data and 

the service agreement will specify a maximum delivery quantity set high enough that it will never be exceeded; the 

supplier then holds the interstate transportation capacity needed to consummate delivery. Certain of the 

pipelines, among them El Paso Natural Gas (EPNG), provided a transportation-only analog to their smaller 

customers in which the pipeline is committed to deliver to the customer whatever amount of natural gas the 

customer delivers into the pipeline. In the early 2000’s EPNG was ordered to convert its full requirements 

customers to fixed capacity entitlements. 

106

 We know of no source that compiles further information about the frequency and duration of LDC 

curtailments. Disallowing service to customers using interruptible capacity is not a curtailment of service, by 

definition, either on an LDC system or an interstate pipeline. 

107

 Institute of Public Utilities, “NARUC Inventory on Gas Curtailment Planning,” April 2005.

Any inability to get gas is not 

properly called a curtailment. 

Customers who choose to 

hold interruptible 

transportation rights explicitly 

choose to bear the risk of 

interruption when gas 

supplies are tight. But LDCs 

that need to curtail will tend to 

call upon electric generators 

to curtail even if they have 

firm service because they are 

large loads that can protect 

service to many other gas 

customers.
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 Some states, about a third of respondents, require a customer to have alternate fuel capability 

in order to select interruptible LDC service.108

 Most of the Commissions have authority to prescribe specific actions by the LDCs during a 

shortage whether there is a plan on file or not.

 Only four of the states have examined the impact to electricity generation from a gas 

curtailment.

 Half the states understand that electric generators often do not hold firm interstate pipeline 

capacity.

 No state indicated that gas utilized for electricity generation would receive priority during a gas 

curtailment; in fact half the states said that electric generators with non-firm gas transportation 

contracts definitely would be curtailed prior to other users (the others either didn’t respond or 

didn’t know).

In some states, gas-fired electric generation has been 

installed with alternate fuel capability.109 This occurred 

largely because those specific locations were known at the 

time of construction to not have sufficient access to natural 

gas. Such alternate fuel capacity is typically diesel fuel or 

residual fuel oil. Those petroleum products cost more and 

have higher emissions than natural gas. Adding alternate fuel 

capability increases construction cost and facilities must be 

added to handle the fuel on-site. A small amount of on-site 

liquid fuel storage is typically built. Often, containment 

berms are required around those storage tanks. No 

cost-effective way to store the few days worth of natural gas 

that most contingency plans call for is available that we know 

of. In some instances it may be possible to add small peaking 

plants that liquefy natural gas and hold it for a peak day or to 

truck in LNG. AGL Resources owns LNG peaking plants near 

Macon, Georgia and Chattanooga, Tennessee that can deliver 70,000 and 90,000 MMBtu, respectively, 

into the local pipeline system. Nonetheless, if the U.S. is to rely on ever increasing amounts of natural 

 

108

 State commissions could also presumably order jurisdictional electric generators to subscribe to firm interstate 

transportation in order to protect transportation priority upstream of the LDC. They would not have that authority 

over municipal generators, of course, or unregulated “merchant” generators.

109 While the Power Plant and Industrial Fuel Use Act of 1978 was largely repealed in 1987, it still requires that new 

natural gas-fired baseload power plants self-certify to the Secretary of Energy that they can burn coal or another 

alternate fuel as a primary fuel source. The requirement applies only to plants in the lower-48 states and District 

of Columbia. A baseload unit is defined as having a capacity factor of 40% or higher. The self-certification must 

merely confirm that the proposed gas-fired plant “(i) has sufficient inherent design characteristics to permit the 

addition of equipment (including all necessary pollution devices) necessary to render such electric powerplant 

capable of using coal or another alternate fuel as its primary energy source; and (ii) Is not physically, structurally, 

or technologically precluded from using coal or another alternate fuel as its primary energy source.” See Public 

Law No. 100-42 and 10 CFR 501.60, 61. Gas-fired plants with back-up fuel capability appear to have it to protect 

against interruption of supply and not because of the Fuel Use Act. 

More than half the states 

responding to NARUC’s survey 

realized that electric 

generators with non-firm gas 

transportation contracts 

would have their service cut 

first, but only four states have 

examined the impact to 

electric generators from a 

curtailment. Only some states 

require a generator to have 

alternate fuel capability in 

order to select interruptible 

transportation.
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 78

gas for electricity generation, states will need to revisit their curtailment rules in order to maintain the 

reliability of electricity.

Curtailments can happen for another reason that likely needs some revisiting should utilities need to 

switch large portions of their generation fleet over to natural gas. 

When a customer signs up for service on an interstate pipeline, 

they specify what is known as a Maximum Daily Quantity, or 

MDQ. The fixed reservation charge that customer pays is based 

on the capacity reserved for its use as specified by the MDQ. The 

customer is not allowed to take more gas than the space 

reserved under its MDQ will allow it to transport. The customer 

would have analyzed various cost versus risk tradeoffs when it 

selected its MDQ. Many customers, naturally, will not want to 

reserve and pay for the extra capacity that they will only use for 

1 day perhaps every 8 years when very cold weather occurs. But 

now suppose that extreme cold weather does occur. The 

pipeline may, with a penalty charge, allow the customer to pull 

from the pipeline more natural gas than her share (her share 

being the amount reserved in the MDQ). But then again, the 

pipeline may not; it may not be able to due to the need to honor 

the MDQs of other customers who are also experiencing higherthan-normal demands. 

