Federal Energy Regulatory Commission • Staff Report • September 30, 2004

C U R R E N T ST A T E OF A N D I S S U E S CONCE S CONCE R N I N G

Underg r ound Natur ound Natur ound Natural Gas Storage

Federal Energy Regulatory Commission

Staff Report • September 30, 2004

A – Salt Caverns B – Aquifers C – Depleted Reservoirs

Docket No. AD04-11-000
Federal Energy Regulatory Commission • Staff Report • September 30, 2004

TABLE OF CONTENTS

Current State of and Issues Concerning

Underground Natural Gas Storage Underground Natural Gas Storage

Summary of Key Findings Summary of Key Findings 1

Introduction 2

I. Background and History of Underground Storage I. Background and History of Underground Storage 4

Traditional Underground Storage 4

The Nontraditional Usage of Underground Storage 4

Three Types of Underground Gas Storage Facilities 4

Summary of Physical Characteristics of Traditional Storage 5

Operating Characteristics of the Types of Underground Storage 6

Nationwide Storage Capacity 7

Actual Storage Operating Capacities 9

Storage Capacity Summary 10

Regional Distribution of Underground Storage 10

The Commission’s Role in Underground Storage 12

Current Developments Regarding Underground Storage 14

Problems with Underground Storage Projects 15

Need for More Storage 15

Staff Observations on the Current State of Underground Storage 16

II. Economics of Underground Storage II. Economics of Underground Storage 18

Storage Economics 18

Storage Development Costs 18

The Value of Storage 19

Economic Summary and Conclusions 24

III. Possible Options for Stimulating Underground Storage Development III. Possible Options for Stimulating Underground Storage Development 26

Cost-Based Rate Options for Storage Development 27

Market-Based Rates 29

Revise or Waive Commission Policies 31

Appendix A – Under Appendix A – Underground Gas Storage Tariff Rates 32

Appendix B Appendix B – Example of State Regulatory Approach 33
1 Federal Energy Regulatory Commission • Staff Report • September 30, 2004

KE Y F INDINGS:

• Under average conditions and from a nationwide perspective, storage appears to be

adequate to meet seasonal demand; however, continued commodity price volatility

indicates that more storage may be appropriate.

• Storage may be the best way of managing gas commodity price, so the long-term

adequacy of storage investment depends on how much price volatility customers

consider “acceptable.”

• A study performed by the National Petroleum Council indicates that there may be a

need in North America for 700 Bcf of new storage between now and 2025. Another

study, by The INGAA Foundation, concludes that 651 Bcf of new storage may be

needed in the United States and Canada by 2020. In addition, there may be certain

region-specific (e.g., Southwest, New England) needs for new storage.

• Geology, economics and environmental impacts may stall development and could

jeopardize achieving forecasted capacity needs.

• Reengineering of existing storage fields is underway in order to improve working

gas capability – application of new engineering techniques can help to ensure that

development of new fields stays on track.

• Four key methods that market participants use to value storage (e.g., cost of service;

least-cost planning; seasonal valuation, or intrinsic; and, option-based valuation,

or extrinsic) do not always reach the same result because they are based on differing

views of the need and reasons for storage.

• Storage projects in certain geographic areas (e.g., Southwest) often fail the

Commission’s market-based rates tests.

• Creative ratemaking approaches may encourage storage development.

• Creative certificate and policy choices may also encourage storage development by

reducing costs and permitting additional opportunities to generate revenues.
2 Current State of and Issues Concerning Underground Natural Gas Storage

This report addresses three aspects of the state of and issues concerning the underground storage of natural gas: the

history of storage development and its physical characteristics and the need for storage; the economics of underground

storage; and, ratemaking options for future storage development.

The underground storage of natural gas has historically been critical in assuring that overall demands and usespecific requirements of natural gas customers are met. The Natural Petroleum Council’s (NPC) September 2003

report1

 noted that the demand for storage is expected to increase in the foreseeable future. Specifically, the NPC

foresees the need for an additional 700 Bcf of new storage in the United States and Canada over the next 20 years,

which translates to an average of 35 Bcf of new storage being added each year.

INTRODUCTION

Presently, from a national perspective and assuming

average weather, storage appears to be adequate.

However, simply considering average demand and

national balances does not tell the complete story. For

some market areas, particularly those that are distant from

supply sources, the development of new storage

infrastructure could cost-effectively help customers

maintain service reliability and manage commodity price

volatility.

In addition, gas prices have increased with the decline in

gas production. During the “gas bubble” of the 1980s1990s, production increased in response to short-term

spikes in demand. Production increases coupled with

demand decreases in this same period allowed supply to

meet demand, even during peak periods, without

significant price spikes. As production declined or

flattened over the past few years, production spikes can

no longer be relied upon to meet demand spikes. As a

result, commodity price swings manage demand

fluctuations.2

Building new storage may be an effective way to reduce

commodity price volatility. Demand for storage services

to manage price volatility will depend on customer

tolerance for price risk, how that price risk is valued, and

the cost of service. Accordingly, there may be a public

policy interest in encouraging storage development.

While the desire of project sponsors to build new storage

in the Southwest and Northeast has been demonstrated

by the various applications seeking to develop projects,

the development has not occurred for economic,

environmental, geological and political reasons.

Specifically, in the Southwest there have been three recent

storage projects that, for various reasons, have not been

developed. The Desert Crossing storage project, although

initiated, has not been further pursued; while no formal

reason for not pursing development was provided, market

(contractual) support did not materialize and

environmental concerns associated with certain aspects

of the proposal were raised.3

 The Copper Eagle storage

project, located on the outskirts of Luke Air Force Base,

became the subject of security and safety concerns; plans

for its development have been delayed following

expressions of concern by the State of Arizona legislature.4

The sponsor of the Red Lake storage project did not pursue

development owing to Red Lake’s unwillingness to go

forward without authorization for market-based rates. Its

inability to demonstrate a significant lack of market power

resulted in the Commission’s decision to deny market1 Balancing Natural Gas Policy – Fueling the Demands of a Growing Economy, National Petroleum Council (2003).