Suppose this customer were a local utility serving both gas 

end-users and the power plant that utility uses to deliver 

electricity to those same gas end-users. Gas demand shoots up above the amount it can obtain, 

pursuant to its MDQ, from the pipeline. What does the combined utility do in this case? Virtually all 

would choose to curtail gas deliveries to their power plant so that they could protect service to local 

end-users. If we are to truly switch coal-fired generation to natural gas, utilities all over the country will 

need to revisit their MDQs, the analysis that they performed in selecting those MDQs and the risk/cost 

tradeoff embodied in choosing an MDQ that is lower than total requirements on a very cold day. 

Holding the higher level of interstate pipeline capacity to preserve access to natural gas under extreme 

conditions and enable the utility to continue generating electricity using natural gas will impose higher

costs on electricity and natural gas end-users. 

A municipal utility located in 

the Midwest curtailed 

deliveries to its own gas-fired 

power plant during a cold 

snap in order to preserve 

deliveries to its other natural 

gas end-users. The limiting 

factor was not a curtailment 

called by the interstate 

pipeline but rather was the

utility’s MDQ on the pipeline. 

Increasing MDQs to obtain 

certainty of enough gas to 

protect electric generation 

reliability will cost electric 

utilities and their customers

more in pipeline demand 

charges. 
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Hurricane Risk to Supply and Prices

Hurricanes striking the U.S. coast in the Gulf of Mexico can damage production facilities and create risk 

to both natural gas prices and supply.110 10 Bcf per day, which is approximately 20% of U.S. domestic 

production and 15% of U.S. average day requirements, comes from low-lying areas of the Gulf Coast or 

offshore. As even relatively minor or tropical storms approach, 

the crews working on the Gulf’s 4,000 platforms are evacuated. 

They close safety valves to assure that no oil or gas can spill or 

escape should facilities be damaged, thus shutting-in 

production as they leave. The platforms are connected via 

more than 33,000 miles of sub-sea pipelines to onshore 

infrastructure consisting of surface-level piping, valves, 

metering stations and compressors. Key facilities include 47 

natural gas processing plants and 17 gas liquids fractionation plants that are located in coastal counties. 

In addition, Henry Hub, which is not only the physical location used to clear the NYMEX gas futures 

market but is the physical interconnection of four intrastate and five interstate pipelines sites is located 

quite near the coast. Tropical storms and less intense hurricanes simply cause a couple of days 

interruption to production and attendant price spikes as traders use virtually any excuse to bid up 

prices. 

While most storms cause little damage beyond the inevitable price run up that occurs in advance of the 

storm, intense hurricanes can cause damage to production, processing and off-shore delivery 

infrastructure such that as crews return to the rigs repairs must be made before production can be 

restored. Hurricane Katrina destroyed 44 platforms and damaged 20 more. Four days after Katrina, 

most Gulf offshore production—representing about 13% of U.S. daily average gas demand—remained 

shut in. Sabine Pipeline declared force majeure on deliveries and because the control room at Henry 

Hub was underwater (no gas could flow) and trading of the NYMEX futures contract was suspended as 

physical delivery of gas under futures contracts occurs at Henry.111 Several other pipelines declared 

force majeure on portions of their lines or at specific delivery points; however, situation reports and 

assessments from the Department of Energy and EIA show that none shut down completely. More than 

36 large diameter pipelines in Federal waters were damaged and 8 gas processing plants remained 

closed. A week later, half of Gulf offshore production (about 4 Bcf) remained shut-in. Repair crews 

 

110

 Reductions in supply due to well freeze offs (which occur under very cold conditions in which the water 

produced in association with gas freezes in the top of the wellhead, blocking production) can also occur. Wells in 

areas that expect freezing weather are built to withstand this. Wells in parts of Texas, Louisiana and locations 

where cold weather occurs seldom do from time to time experience freeze offs. The last reportedly occurred in 

2007 and took out 1.5 Bcfd of production. An outage of that magnitude could be expected to be overcome with 

gas from storage. Another potential source of disruptions arises from earthquakes. Natural gas pipelines in known 

earthquake zones are engineered to withstand shaking. Pipelines built in the Midwest or East in zones with little 

recent seismic activity may not be. Sandia National Laboratory is reported to have a study underway to evaluate 

this risk. 

111 Force Majeure is the term used in contracts to indicate a major event beyond any party’s control. An explosion 

of a pipeline is beyond the control of shippers and the pipeline and thus is considered a force majeure event. 

Most contracts will give examples of what constitutes force majeure under that particular contract.

The roughly 8 Bcfd of gas 

supply shut-in due during 

and immediately after 

Katrina was enough to meet 

about 13% of U.S. daily 

average demand. 
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 80

were impeded by lack of access to boats, crews, divers, and other equipment, lack of electric power, lack 

of access to transportation fuels needed to travel to facilities in the hurricane impact zone and long lead 

time required for delivery of repair materials and components such as custom-built valves or flanges. As 

shown in Table 12, a month later 3.5 Bcf was still shut-in. The day after Hurricane Rita’s landfall on 

September 24, the shut-in quantity had returned to 8.0 Bcf per day. When Minerals and Management 

Service issued its final shut-in statistics report eight months after the hurricanes, a total of nearly 1 Tcf 

of gas that otherwise would have been available for production instead had been shut-in and was 

unavailable to the market.112 Figure 18 shows the asymptotic approach of Gulf production to 

pre-hurricane levels.

Table 12: 2005 and 2008 Hurricane Oil and Gas Damage Summary

Platforms Outages

Landfall Destroyed Damaged Max Day 30-day +

Katrina 8/29/2005 44 20 8.3 Bcfd 3.5 Bcfd

Rita 9/24/2005 69 32 8.0 Bcfd 5.5 Bcfd

Gustav 9/1/2008 n/a n/a 7.1 Bcfd 3 Bcfd

Ike113 9/13/2008 60 124 7.3 Bcfd 3 Bcfd

If the resource portfolio relies on more natural gas, then our ability to provide electricity is at risk when 

natural gas supply is disrupted. Other fuels do not appear to impose this risk.114 Yet in the 2005 

hurricane incident what also happened is that electricity and natural gas demand declined. Comparing 

natural gas demand to natural gas production using monthly data (daily data is not publicly available) in 

Figure 19 shows that demand actually dropped by more than the supply lost such that there was little 

net negative impact beyond the price volatility. 

 

112

 1 Tcf in a 23 Tcf annual market is 4.35% of the market and somewhere between one-quarter to one-third of the 

quantity the industry likes to see in storage inventory at the start of each winter.

113

 The platforms destroyed or damaged apply to both Ike and Gustav together. EIA reported the platforms 

damaged and destroyed for hurricanes Gustav and Ike on a combined basis likely because damage assessments for 

Gustav were still underway when Ike arrived.

114

 In fact, coal is delivered in advance to most electric power plants such that they maintain a 30-day or more 

average supply on site. Single facility natural gas storage has not proven itself cost-effective.
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Figure 18: Hurricane Impact on Production

Source: U.S. Department of Energy, “Impact of the 2005 Hurricanes.”

But that is not the end of the story. The lack of recorded demand in the EIA data may be not because 

there was no “demand,” but because there was no “consumption” as the hurricane completely 

disrupted normal life. In other words, the recorded consumption data does not capture demand that 

would have been served absent the disruption. Florida issued an emergency order allowing gas-fired 

plants with alternate fuel capability to burn those fuels even if it violated their air permits; South 

Carolina curtailed some interruptible customers with alternate fuel capability and allowed its pipeline to 

purchase higher-priced replacement gas for customers who wished it to do so.115 Yet our search has 

returned no other published reports of gas service being curtailed. 

To the contrary, post-hurricane review reports make no mention of consumer curtailments associated 

with shut-in Gulf production.116 Even the Situation Reports published each day for some months after 

 

115

 Florida Department of Environmental Protection, “Emergency Authorization for Deviation From Permit and 

Certification Requirements at Power Plant Facilities Made Necessary by Hurricane Katrina,” OGC No. 05-2068, 

September 1, 2005; and Public Service Commission of South Carolina, Docket N0. 2005-261-G, Order No. 2005-483, 

September 8, 2005. Florida has long been gas constrained such that power plants there have alternate fuel 

capability; the gas-fired “merchant” fleet constructed elsewhere, however, generally does not have alternate fuel 

capability except in specific instances where lenders required it due to insufficient local natural gas access.

116 See, for example, Department of Energy, “Impact of the 2005 Hurricanes” found at: 

http://www.fossil.energy.gov/programs/oilgas/publications/naturalgas_general/hurricane_report05.pdf, or 

Energy and Environmental Analysis, “Hurricane Damage to Natural Gas Infrastructure and its Impact on the U.S. 

Natural Gas Market,” sponsored by The Energy Foundation, found at: 

http://www.ef.org/documents/hurricanereport_final.pdf
Implications of Greater Reliance on Natural Gas for Electricity Generation

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the hurricanes noted which pipelines were experiencing interruptions, the number of electricity 

customers still without power, and which refineries were and were not able to operate, but none of 

them mention customers without natural gas other than with respect to Entergy in flooded-out New 

Orleans.117 Perhaps remarkably, the largest interruption to Gulf Coast production likely to occur appears 

to have not resulted in disruption to natural gas deliveries.

The National Infrastructure Simulation and Analysis Center 

(NISAC) at Sandia National Laboratory also has done an 

analysis of access to natural gas after a major hurricane. 

The Sandia analysis concluded that enough natural gas was 

available from storage to offset production limitations posthurricane. It notes further that “what happened in the 

aftermath of Hurricanes Katrina and Rita there was 

relatively little disruption to the current consumption of 

natural gas, but that shut-in offshore wells means that gas 

was not being produced and *thus not+ put into storage.”118 

Were coal-fired plants switched to natural gas, some of 

those plants would likely be located in areas in which 

natural gas was unavailable after the hurricane. (Figure 5

shows several plants located along the coast between New Orleans and Pensacola, for example.) For 

this reason, NISAC should conduct a more detailed analysis in which it looks at precise receipt and 

delivery points at which gas might or might not be available relative to utility citygates and potential 

coal-fired power plants and determine which are upstream versus downstream of storage in order 

complete its findings.

 

117

 Electricity was disrupted due to some plant damage but mostly due to substation and line damage. Refineries 

had to wait for electricity to operate. Some disruption to gasoline supplies occurred as the refineries assessed 

damage, made repairs and waited for electricity to operate the key petroleum products pipelines used to deliver 

product from refineries to local market tank farms. These disruptions were not a function of lack of access to 

natural gas.