2 See Report on the Natural Gas Price Spike of February 2003, Staff Investigating Team, July 23, 2003.

3 Desert Crossing Gas Storage and Transportation System LLC, 98 FERC ¶ 61, 277 (2002).

4 Copper Eagle Gas Storage L.L.C., 97 FERC ¶ 62,193 (2001); Copper Eagle Gas Storage, L.L.C., 99 FERC ¶ 61,270 (2002).
3 Federal Energy Regulatory Commission • Staff Report • September 30, 2004

based rate authority.5 Evidence of the desire for storage

in the Southwest was demonstrated in the Southwestern

Gas Storage Conference held on August 23, 2003, in Phoenix,

Arizona.6

 There, participants, including the Chairman

of the Arizona Corporation Commission, expressed

unanimous support for the proposition that development

of new storage in the region was needed.

In the Northeast, two major projects, the NE Hub storage

project and the Avoca storage project, similarly never came

into service, and the Wyckoff/Greyhawk storage project

has been delayed, although they all were certificated by

the Commission, but encountered various technical and

economic problems.7

 While these projects were located

in New York state in areas where the geology is conducive

to the development of underground storage, the geology

in other parts of the Northeast is not practical for the

development of underground storage.

As discussed in more detail in this report, there are other

approaches to achieving the development of new storage

using both new and existing fields. For example,

reengineering of existing storage fields is an ongoing

exercise to improve working gas capability. In addition,

the application of new engineering techniques can prove

useful in achieving greater deliverability from existing

fields. These techniques also help to ensure the efficient

development of new fields in areas geologically conducive

to storage, stays on track.

Through new design approaches and the application of

advanced engineering techniques, certain physical

barriers to the development of new storage can potentially

be overcome. However, as discussed later in this report,

long-term market price signals appear to be weak for new

storage development. Further, the four key methods that

market participants use to value storage (cost of service;

and, least-cost planning seasonal arbitrage, or intrinsic;

and option-based or extrinsic) do not always reach the

same result because they are based on differing views of

the need and reasons for storage.

But regulatory requirements may prove to be a financial

barrier inhibiting development in some regions. Storage

developers have claimed a preference for market-based

rates. And, in the markets where new storage developers

cannot assert market power, market-based rates have been

allowed.

Current Commission rate policy provides considerable

flexibility to design cost-based rates, negotiated rates and

market-based rates. Additional cost-based rates and

market-based rate alternatives could be explored to

encourage additional storage development. Further,

revised storage project certification requirements and

procedures could potentially reduce costs and offer the

potential to generate additional revenues

This report sets out some of these approaches and also

describes some non-cost-based approaches that may be

useful in addressing financial obstacles to new storage

development.

5 Red Lake Gas Storage, L.P, 103 FERC ¶ 61,277 (2003); Red Lake Gas Storage, L.P., 102 FERC ¶ 61,077 (2003).

6 Southwestern Gas Storage Technical Conference, Docket No. AD03-11-000, Notice of Technical Conference (2003).

7 NE Hub Partners, L.P., 105 FERC ¶ 61,334 (2003); Avoca Natural Gas Storage, 88 FERC ¶ 62,245 (1999); Wyckoff Gas Storage Company, LLC, 105 FERC

¶ 61,027 (2003).
4 Current State of and Issues Concerning Underground Natural Gas Storage

BACKGROUND AND HISTORY OF UNDERGROUND STORAGE

Natural gas storage facilities are used to meet gas demand

peaks which exceed production and long-haul pipeline

throughput. Increasingly, storage also plays a variety of

roles helping market participants manage pipeline

imbalance charges and daily and seasonal price volatility.

When cold weather or other market conditions create

more demand for gas than domestic production or imports

can satisfy, gas that has been put in storage can be

withdrawn to make up the difference. While natural gas

is also stored for peak daily and hourly uses mainly by

distribution companies and liquefied natural gas (LNG)

is stored briefly at import terminals, this report will focus

on what is known as traditional underground gas storage,

as well as, the new, nontraditional usage of storage

developed by the unbundling of storage and the new

market conditions.

Traditional Under raditional Underground Storage

Geology is a key issue for determining the location of

new traditional underground storage projects and the

expansion of existing projects. There are areas that have

the geological characteristics to construct storage fields;

other areas do not. Selection of any new underground

gas storage location depends on geological and

engineering properties of the storage reservoir, its size

and its cushion, or base, gas requirements. It also depends

on the site’s access to transportation pipeline

infrastructure, gas production sources, and to markets.

The use of underground gas storage facilities in the natural

gas industry is almost as old as the development of long

distance transmission lines. The first high pressure

transmission lines began operations in 1891 with

successful construction of two parallel 120-mile, 8-inch

diameter lines from fields in northern Indiana to Chicago.

The first successful gas storage project was completed in

1915 in Welland County, Ontario. The following year,

operations began in the Zoar field near Buffalo, New York.

Underground storage field operations include a host of

component and interdependent facilities. There are

injection/withdrawal wells, observation wells, water

disposal wells, gathering lines, dehydration facilities, gas

measuring facilities, compressors, etc. Underground

storage fields come in three basic types: depleted gas/oil

reservoirs, salt caverns, and aquifers. Access to at least

one major transportation pipeline to receive gas or deliver

gas is, of course, a complementary requirement.

The Nontraditional Usage of Underground

Storage

In addition to meeting the traditional seasonal load

variations, the hourly swings, and emergency situations,

storage is now being used to meet services created by both

the unbundling of storage and by the new market

conditions. Specifically, storage is being used to:

1. Meet the regulatory obligation to ensure supply

reliability at the lowest cost to the ratepayer by

maintaining specific levels of storage inventory.

2. Avoid imbalance penalties and facilitate daily

nomination changes, parking and lending

services, and simultaneous injections and

withdrawals.

3. Ensure liquidity at market centers to help contain

price volatility and maintain orderly gas markets.

4. Offset the reduction in traditional supplies that

were relied upon to meet winter demand.

5. Increase the comfort inventory level of working

gas or top gas.

6. Offset, through the injection of more gas during

the shoulder months, the growing summer peak

impacts from electric generation.

7. Support other electric generation loads.

Three Types of Underground Gas Storage Facilities Three Types of Underground Gas Storage Facilities

Salt Cavern

Some storage facilities use caverns that are leached or

mined out of underground salt deposits (salt domes or

salt formations). Salt cavern capacity typically is 20 percent

to 30 percent cushion gas and the remaining capacity is

working gas. Working gas can generally be recycled 10-12

times a year in this type of storage facility. These facilities
5 Federal Energy Regulatory Commission • Staff Report • September 30, 2004

are characterized by high deliverability and injection

capabilities and are mainly used for short peak-day

deliverability purposes (i.e., for fueling electric power

plants).

Depleted Oil/Gas Reservoir

The most common underground gas storage facilities are

those that use deep underground natural gas or oil

reservoirs that have been depleted through earlier

production. These reservoirs are naturally occurring, and

their potential as secure containers has been proven over

the millennia that the reservoirs held their original

deposits of oil and gas. An underground gas storage field

or reservoir is a permeable underground rock formation

(average of 1,000 to 5,000 feet thick) that is confined by

impermeable rock and/or water barriers and is identified

by a single natural formation pressure. The working gas

capacity is typically 50 percent, with the rest of the capacity

maintained to ensure adequate deliverability. Gas is

typically withdrawn in the winter season and injected

during the summer season. This type of storage facility

could be used for seasonal system supply or for peak-day

demands.

Aquifer

A large number of reservoirs are bound partly or

completely by water-bearing rocks called “aquifers.” The

nature of the water in the aquifer may vary from fresh to

nearly saturated brines. Aquifer storage facilities typically

have high cushion gas requirements, ranging between 50

percent to 80 percent. However, they achieve high

deliverability rates, with gas injected in the summer season

and withdrawn in the winter.

The following chart , based on the Department of Energy’s

Energy Information Administration (EIA) final 2001 data,

shows that depleted reservoirs are the dominant type of

underground storage based on total capacity. These

percentages have slightly changed using 2002 EIA data,

which are not yet final.8

Source: Energy Information Administration 

Types of Underground 

Storage Capacity 

Depleted 

Reservoir

86%

Aquifer

10%

Salt Cavern

4%

Summary of Physical Character haracteristics of Traditional raditional

Natural Gas Storage

( The following descriptions are from the Natural Gas

Supply Association)9

The most common form of underground storage consists

of depleted gas/oil reservoirs. Depleted reservoirs are

those formations that have already been tapped of all

their recoverable hydrocarbons. This leaves an

underground formation geologically capable of holding

natural gas. In addition, using an already developed

reservoir for storage purposes allows the use of the

extraction and distribution equipment left over from when

the field was productive. Having this network in place

reduces the cost of converting a depleted reservoir into a

storage facility. Depleted reservoirs are also attractive

because their geological characteristics are already well

known. Of the three types of underground storage,

depleted reservoirs, on average, are the cheapest and

easiest to develop, operate and maintain.

8

 Form EIA-191, Monthly Underground Gas Storage Report.

9 See NGSA’s Web site at http://www.naturalgas.org/naturalgas/storage.asp
6 Current State of and Issues Concerning Underground Natural Gas Storage

Aquifers are underground permeable rock formations that

act as natural water reservoirs. However, in certain

situations, these water-containing formations may be

reconditioned and used as natural gas storage facilities.

Because they are more expensive to develop than depleted

reservoirs, these types of storage facilities are usually used

only in areas where there are no nearby depleted

reservoirs. Traditionally, these facilities are operated with

a single winter withdrawal period, although they may be

used to meet peak load requirements as well. Aquifers

are the least desirable and most expensive type of natural

gas storage facility for a number of reasons. First, the

geological characteristics of aquifer formations are not as

thoroughly known as are depleted reservoirs. A

significant amount of time and money goes into

discovering the geological characteristics of an aquifer and

determining its suitability as a natural gas storage facility.

Also, the cushion gas requirement for aquifers is higher

than for depleted oil/gas reservoirs.

Underground salt formations offer another option for

natural gas storage. These formations are well suited to

natural gas storage because salt caverns, once formed,

allow little injected natural gas to escape from the

formation unless specifically extracted. The walls of a salt

cavern also have the structural strength of steel, which

makes it resilient to reservoir degradation over the life of

the storage facility. Salt caverns are formed out of existing

salt deposits. These underground salt deposits may exist

in two possible forms: salt domes and salt beds. Salt domes

are thick formations created from natural salt deposits

that, over time, move up through overlying sedimentary

layers to form large dome-like structures. Salt beds are

shallower, thinner formations. Because salt beds are wide

and thin, salt caverns in them are more prone to

deterioration and may also be more expensive to develop

than salt domes.

Operating Characteristics of the Types of Operating Characteristics of the Types of

Underground Storage

The pressure range in a depleted reservoir for the storage

operating cycle depends upon (1) the safe upper limit of

the reservoir pressure (bottom hole or surface pressure),

(2) the flow capacity of the wells, and (3) compression

requirements when injecting gas into the reservoir or

delivering to market. Normally gas and oil fields have

pressures at discovery in the range of 0.43 to 0.52 pounds

per square inch per foot of depth. The highest pressure

level possible normally will provide the maximum

storage capacity and the wells will have the highest flow

capacity.

Peak-day or seasonal deliverability is directly related to

storage volume vs. storage pressure. Required storage

deliverability services (daily or seasonal volumes) require

maximum storage pressure and gas-in-place volumes prior

to the withdrawal season.

Therefore, the main issues are how much gas can be carried

over from year to year, how long the gas can remain in

the reservoir prior to being turned over and how soon

can the capacity be refilled. These problems are not based

on some theoretical behavior, but instead are based on

experience under a variety of turnover and injection

conditions.

It is operationally improper to simply let the gas sit in

any storage field. If working gas is not recycled properly,

it will move from higher pressure areas of the storage

field to lower pressure areas, move into tighter formations

or migrate to a point that will result in an increase in

cushion gas requirements or gas loss.

The following table summarizes our understanding of how

the three types of storage fields are generally operated.

Less cushion gas is needed for salt caverns and they can

be filled and emptied much more frequently than aquifers

or depleted reservoirs. For aquifers or depleted reservoirs,

the injection period usually corresponds with the months

of April through October (214 days), while the withdrawal

period is usually the months of November through March

(151 days). Storage operators must use their best geologic

and engineering judgment to vary from this schedule.

Early season cold weather can reduce storage gas in place

and deliverability, while late season cold weather can

reduce the next season’s required injections in terms of

volumes and days.
7 Federal Energy Regulatory Commission • Staff Report • September 30, 2004

Nationwide Storage Capacity

Because not all storage is under the Commission’s

jurisdiction, we have to look to other sources of

information to get nationwide totals of storage capacity.