118 Ellison, J. “Modeling the U.S. Natural Gas Network,” Sandia National Laboratories Critical Infrastructure 

Modeling and Simulation Group. Found at: http://www.sandia.gov/nisac/docs/IERC06JEa.pdf

NISAC’s conclusion that 

hurricanes pose little risk to 

end-user natural gas 

deliveries does not consider 

the impacts should we switch 

existing coal to gas or the 

specific locations of new gasfired power plants relative to 

the specific pipeline receipt 

and deliver points that could 

be affected.
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 83

Figure 19: Katrina and Rita Impact on Monthly Natural Gas Production and Demand

Source: EIA, Natural Gas Monthly

While there is a somewhat surprising lack of evidence of even local utility curtailments after Katrina and 

Rita (likely owing to the natural gas system’s flexibility and redundancy along the Gulf Coast as visible in 

Figure 11) an additional note is worth making: winter 2005-2006 was extraordinarily warm–

“the winter that never was.” Had cold weather occurred or occurred early (the natural gas market tends 

to react more strongly in the early part of the season), the reduced storage inventories might well have 

caused curtailments to utilities in the Northeast, Midwest, and mid-Atlantic. FERC staff’s 2005 – 2006 

winter assessment worried about how tight supply could magnify price effects.119 Spot prices stayed 

above $10 per MMBtu until well into the winter based on fear that cold weather would prove too much 

for fragile supply to withstand. As shown in Figure 20, by Bidweek ending January 2006 the market 

recognized that temperature conditions to date had left enough gas in storage to get through any 

lingering cold and prices finally fell below double digits; by the summer of 2006, prices were back to 

their pre-hurricane levels. Without that warm weather, we undoubtedly would have a very different 

view of the industry’s ability to withstand the kind of damage caused by Katrina and Rita. Should 

electric utilities replace coal-fired generation with natural gas, they will not want to rely on warm 

weather providing a silver bullet should major storms cause damage that reduce production and prevent 

filling of natural gas storage.

 

119

 October 20, 2005 Winter Energy Market Assessment, Found at: http://www.ferc.gov/market-oversight/mktviews/2005/10-20-05.pdf.

0

10

20

30

40

50

60

70

80

90

Bcf per Day

Dry Production Consumption
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 84

Figure 20: Katrina and Rita Impact on Natural Gas Prices

Source: Monthly NYMEX Closing prices Compiled from Variety of Published Sources including Wall Street Journal and 

Bloomberg

Based on the evidence, the major impact borne by natural gas 

users as a result of Gulf coast storms appears to be a price 

impact – an impact that would be felt more severely as the 

proportion of electricity generated with natural gas increases. 

The severe supply disruption after Katrina and Rita did not 

result in a broad inability to obtain natural gas. Whether this 

result would obtain in a market half again or nearly twice as 

large (as might occur if coal-fired plants switched to gas) is 

unclear. Moreover, whether deliveries to specific the 

locations of those plants could be maintained is also unclear. The ability to get natural gas to specific 

locations after strong hurricanes requires further study, particularly if coal-fired generation switches to 

natural gas.120

 

120

 Some readers may wonder if the six-month drilling moratorium on OCS deepwater drilling related to the 

Deepwater Horizon accident will have an impact on production. It should not reduce current production because 

it affects only the drilling of the well prior to production. “Workover” drilling is still permitted. A workover is 

drilling done to an existing well to enhance production or fix a problem in an otherwise producing well rather than 

a new well. The drilling moratorium applies to only 33 rigs. 

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

$16.00

May-05

Jun-05

Jul-05

Aug-05

Sep-05

Oct-05

Nov-05

Dec-05

Jan-06

Feb-06

Mar-06

Apr-06

May-06

Jun-06

$ per MMBtu

The ability to get natural gas 

to specific locations after 

strong hurricanes requires 

further study, particularly if 

coal-fired generation has to 

switch to natural gas.
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 85

Staff Expansion

Some electric utilities burn natural gas today to generate electricity. Many, however, do not burn 

natural gas to generate electricity or burn a relatively small quantity, meaning they don’t have in-house 

expertise in natural gas operations, regulatory issues or markets. Coal, for example, is typically 

purchased under long-term contracts in a market in which prices are stable. Gas isn’t. Even those 

utilities that today burn gas are likely to find their staff facing expanded responsibilities as they scale up 

their operations. The new or expanded activities an electric utility would likely face include:

• Monitor Market Conditions

• Assess Gas Requirements and Plan Operations to Minimize Electricity Cost/Maximize Reliability 

• Purchase Natural Gas, Transportation and Storage 

• Submit Daily Gas Nominations and Manage Imbalances

• Manage Risk (i.e., hedge)

• Monitor and Participate in Regulatory Cases Related to Natural Gas

• Manage Contract Execution, Accounting and Settlement 

To some degree utilities may rely on joint action agencies or contract out for certain services. For a 

relatively small utility, it probably takes three people to conduct these activities. Costs for a staff that 

size, including salaries, benefits and overhead, might amount to $1 million per year. For a bigger utility 

it would take more. Professional fuel managers might contract to manage fuel for a power project often

charge 1 to 5 cents per MMBtu. They wouldn’t cover quite the full range of services listed above; their 

offering is more the daily nomination and imbalance effort. Using that 1 to 5 cents per MMBtu as a 

starting point proxy for the cost electric generators might face to manage their gas supply, for a 14 Tcf 

incremental gas burn, works out a range of $140 million to $700 million per year. Over twenty years and 

allowing for a ramp up over the first five years yields an estimated gas management cost of $2.5 to 

$12.6 billion cumulatively; somewhere past the mid-point of that range is $8 billion.
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Summary Observations Related to Operational Considerations

1. The Gas Day does not link up well with the Electricity Day, meaning that gas 

nominations have to be submitted many hours before electric dispatch decisions 

are made.