The EIA reports that as of 2002 (the latest data available),

interstate pipelines operated nearly 55 percent of the

nation’s gas storage capacity10 but had contractual rights

to use only 8 percent of the working gas capacity for their

own purposes. Local distribution companies (LDCs) and

intrastate pipeline companies operated about 35 percent

of working gas capacity and independent operators

operated about 10 percent of working gas capacity.

However, most of the pipeline’s storage capacity, about

73 percent, is contractually committed to LDCs. Marketers

also hold a significant share of storage capacity under

contract, about 15 percent. The total maximum U.S.

natural gas storage capacity (cushion, or base, gas plus

working gas) reported to the EIA fluctuated slightly above

the 8 Tcf level for the past eight years (8 to 8.4 Tcf), while

for the same period, the EIA reports that working gas

storage capacity has varied between 4.4 and 4.7 Tcf.

Using a different survey, the Office of Fossil Energy –

which, like EIA, also is in the Department of Energy –

reported that as of 2003 there were 110 underground gas

storage operators that maintain and operate 415

underground gas storage facilities with a working gas

capacity of 3.9 Tcf in this country. Of this total number of

facilities, 201 are FERC-jurisdictional, controlled by 43

operators. The total FERC-jurisdictional working gas

capacity is 2.5 Tcf. Close to half of all the storage capacity

is located in the Midwest. The graph on the following

page shows the relatively stable amount of storage capacity

from 1997 to present, based on EIA’s data.

10 Form EIA-191, Monthly Underground Gas Storage Report.

Source: Analysis of FERC filings

Type Cushion to Working

Gas Ratio 

Injection Period

(Days)

Withdrawal Period

(Days)

Aquifer

Depleted Oil/Gas

Reservoirs

Salt Cavern

Cushion 

50% to 80%

Cushion 50%

Cushion

20% to 30%

200 to 250

200 to 250

20 to 40 

100 to 150

100 to 150

10 to 20

Gas Storage Facility Operations
8 Current State of and Issues Concerning Underground Natural Gas Storage

Volumes of Underground Natural Gas Storage

Source: U.S. Department of Energy, Office of Fossil Energy Tcf

Northeast Midwest Southeast West Total U.S.

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

1997 1998 1999 2000 2001 2002 2003 2004

However, total reported storage capacity has never really

been tested with operating experience. Thus, the value

that defines “full” when determining the total working

gas capacity is not known exactly. Even the EIA’s “Basics

of Underground Natural Gas Storage” discusses three

different approaches to measuring “percent full” of U.S.

natural gas storage. Based on our interpretation of

historical data, staff believes there is a total practical storage

operating capacity of 7.6 Tcf, of which 3.5 Tcf 11 is working

gas capacity and the remaining 4.1 Tcf is cushion gas. The

American Gas Association (AGA) reported that the largest

working gas capacity held in storage during a given time

period was 3,294 Bcf. Therefore, based on EIA data of

total storage capacity being at least 8.2 Tcf for several recent

years, the staff estimates that there is as much as 600 Bcf of

potential working gas capacity available within existing

storage fields for future use. Thus, staff estimates the total

U.S. potential working gas capacity to be 3.6 to 3.8 Tcf.

Based on these estimations, there is 200 Bcf to 500 Bcf of

potential working gas capacity beyond the presently

proven 3.5 Tcf of working gas that could be reengineered

and used.

Another technical point is that storage working gas

capacity is directly related to the availability of supply. If

there is sufficient gas supply available during the early

injection season when storage pressures are lowest, the

storage operators could inject at the highest rates and re11 Actual total operating capacity reported by EIA monthly (2001-02 withdrawal season). However, the total potential working gas capacity is

estimated by EIA to be 3.9 Tcf, thus we would accept that working gas could be 3.5 Tcf to 3.9 Tcf.
9 Federal Energy Regulatory Commission • Staff Report • September 30, 2004

pressurize their storage reservoirs to be ready for

withdrawal season, which usually begins November 1

each year. As storage reservoir pressures increase, gas-inplace volume also increases and the injection rate declines

gradually in late injection season. Therefore, the injection

rate is higher at the beginning of injection season and

lower at the end of injection season. The withdrawal rate

is highest at the end of injection season, when storage

reservoir pressure is highest. Storage operators estimate

the volume of supply needed for each season and they try

to refill their storage fields’ working gas capacities based

on historical performance levels and match their storage

capacities with their customers’ requirements. Many

storage fields are designed to have some excess working

gas capacities and operational flexibility to withdraw some

cushion gas, as needed, within the late withdrawal season.

Actual Storage Operating Capacities Actual Storage Operating Capacities

As shown below, based on historic EIA data, cushion gas

averaged about 54 percent of the total operating capacity

from 1975 through 1991. In 1992, cushion gas began to

increase, reaching 61 percent of the total operating

capacity in 2000. While cushion gas has been increasing,

working gas capacity has been decreasing. This increase/

decrease of cushion and working gas capacity could

represent the reclassification of working gas to cushion

gas as a result of open access, as well as maintaining higher

storage pressures to support higher withdrawal rates. Also,

this supports the need for realignment or re-engineering

of existing storage fields to improve the cycling capability

of the storage fields and reduce cushion gas requirements

if and when higher storage services are needed.

Bcf

Cushion Gas Working gas

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

1973

1975

1977

1979

1981

1983

1985

1987

1989

1991

1993

1995

1997

1999

2001

2003

Relative Volumes of Working and Cushion Gas

Source: Graph generated by FERC staff from EIA data
10 Current State of and Issues Concerning Underground Natural Gas Storage

Storage Capacity Summar apacity Summary

Total U.S., storage operating capacity (EIA data) =

 7.6 Tcf (actual)

Total U.S., working gas capacity (potential) =

3.9 Tcf (estimated by EIA)12

Total U.S., actual operating working gas =

3.5 (1990-1991 withdrawal season)

Total Jurisdictional operating capacities

(staff estimation) = 5.2 Tcf

Total Jurisdictional working gas capacities

(staff estimation) = 2.5 Tcf

Regional Distribution of Underground Storage

The maps below illustrate the regional distribution of

underground storage, which is concentrated in upper

Ohio Valley, Michigan, Illinois, Gulf Coast and south

central locations. This regional distribution is based on

convenient geology, historic natural gas usage patterns

and location of depleted oil/gas reservoirs. There are

locations in the northeastern United States where there

are no depleted oil/gas field, salt domes/formations or

natural geological confinements for the development of

underground storage fields. While an alternative is the

importation and storage of LNG (surface or subsurface),

this alternative faces land use and local siting barriers.13

12 EIA, Natural Gas Monthly, 1973-2003, shows estimated working gas capacity of 3.2 to 3.5 Tcf.

13 In addition to the LNG import terminal at Everett, Mass., which has a storage capacity of 3.4 Bcf, there are 46 liquefaction and satellite storage

tanks located in Connecticut, Maine, Massachusetts, New Hampshire and Rhode Island owned and operated by LDCs. The total combined

storage of peak shaving and satellite storage is 15 Bcf. Cumulative vaporization capacity of these storage tanks, plus that from the Everett facility,

is approximately 2.3 Bcfd, which can supply as much as 50 percent of the region’s peak day needs. In addition to the LNG storage, LDCs have

260 propane tanks in New England with a total storage capacity of 1 Bcf of liquefied petroleum gas (LPG). Vaporization from LPG can meet 5

percent of New England’s peak day needs. See also New England Natural Gas Infrastructure, Docket No. PL04-1-000, December 2003.
11 Federal Energy Regulatory Commission • Staff Report • September 30, 2004

FERC Jurisdictional U.S. Storage by Type and Location

Depleted Gas Reservoir Aquifer Storage Field Salt Cavern Storage

Non-jurisdictional U.S. Storage by Type and Location

Source: Developed using Platts PowerMap and GasData 

Depleted Gas Reservoir Aquifer Storage Field Salt Cavern Storage
12 Current State of and Issues Concerning Underground Natural Gas Storage

The Commission’s Role in Under s Role in Underground Storage

Commission Certificates

The Commission has jurisdiction over any underground

storage project that is owned by an interstate pipeline

and integrated into its system. Also, independently

operated storage projects that offer storage services in

interstate commerce are under the Commission’s

jurisdiction. The chart below is based on staff ’s

compilation of Commission orders and it shows that the

annual number of new storage fields certificated by the

Commission has decreased since the 1970s and early 1980s.

Beginning in 2002, the new certificated storage fields

mostly involved the development of small depleted gas

fields and salt cavern storage fields.

FERC Certification of New Storage Fields by Year

Source: FERC filings

Year

Number of Fields

0

1

2

3

4

5

6

7

8

9

10

1968196919701971197219731974197519761977197819791980198119821983198419851986198719881989199019911992199319941995199619971998199920002001200220032004

Likewise, based on our compilation of applications at the

Commission, the number of applications to construct and

modify storage facilities has fluctuated from the 1970s

through 2004. We attribute the large number of

applications during the late 1970s and early 1980s to the

industry’s reaction to colder-than-normal winters. The

current increase in the number of storage applications

reflects modifications of existing storage fields (increasing

capacity and efficiency) as well as applications by

independent storage operators entering the natural gas

market as a result of Order No. 636.

Current Commission Cases

Eleven major interstate storage projects (adding six new

storage fields) were certificated since 2002, authorizing
13 Federal Energy Regulatory Commission • Staff Report • September 30, 2004

0

2

4

6

8

10

12

14

16

18

20

1 970

1 972

1 9741 976

1 9781 980

1 9821 9841 986

1 988

1 990

1 992

1 9941 996

1 998

20002002

2004

1968

Certificate Applications for Realignment of Storage

Year

Number of Applications

Source: FERC filings

the development of 74.7 Bcf of new interstate working

storage capacity for the U.S. Of the 74.7 Bcf of new storage

capacity, 17.9 Bcf has been delayed or put on hold when

compared to the applicant’s originally projected in-service

date. Of the 11 storage projects, four projects would add

12.2 Bcf of new storage capacity into the Northeast region,

but it is these projects that have been delayed. Two

projects have added 12.1 Bcf of new storage capacity in the

Midwest and five projects added 50.4 Bcf of new storage

capacity in the Gulf Coast/Southeast.

Four storage projects are pending before the Commission;

they have a projected capacity of 54 Bcf for the Northeast,

Midwest and Gulf Coast/Southeast regions. The present

pending and anticipated storage projects will be required

to meet the increasing seasonal peak-day requirements.

Ten publicly announced storage projects are on the

horizon with potential storage capacity totaling 115.8 Bcf.

Of this amount, 5 Bcf would be in the Northeast, 27 Bcf

would be in the Midwest, 53.6 Bcf would be in the Gulf

Coast/Southeast and 3.2 would be in the West.

The regional distribution of these approved, pending and

on-the-horizon projects is shown on the map below.
14 Current State of and Issues Concerning Underground Natural Gas Storage

Current Developments Regarding Underground

Storage

New Technologies

Current methods of improving storage field efficiency,

such as mechanically removing debris, washing, injecting

acids and creating new perforations in the well pipe often

provide only limited and temporary improvements. New

technologies are now being used to improve storage field

efficiency:

• To unclog storage wells, a low-frequency/high

frequency sound wave device is being used that

vibrates the scale off the well pipe.

• There are innovative fracturing technologies, such

as injecting high pressure liquid carbon dioxide

instead of water or other liquids, to keep clays from

sticking and sealing off parts of the reservoir.

• In salt cavern development, operators can chill the

natural gas and condense its volume to reduce the

size of the storage field and the amount of brine that

needs disposing.

• Operators can use “lined rock caverns” in storage

facilities, in which a steel tank has been installed in a

cavern that has been blasted into the rock of a hill.

• Freezing natural gas in the presence of water creates

hydrates, thus allowing for large quantities to be

stored in same volumes.

• Operators can use the Bishop Process (TM by

Conversion Gas Imports) in which LNG is unloaded

offshore, warmed to 40 degrees Fahrenheit and then

stored as natural gas vapor in underground salt

caverns either onshore or offshore.