2. Even relatively slight changes in temperature and humidity conditions can cause a 

gas nomination that was “right” when made to end up causing an imbalance 

anyway.

3. Some pipelines have “no bump” rules that mean a firm shipper who doesn’t 

nominate to use all of its available capacity can effectively lose it if an interruptible 

shipper in the same nomination window requests it.

4. Ontario’s NGEIR proceeding resulted in the creation of innovative services to make 

it easier for electric generators to match their gas nominations with their use.

5. Pipeline balancing provisions vary considerably pipe-to-pipe.

6. State rules determining priority of service if there is not enough gas supply are all 

over the map but generally preserve service to residences first.

7. Not all LDC tariffs include priority of service rules.

8. As of 2005, very few states had looked at the impact to electricity generation from 

a natural gas curtailment, but many state commissions knew that generators tend 

to not hold firm interstate pipeline capacity.

9. Roughly 10 states said they require electric generators who subscribe to 

interruptible LDC service to have alternate fuel back-up capability.

10. Greater reliance on natural gas to generate electricity means states need to revisit 

their curtailment rules and utilities will need to revisit their pipeline MDQs.

11. Strong hurricanes that cause damage to above-ground and sub-sea gas facilities in 

the Gulf can shut-in as much as 20% of U.S. gas supply.

12. The severe natural gas supply disruption after Katrina and Rita did not result in a 

broad inability by consumers to obtain natural gas but it significantly increased 

prices and impeded the ability to fill storage in advance of winter. The ability to 

get natural gas after strong hurricanes requires further study, particularly if coalfired generation is switched to natural gas.

13. Electric utilities will need to expand or create gas savvy staffs that can plan and 

manage all of the activities associated with burning natural gas to generate 

electricity. 

14. Electric utilities will not want to rely on warm weather providing a silver bullet 

should hurricanes or other storms cause damage that reduce production and 

prevent filling of natural gas storage.
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 87

Retrofitting Coal Plants to Burn Natural Gas 

The electricity industry can theoretically switch to natural gas by either retrofitting existing coal-fired 

units to burn natural gas or by closing the coal plants and replacing them with new gas-fired plants. Our 

research uncovers no instances of coal plant retrofits to natural gas (we did find some references to 

retrofits to allow firing of biomass converted to charcoal-like pellets). One can find headlines and press 

reports about “switching” or “converting” to natural gas but upon reading closely it becomes clear that 

the conversion will in fact be implemented by replacing the coal-fired unit and not by retrofitting it. 

Legislatures in Minnesota and Colorado, for example, are reported to have either passed or are 

considering bills supporting conversion of coal-fired units to natural gas. The Minnesota legislature, in 

2001, passed a bill providing that any utility that “converted” from coal to gas could pass the costs 

through to ratepayers without review of the proposed rate 

change.121 Xcel Energy subsequently proposed spending $1 

billion to “convert” some plants to gas. What Xcel actually 

did was build 1100 MW of new combined cycle gas-fired 

generation at the sites of existing coal-fired plants located in 

Minneapolis and Saint Paul.122 Colorado has a similar bill 

before its legislature this year supporting so-called 

conversion but reviewing the details reveals that the plants 

Xcel owns there would likely either be retrofit to burn 

biomass or be replaced with natural gas combined cycle 

units. Even the Minnesota Public Utilities Commission 

decision approving the Xcel investment referred to the 

change as a “conversion” before proceeding to explain that 

the coal unit would be replaced by a new gas unit. In short, the idea of retrofitting or converting a coalfired plant to burn natural gas is a misnomer; proposals to convert are nearly always plans to completely 

replace the coal-fired generation with a new gas-fired unit at the same location. 

In 2008, the Government Accountability Office (GAO) delivered a report looking at the economics of 

converting the U.S. Capitol complex from coal to natural gas and discussing various aspects of doing so 

 

121

 Minnesota Statutes § 216B.1692. The Minnesota Pollution Control Agency’s report to the Minnesota Public 

Utilities Commission can be found at: 

http://www.pca.state.mn.us/publications/reports/xcelenergy-metroemissionproposal.pdf.

122

 These were the High Bridge and Riverside plants. The Riverside “Repowering Project” consisted of retiring 

three existing coal burning boilers and repowering steam turbine 7 by adding two gas-fired combustion turbines 

(CTs) each with a heat recovery steam generator (HRSG). The new CTs and HRSGs were constructed where the 

original Riverside Units 1-5 once stood. At High Bridge, Xcel demolished the coal plant, removing boilers, turbinegenerators and auxiliary systems including buildings and foundations and termination of all linear facilities but 

retained the existing water supply and return from the river.