Recent Gas Storage Projects 

Capacity in Bcf; August 2004

Source: FERC filings and price industry reports 

Egan

(8.0)

SG Resources

(12.0)

Seneca

(0.8)

Dominion

(5.6)

Gulf South

(10.6)

Natural

(10.7)

Wyckoff (6.0)

KM (6.0)

Caledonia

(11.0)

Falcon Gas

(20.0)

NUI 

Tennessee

(5.0)

Copper Eagle (3.2)

EnCana

(8.0)

Bluewater

(27.0)

Saltville

(5.8)

Columbia

(12.4)

Texas Gas

(8.2)

Dominion

(9.4)

Sempra

(24.0)

Falcon Gas

(3.0)

NGO

(6.1)

Liberty Gas (17.0) (11.6)

Copiah

(3.3)

NGPL

(10.0)

Certificated Since 2002 (11) On the Horizon (10) Currently Pending (4) 
15 Federal Energy Regulatory Commission • Staff Report • September 30, 2004

More on LNG and Underground Storage

Quantities of LNG imports into the United States have

increased almost six-fold from 85 Bcf in 1998 to 507 Bcf in

2003. Should LNG imports grow in the future as projected,

more storage facilities (LNG tanks, salt cavern storage and

depleted offshore oil/gas reservoirs) will be needed. The

DOE is studying a novel method of unloading and

regassifying LNG directly from ocean tankers for storage

in underground salt caverns. Under the Bishop Process,

LNG would be received directly from an offshore tanker,

regasified, pressurized and warmed to 40 degrees F, then

injected into underground salt caverns. A DOE study

identified more than two dozen potential sites that had

suitable salt formations, sufficiently close proximity to

existing pipelines and navigable water.14 This process

would eliminate the need to build expensive aboveground

cryogenic storage tanks. A combination of the Bishop

Process with the construction or conversion of existing

offshore depleted gas fields, platforms and lines could also

be a means to import, store and transport LNG. There are

many offshore depleted gas fields that could be used for

this purpose.

Problems with Underground Storage Projects Problems with Underground Storage Projects

A few storage projects have been canceled, delayed or

placed on hold due to market concerns, environmental

issues and rate issues. Specifically, storage projects have

been placed on hold until the market improves or have

been cancelled due to a lack of market interests.

Environmental concerns such as brine disposal used in

the development of salt caverns and land use have been

raised. Storage projects have incurred funding problems

and cost concerns, and some projects have been cancelled

or delayed due to pipeline infrastructure problems. With

the denial of market based rates for storage projects by the

Commission, certain storage proponents believe costbased rates may not provide adequate incentives to attract

the investment necessary to develop the proposed storage

facilities.

Need for More Storage

Estimations of the need for more storage first require

projections of national and regional natural gas supply

and demand. Then one must estimate the future

expansion of natural gas transmission and distribution

to gauge how much more storage might be needed to meet

seasonal and peak deliverability demands. The price of

natural gas and the price volatility also affect the need for

storage and such factors also need to be estimated. The

NPC gas study and other sources have estimated a need

for additional storage in the United States and Canada of

up to 700 Bcf by 2025. This has been projected on a regional

basis by work sponsored by The INGAA Foundation, as

follows below:

Source: Energy and Environmental Analysis Inc, At the Crossroads: Crisis or Opportunity for Natural Gas

Western Canada 30 Bcf 40 Bcf 70 Bcf

Eastern Canada/Michigan 36 Bcf 74 Bcf 110 Bcf

Midwest – 60 Bcf 60 Bcf

New York 10 Bcf 56 Bcf 66 Bcf

Pennsylvania / West Virginia 33 Bcf 90 Bcf 123 Bcf

Gulf Coast 72 Bcf 5 Bcf 77 Bcf

West Coast 21 Bcf 78 Bcf 99 Bcf

Other 10 Bcf 37 Bcf 47 Bcf

Total 212 Bcf 439 Bcf 651 Bcf

Incremental Working Gas 

Capacity in EEA Base Case 2004-2008 2009-2020 Total

New North American Gas Storage Requirements

14 See http://www.fe.doe.gov/programs/oilgas/storage/index.html.
16 Current State of and Issues Concerning Underground Natural Gas Storage

S t aff Observations on the Cur tions on the Current State of

Underground Storage

Natural gas storage is in better shape this year than last.

From a national perspective, we have adequate storage

volumes in place in the United States at this time to cover

normal conditions. The EIA’s “Weekly Natural Gas

Storage Report” divides U.S. underground gas storage

into three regions: East, West and Producing. As of

September 9, the United States had 257 Bcf more in storage

than at this time last year and 183 Bcf more than the fiveyear average for this time of year. If storage injection

continues at its current pace, there should not be any

problem in refilling working gas storage to the previous

year’s level (3,155 Bcf on October 31, 2003) and the storage

fields should be full and pressurized to their designed

levels.

In recent years, however, relatively few new storage fields

have been built. Also, there has been an abandonment

of a number of old, inefficient, and uneconomically

operated underground gas storage fields. Traditionally,

underground storage fields were designed to meet peak

seasonal demands. Today, especially with the

proliferation of gas-fired electric plants, storage facilities

are increasingly expected to meet rather dramatic daily or

even hourly swings. Thus, storage operations are

changing with changing market characteristics. The load

profile has changed for natural gas customers over the

past few years, and gas supply now is required – sometimes

quickly – throughout the year rather than merely meeting

peak seasonal demands. Therefore, storage fields with

high injection and withdrawal capabilities are becoming

the main choice for many storage operators. The

traditional marketplace now values highly diversified

types of storage services and has increasingly sought

storage that rewards flexibility, safety and reliability. This

is the main reason why storage operators are reengineering and conducting detailed studies of their

storage fields to see how they can improve the performance

of existing storage facilities. Storage field re-alignments

are being implemented to increase working gas capacity

within existing fields and to reduce cushion gas

requirements, which results in increases in deliverability.

Since 1968, there have been many applications for the

realignment of old storage fields. Storage operators have

modified old storage designs, incorporated new design

procedures and constructed surface and subsurface

facilities. These modifications include drilling largediameter wells, relocating wells within reservoirs,

incorporating coil tubing drilling (CTD)15 and horizontal

well drilling and completing larger diameter wells.

Additionally, storage operators are adding compression,

dehydration facilities, and new gathering lines.

Operators are also using new technical procedures to better

understand reservoir geology, confinement and reservoir

flow behaviors, abandoning uneconomical facilities and

incorporating new storage operational procedures.

Storage field modifications have generally provided new

operational capability for storage operators to recycle more

working gas efficiently. By cycling working gas during

both injection and withdrawal seasons, the storage

operator is able to confine the storage gas, better define

geological parameters, reduce gas migration/loss, increase

efficiency and reduce operational cost. Finally, a few

storage fields’ working gas volume has increased and

cushion gas volume of those same fields were reduced.

On balance, through realignments or re-engineering

procedures, injection/withdrawal capability has increased

without any significant increase in total storage operating

capacity. In fact, data indicate that the total U.S. storage

operating capacity (jurisdictional and nonjurisdictional)

has remained about the same over the past few years.