The idea of retrofitting or 

repowering coal-fired plants to 

burn gas turns out to be a 

misnomer. Retrofitting or 

converting coal-fired 

generation to gas may be 

technically feasible, but most 

conversions are accomplished 

by replacing the coal unit with 

a completely new gas-fired 

unit at the same site.
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 88

for the country as a whole.123 The GAO reported that not only is switching all coal-fired generation to 

gas infeasible because insufficient natural gas supply and the impracticality of adding the additional gas 

industry infrastructure required to do so but that retrofits of existing coal-fired plants to allow them to 

burn gas made no sense: “it would be more feasible and cost-effective to construct new natural gas 

units or to dispatch excess capacity at existing natural gas units than to convert a coal plant because of 

technical and economic factors, among other reasons.”124 GAO further stated that the switching from 

coal to gas that has been done has not been done via retrofits but by building new gas-fired plants.125

A study performed in 2000 by the Interlaboratory Working Group on Energy-Efficient and Clean-Energy 

Technologies for the U.S. Department of Energy’s Office of Energy Efficiency and Renewable Energy 

considered the economics of retrofitting coal-fired generation to burn gas versus greenfield NGCC 

construction. It found the “all-in” cost from the repowered unit to be between a half-cent per kWh to 

one cent per kWh, depending on the unit’s capacity factor. It concluded: “*g+iven the other 

uncertainties in repowering a plant this cost differential is not sufficient to choose repowering over 

greenfield.”126

In terms of retrofitting specifics, the boilers designed to burn coal are different from the ones designed 

to burn gas. Retrofitting would involve installing a new combustion system and a new heating surface. 

Due to these changes, the retrofitted unit would operate at a lower rate of efficiency, which GAO cites 

as 10 to 12 %.127 Some other pieces of the coal-fired station could potentially be re-used, subject to an 

engineering review of their operating condition, in either a retrofit or a new combined cycle 

replacement. These include:

a) the existing steam cooling infrastructure;

b) the existing linear structures to the site such as for water, sewer and transmission, although new 

interconnections would need to be made within the site; 

c) the existing administrative and control buildings including phone and internet access (but the 

main computer control systems (including SCADA) would likely be replaced if not updated 

recently and would have to be revised to match the new unit); 

d) the existing road access and security infrastructure; 

e) the existing safety/emergency infrastructure consisting of fire water tanks, emergency 

generators and fire pump engines;

f) the existing onsite switchyard or substation; and potentially

g) the existing emission stack(s), unless it has to be replaced to meet the new EPA NOx hourly 

NAAQS.

 

123

 GAO, “Implications of Switching from Coal to Natural Gas,” GAO-08-601R, May 1, 2008. Found at: 

http://www.gao.gov/new.items/d08601r.pdf

124

 GAO, op. cit., pp. 5 – 6.

125

 GAO, op. cit., p. 16

126

 Interlaboratory Working Group, “Scenarios for a Clean Energy Future,” Oak Ridge National Laboratory and 

Lawrence Berkeley National Laboratory, ORNL/CON-476 and LBNL-44029, November 2000, p. E-7.4.

127

 GAO, op. cit., p. 15
Implications of Greater Reliance on Natural Gas for Electricity Generation

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Another potential obstacle to retrofitting existing coal units to burn gas, as pointed out in the GAO 

study, is that some coal-fired units are essential to local reliability and reserve margins. They cannot be 

taken out of service for the four to six months required to do the retrofits as doing so would leave 

certain geographic areas with insufficient system reserves, leading to brownouts or blackouts. GAO did 

not identify what those locations are but further study to identify them would likely be useful. 

In terms of economics, the installed cost for a new combined-cycle gas-fired unit of 1000 MW is the 

range of $1 Billion, or roughly $1 million per MW.128 Accordingly, the estimated first order cost to 

replace the existing 335,000 MW worth of coal-fired generation in the U.S. is roughly $335 Billion—for 

the power plant only. In other words, the cost of the additional natural gas infrastructure such as long 

distance transmission pipelines and storage that this study has discussed that would be needed to serve 

massive replacement of coal-fired generation with natural gas would be on top of the construction cost 

for the plant itself. This figure also does not include any environmental remediation or plant 

decommissioning costs (or savings) for the coal-fired unit being replaced; there may also be SOx or NOx 

or carbon credit values or lower water costs to take into account. The $1 million per MW would, 

however, include the cost to construct short service laterals to a high pressure gas transmission mainline

assumed to be nearby.

129

 Locating replacement natural gas plants at the site of the existing coal-fired 

generation makes the most sense since the site would already have transmission to deliver its generated 

energy into the power grid. It would also have access to water and a rail line (the rail line right-of-way 

could well be used to locate the bigger lateral pipeline that 

will be required to deliver gas to the site). 

The cost estimate above does not include that outstanding 

debt service on existing coal units that would need to 

continue to be paid or recovery of investment from 

ratepayers in coal-fired facilities done on utility balance 

sheets that may remain to be recovered. Many utilities have 

outstanding debt or unrecovered costs for coal-fired units 

that may have been built years ago. Power plants, regardless 

of whether they belong to an investor-owned utility, a municipal utility or an electric co-operative, are 

routinely financed over 20- or 30-year periods.130 Based on data reported to EIA, about 30% of the U.S. 

coal-fired fleet is 30 or fewer years old. Other plants have made retrofits for pollution control 

technology that may have been financed. To the extent that utilities have outstanding debt service 

 

128

 EIA used in its AEO 2010 an “overnight” installed cost for natural gas combined cycle plants of $984 per kW, in 

$2008. See Table 8.2, “Assumptions to the Annual Energy Outlook 2010.” Found at: 

http://www.eia.doe.gov/oiaf/aeo/assumption/pdf/electricity.pdf#page=3

129

 Most gas-fired power plant construction estimates include the cost of a short service lateral out to a mainline 

as part of the capital cost. If the service lateral were longer or if a compressor were needed to bump the pressure 

up for the gas turbine or if no high pressure transmission mainline were nearby, then the capital costs would 

increase further. Note that this estimate does NOT include the annual fixed costs to reserve interstate pipeline 

capacity, LDC capacity, storage service, or the cost of increased personnel or services to manage all of the above. 