Thus, the recent trend in storage field construction activity

has predominantly been the modification and

realignment of existing storage fields to meet changing

market demands rather than a dramatic increase in

15 CTD is used in existing storage reservoir when the conventional well enhancing techniques (hydraulic fracturing, acidizing and/or reperforating)

for enhancing well performance have not proved to be effective.
17 Federal Energy Regulatory Commission • Staff Report • September 30, 2004

construction of new storage fields. During the past 10

years, there has been a significant increase in the ability

to move gas in and out of storage.

It is the staff’s technical opinion that prudent operational

procedures and realignment of storage facilities within

the past few years by storage operators have resulted in

better use of storage capacity. Storage operators have

modified their storage facilities and improved storage

capabilities with different types of storage operations and

services than offered in previous years. In staff’s view, in

the future, storage operators will construct a limited

number of storage facilities on an as-needed basis.

However, these projects will tend to be highly selective,

taking advantage of particularly advantageous locations

or highly favorable geological characteristics.

Historical storage engineering and operational data

indicate that not all working gas has been recycled in

many storage fields. There are many old storage fields

that could and should be redesigned and realigned by

incorporating new technology, reducing cushion gas

volume, increasing working gas volume and increasing

efficiency of storage operation by recycling more working

gas. All these new designs and modifications will improve

operational capability and reduce operational costs

without necessarily increasing the total certificated storage

capacity. It is advantageous environmentally and also

more cost effective to improve the cyclic capability of

existing underground field than to construct a new

depleted oil/gas field. It is important to recognize that

steadily increasing storage demands will not necessarily

be met with large investment in new storage fields in the

United States.

The level of total gas storage capacity has been relatively

flat for a number of years. During the past few years we

have seen an average of only one or two new underground

gas storage certificated per year. However, the National

Petroleum Council’s projected need of up to 700 Bcf of

new working storage capacity by 2025 discussed above

can be met by the construction of only 35 Bcf of working

capacity per year over the next 20 years. The industry

appears to be close to meeting or surpassing this goal based

on the storage projects that we have approved, have

pending before us or are expecting to be filed in the near

future. While several old storage fields have been

abandoned, others have been sold for less-active local

uses. However, over the past 10 years the Commission

has authorized many storage realignment applications to

improve injection/withdrawal and operational capability

of existing storage fields.
18 Current State of and Issues Concerning Underground Natural Gas Storage

Storage Economics Storage Economics

Successful storage infrastructure investments, as with all

private sector capital expenditures, must provide

attractive financial characteristics. Many investment

measures are used by industry to evaluate the commercial

viability of projects including, although not limited to,

net present value and internal rate of return. These

techniques provide different indicators of a project’s merit

but fundamentally each is a measure of cash flow benefits

relative to capital expenditures and operating expenses.

Independent, unregulated storage projects will generally

be expected to have returns on equity exceeding 20 percent

while jurisdictional storage projects will typically have

equity returns between 12 percent and 15 percent. The

higher return for unregulated projects, often salt-cavern

based, is due to the perceived market, geologic and

development risks.

Capital costs and cash flow, and hence, the economic

attractiveness of storage, depends upon the physical

characteristics and capabilities of a particular storage field,

the services to be provided and to a lesser extent,

regulatory regimes. Development costs vary greatly by

the type of storage and its performance characteristics.

The projected revenue and cash flow benefits differ for

facilities designed to ensure seasonal supply reliability

and meet daily or intra-day demand swings as compared

to capturing commodity arbitrage opportunities. Further,

regulators can restrict the ability of storage projects to

realize profits or, conversely, guarantee profits.

Consistent with the physical perspective that storage

amounts nationally are generally adequate and the

requirement for new storage is more of a chronic versus

acute need, the economics for new storage development

are not robust, with the exception of expansions of

existing fields. In particular, high-deliverability storage

projects that could serve to mitigate price levels and

volatilities as seen during the price spikes of 2003 and

2004 have particular challenges in matching value to

capital costs.

ECONOMICS OF UNDERGROUND STORAGE

Storage Development Costs Storage Development Costs

Among the three types of storage fields (salt cavern,

depleted reservoir and aquifer), salt caverns are generally

the most expensive to develop on a capacity basis.

However, because salt cavern storage can be cycled many

times (up to 12 times for some facilities), on a

deliverability basis it can be less costly than other types

of storage facilities.

A typical 6-12 cycle Gulf Coast salt cavern can costs

upwards of $10 million/Bcf of working gas capacity and is

higher in other regions, with Midwestern facilities the

next most expensive, followed by the Rockies, the

Northeast and finally California and the Pacific

Northwest. A typical 2-cycle depleted reservoir field can

cost between $5 million and $6 million/Bcf.1 6 The

following table summarizes broad ranges of development

costs.

16 Industry sources

2-Cycle 

Reservoir

6-to-12 Cycle 

Salt Cavern

Gulf Coast

Northeast 

and West

Source: Industry sources

$10 - $12 million

As much as $25 million

Type 

Development Costs 

Per Bcf of Working 

Gas Capacity

$5 - $6 million

Development Cost of 

Working Gas Storage 
19 Federal Energy Regulatory Commission • Staff Report • September 30, 2004

Generalizations aside, costs are site-specific based on:

• the quality and variability of the geologic

structure of the proposed site;

• the amount of compressive horsepower

required;

• the type of surface facilities needed;

• the proximity to pipeline infrastructure; and

• permitting and environmental issues.

Significant project development effort must be done before

a storage site is located and planned, increasing the risk

of project delays and cost overruns.

The cost of base gas is one of the most expensive elements

of a storage project. As a rule of thumb, the total capacity

of depleted reservoirs normally consists of 50 percent base

gas. Expansions of existing reservoir storage, however,

can significantly reduce the need for base gas. Total aquifer

storage field capacity is made up of between 50 percent

and 80 percent base gas. A salt cavern storage field typically

requires 25 percent base gas. However, leaching and brine

disposal costs for salt caverns are high. This is due to the

large amounts of water needed to leach a salt cavern and

the environmental problems associated with disposing

of the brine during the leaching process.

The majority of recent storage projects involve re-working

and expanding older high-quality depleted reservoirs to

generate higher deliverability using new technologies

such as horizontal drilling. These projects minimize

development costs by leveraging the existing infrastructure

and avoiding many environmental issues.17 In addition,

field performance is easier to judge because the

characteristics are already known.