130

 Some utilities might pay off the debt on their plants more quickly than 20- to 30-years, but there are also 

examples of plants being refinanced past that timeframe, including instances when the utility may have invested in 

control technology for one pollutant or another and financed that cost.

The installed cost to replace 

the existing coal-fired fleet is 

approximately $335 Billion –

before adding the new gas 

infrastructure or paying for the 

annual services needed to 

support those plants.
Implications of Greater Reliance on Natural Gas for Electricity Generation

Aspen Environmental Group Page 90

obligations, they are not simply a “sunk” cost but must be paid in current time from utility cash flow. 

The need to complete paying off this debt and the impact on utility cash flow is rarely highlighted but 

needs to be recognized as part of the cost of potentially replacing the coal-fired fleet. Moreover, the 

first order estimate above further assumes that only the existing fleet is “converted;” it does not include 

the cost of power plants that must be built to meet future load. 

Modifying the coal plant to burn gas or building a new gas-fired unit will also require new or revised 

permits in the areas of air, water, and waste. According to internal Aspen staff and outside experts, 

challenges in getting those permits will be site-specific and depend on the scope of changes made at the 

project site. 

With respect to solid waste, retirement of a coal plant would not impose any federal requirements 

today unless environmental contamination subject to the Comprehensive Environmental Response, 

Compensation, and Liability Act (Superfund) were present. States may have solid waste permits or 

regulatory requirements, however. The coal ash rule recently proposed by EPA, however, may add a 

new obligation to obtain a Resource Conservation and Recovery Act permit to close the on-site ash 

management unit and trigger facility-wide corrective action to remediate any solid waste contamination 

within the facility fence line. Note that building a new NGCC at the site does not necessarily require 

retirement and abandonment of the existing coal-fired unit; the plant could instead be closed and 

allowed to stand for some period of time.

Revised or new water permits will depend on whether the physical changes to the facility are sufficiently 

wholesale that the facility is deemed to create a “new source” of wastewater or a “new facility” for the 

intake cooling water. This could occur with respect to waste water effluent, if, for example, the site uses 

a waterbody that has been listed as impaired for one or pollutants discharged by a “new source.” 

Alternatively, if the cooling water intake structure has to be changed significantly such as to limit the 

design velocity through the intake screens or the proportion of the source waterbody that may be 

withdrawn, those changes could be enough to create a “new facility.” EPA also has rules that would 

limit flows at “new facilities” to levels consistent with wet re-circulating cooling.

Air permits for a natural gas-fired facility under existing regulation are well-known to be easier to obtain 

than for a coal-fired unit. SO2, as one example, is little problem for gas-fired power plants because most 

sulfur is removed from natural gas in a processing plant relatively near the wellhead. Yet there are at 

least three air permit issues that mean converting to natural gas a) may not be as simple as it appears, 

and b) that create additional costs not included in the $335 billion NGCC construction cost estimate 

presented herein that should be recognized nonetheless. 

First, consider particulate matter (PM). To the extent that the size of the new gas-fired unit is larger 

than the coal-fired unit that it replaces or that it operates in more hours, particulate emissions may be 

higher than for the coal-fired unit the gas unit replaces. Standards for PM2.5 have become increasingly 

stringent, forcing more parts of the U.S. into nonattainment, which triggers more-stringent permitting 

requirements, like offsets. Controlling NOx with the selective catalytic reduction introduces ammonia 

emissions, which may be subject to limits or monitoring, because ammonia is a primary component in 
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forming PM2.5 as ammonium sulfate and ammonium nitrate particles. Achieving accurate and reliable 

PM data during emissions monitoring and stack testing is also a challenge. The unit facing these issues 

would then incur additional costs to achieve PM compliance. 

Second, EPA finalized a new National Ambient Air Quality Standard (NAAQS) for nitrogen dioxide (NO2). 

The rule created a new 1-hour standard for ambient NO2 at 100 parts per billion.131 The concern is that 

NGCCs may be compliant independent of current background emissions, but the background ambient 

NO2 levels will be determined by monitors placed near highways. This will force urban areas into

nonattainment and trigger more stringent permitting requirements for NGCCs. EPA’s list of counties 

that would be in nonattainment (found at: http://www.epa.gov/air/nitrogenoxides/actions.html) is 

conservative as the rule requires the new dispersion monitors to be placed in more counties where 

monitors do not exist and near highways where NO2 emissions would be higher. Alternatively, if the 

NGCC is sited in an NO2 nonattainment county, emission offsets and/or use of some sort of control 

equipment not currently envisioned or higher stack may be needed. Those costs are not included in this 

study’s estimates of the cost to replace coal-fired generation with new natural gas combined-cycle units. 

Figure 21 illustrates the potential configuration of an NGCC relative to property lines, a highway and 

dispersion model receptor grid under the proposed 1-hour NOx standard.

Third, is the great unknown of how CO2 will be regulated and what CO2 emissions standard could apply. 

As long as the Clean Air Act regulates CO2 and GHGs, Best Available Control Technology (BACT) 

requirements at power plants will force some type of controls on CO2 emissions. The EPA PSD “Tailoring 

Rule” (May 2010) did not alleviate this regulatory requirement for fossil-fuel fired utilities. Also, 

combustion of natural gas emits only half as much CO2 as coal, but if those emissions are regulated plant 

by plant (instead of by utility portfolio), it is unclear whether CO2 control would occur under New Source 

Performance Standards (NSPS) or BACT. Utilities today don’t know if that will include some type of 

emissions or performance standard potentially set near or below the emissions of an NGCC or a 

requirement that can only be met with geologic sequestration (assuming geologic sequestration is 

demonstrated to be commercially feasible and deployable) or something else. That cost of compliance 

is also currently unknown for geologic sequestration at coal plants or natural gas plants.

Another issue just emerging now is potential regulation of hydrochloric acid (HCl). EPA currently plans

to regulate HCl from smaller combustion units under the Industrial and Commercial Boiler Maximum 

Available Control Technology (MACT) requirement. EPA has not proposed any HCl limit for utilities 

burning natural gas; however, the proposal for the smaller combustion units leaves utilities reluctant to 

assume that they will not eventually have to add equipment for HCl MACT, notwithstanding being 

unsure what that equipment would be or what MACT for HCl even means. The point is that some 

expectation should be made for future compliance obligations.

 

131

 See Docket ID: EPA-HQ-OAR-2006-922. INGAA filed written comments that the one-hour standard “could 

require emissions levels beyond the capability of current control technologies.”
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Figure 21: Dispersion Model Receptor Grid Used for Proposed EPA 1-hour NOx NAAQS
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Conclusion

The purpose of this study is to inform current and future users of natural gas and policy makers what to 

expect should much greater reliance on natural gas to generate electricity become a reality. This could 

happen if Congress enacts new laws or EPA adopts new rules to regulate greenhouse gas emissions. In 

addition, the costs to comply with other regulations (shown in Figure 4) EPA may adopt to reduce levels 

of other pollutants from electricity generating sources is already pushing many electric utilities to 

consider switching to natural gas. In this study, Aspen evaluated the projected quantity of gas that 

could need to be burned by electric generators under several potential scenarios. Aspen also identified 

the operational issues and natural gas infrastructure investment that would be required to support 

much higher gas burns.

Comparing and contrasting the projected gas burns from those studies that have evaluated potential 

economy-wide cap and trade programs to reduce greenhouse gas emissions is informative. Some of the 

studies assume geologic CCS will be available; some not. Some add nuclear generation; some don’t. 

Most increase Renewables in the resource mix but it becomes clear that even at 20% Renewables and 

low load growth (as in Duke CCPP, for example), no new nuclear power leaves only CCS and low load 

growth as the tools to reduce carbon emissions. The comparison highlights the fact that the resource 

mix assumptions made in these studies with respect to load growth, nuclear generation, CCS, 

Renewables and access to offsets – assumptions that may not be achievable – drive the resulting natural 

gas burn. Aspen’s own analysis developing additional scenarios suggests a need to burn roughly twice 

as much natural gas as today if carbon emissions were regulated. And if regulation of carbon and other 

pollutants lead electric utilities to switch potentially all existing coal-fired generation to gas, then the 

additional gas burn also ends up close to 14 Tcf, or roughly double today’s 6.9 Tcf. The new gas burn 

plus that plus burned by existing gas-fired resources would cause virtually as much natural gas as is 

burned today in the entire economy to be used for electricity generation alone. In some states the 

current amount of natural gas consumed would be double or triple the amount delivered to that state 

today.

The need for additional natural gas infrastructure to deliver that higher quantity of natural gas is 

addressed in a recent comprehensive study by ICF for the INGAA Foundation. The INGAA study found a 

need for $108 billion worth of new pipeline capacity even if demand for natural gas declined owing to 

the fact that new supply would come from new basins needing new inter-regional delivery capability. 

That study’s Base Case projected $129 billion. Scaling up to replace all existing coal-fired plants implies 

a need to build more than 70 Bcf per day of new delivery capability costing $348 billion. Additional 

storage would be necessary, too, costing perhaps $12.5 billion. Gathering and processing facilities of 

another roughly $40 billion would also be necessary. 
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Figure 22: Total Cost to Implement Switch from Coal to Natural Gas

Source: Compiled by Aspen

The capital cost to replace the 335,000 MW of existing coal-fired units with new combined-cycle gasfired units amounts to $335 billion. This cost plus the natural gas infrastructure improvements 

combines to total over $700 billion should natural gas need to fully displace coal-fired generation, the 

breakdown of which is shown graphically in Figure 22. Costs of this magnitude suggest that natural gas 

must be more than a bridge fuel because utilities are not likely to invest in and financial institutions are 

not likely to finance this magnitude of investment other than on a long-term basis. Moreover, some 

debt service on plants less than 30 years old (representing 30% of the existing coal-fired fleet) likely 

remains outstanding. Utilities must make these payments out of current cash flow; estimates of these 

costs as well as costs for the new NGCCs to comply with additional emissions regulation should be 

included in the total cost to switch from coal to natural gas.

Electric utilities that today may not have gas-fired resources in their resource mixes will have a lot to 

adjust to as they switch to gas, or, similar to Ontario, will need help convincing the natural gas industry 

to adjust its policies as more natural gas is used to generate electricity. Many pipelines do not offer 

services customized to serve electric generators whose usage changes more frequently than pipelines 

prefer. New services will need to be developed and the two industries will need to become much more 
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aligned in their common practices. In addition, states will likely need to review their curtailment policies 

and think about how gas-fired electricity generation fits into a priority of service order so that electricity 

generated with so much natural gas does not become less reliable.