The table in he next column summarizes recent examples

of storage development costs.18

17 CBI Storage Conference, Houston, Texas, February 23-24, 2004.

18 Dominion Application, CBI Storage Conference, February 23-24, 2004.

The Value of Storage

The value of storage will depend on what function storage

provides with different purposes, for instance, for

reliability of supply, imbalance management, seasonal

arbitrage and trading. Storage operators and customers

have developed sophisticated techniques for valuing

storage based on option theory. Consistent with the

variety of storage uses are a range of valuation approaches

that include:

• Cost of Service Valuation;

• Least Cost Planning;

• Seasonal Valuation (Intrinsic); and

• Option-Based Valuation (Extrinsic).

Cost of Service Valuation

Cost-of-service is used to value services offered by

regulated storage providers such as interstate pipeline

Source: Dominion Resources, Inc, CBI Storage Conference, 

Feb. 23-24, 2004 

Gulf Coast 

Salt 

Cavern

Northeast 

Reservoir 

Storage

Capacity (BCF) 5 9.4

Deliverability 500 147

(MMcfd) (est.)

Base Gas Cost 

($ Millions) 12 3.2

Total Development 

Costs ($ Millions) 65 39.5

Gas Storage 

Development Costs 
companies. It allows for recovery of costs and a return on

capital. Published rates and tariffs are maintained.

Services priced in this manner include firm storage

service, no-notice storage service, interruptible storage

and parking and lending services. Based on a review of

20 storage operator tariffs, the median cost-of-service rate

per Dth of annual working gas capacity for firm storage

service is $0.64.19 A summary of the tariff rates is provided

in Appendix A.

Most cost-of-service regulated storage is reservoir storage.

A cost-of-service rate for high-deliverability salt cavern

storage would be much higher than traditional storage.

As a hypothetical example:

– Capital cost = $60 million for a 5-Bcf Gulf Coast cavern

– Annual Cost of service = $14.63 million20

– Unit storage cost = $2.93 per Mcf per year

Seasonal Valuation

The seasonal valuation of storage is called the intrinsic

value. It is the difference between the two prices in a pair

of forward prices and does not include trading benefits.

This strategy, based on locking-in forward spreads, is

simple to execute, both financially and physically. The

seasonal spread for next winter is demonstrated in the

following table.21

Source: Derived from New York Mercantile Exchange data

Delivery Month Forward Price

Jul-05 5.933

Aug-05 5.955

Sep-05 5.950

Oct-05 5.985

Nov-05 6.225

Dec-05 6.438

Jan-06 6.578

Feb-06 6.538

Mar-06 6.380

Monthly Contract Values 

for Natural Gas Futures 

The differential for July 2005 to January 2006 is ($6.578-

$5.933)/(1.05) = 62¢ as of September 3, 2004, and assuming

one year of discounting at 5 percent (thus, the

denominator of 1.05). More conservatively, the seasonal

spread assuming average values over the entire injection

and withdrawal periods would be approximately 47¢. The

more conservative estimate uses average prices for the

seven-month injection and five-month withdrawal

season as compared with using the highest and lowest

values.

While the spread is 47¢-62¢, for the 2005-05 winter the

spread going into the current winter widened to $1.84 for

October 2004 to January 2005. This differential was high

by historical standards and was largely the result of falling

October prices rather than increasing January prices;

January prices remained relatively stable during this

period. This appeared to reflect an adequate supply of

gas in the market due to a mild summer with reduced

cooling demand. In terms of ability to store excess

production, if more storage capacity were available at these

prices, it’s likely that gas would have been injected into it

and prices wouldn’t have fallen so much. Eventually,

this would have resulted in a reduction in January prices

under “normal” weather expectations, or increased

reliability to handle extreme demand situations.

However, with regard to the planning horizon for storage

development, developers would look to next year’s prices

and beyond to economically justify projects as compared

to a short-term spread of three to four months.

Historical seasonal spreads for a variety of locations are

shown in the following chart.22

19 Staff review of rates and tariffs as maintained on informational

postings. 20 Staff calculation assuming: return on equity of 13 percent, debt cost of

8 percent, 50/50 debt/equity ratio, 34 percent federal tax rate, 3 percent

state ad valorem tax, 20-year book life and 10-year tax life.

21 Staff analysis of September 3, 2004, settlements on the New York

Mercantile Exchange (Nymex).

22 Staff analysis of Gas Daily data, nominal values.

20 Current State of and Issues Concerning Underground Natural Gas Storage
Option-Based Valuation for High-Delivery Storage

High-deliverability storage provides trading benefits that

increase with the number of turns, or cycles, per year.

This is often referred to as the extrinsic value of the storage

and is in addition to the intrinsic value.

The premium of extrinsic value is similar to a call option

on a time spread, increasingly so for a high delivery facility.

This gives storage holders the opportunity, although not

the obligation, to inject at one time and withdraw at

another time. Similar to any option, the value is

proportional to forward prices, price volatility, strike price

and time to expiration.

The chart on the following page illustrates the difference

between extrinsic and intrinsic values.

Average Gas Price Differentials Between Summer and Winter Seasons

Source: Derived from Platts Gas Daily data Avg. $/MMbtu

-1

0

1

2

3

4

5

6

Period 1 

(1998-1999)

Period 2 

(1999-2000)

Period 3 

(2000-2001) Period 4 

(2001-2002)

Period 5 

(2002-2003)

Period 6 

(2003-2004)

Long Term Averages:

Henry Hub $0.65

Dominion NP $1.10 

Dominion SP $0.92 

Northwest $1.57

Chicago $0.72

Henry Hub Dominion North Point Dominion South Point Northwest Chicago

21 Federal Energy Regulatory Commission • Staff Report • September 30, 2004
22 Current State of and Issues Concerning Underground Natural Gas Storage

If all opportunities for injection and withdrawal are

successfully exploited, the value of the multiple-turn

facility will be several times the value of a single-turn

facility with no opportunities to take advantage of market

prices. Current, average estimates of extrinsic values in

the Gulf Coast range from $1.00 for a three-turn facility to

$1.30 for a nine-turn facility, resulting in total storage

valuation, including both seasonal arbitrage and extrinsic

trading benefits, of approximately $1.60 to $1.90 for the

three-turn and nine-turn facilities, respectively.

The chart on the next page demonstrates the extrinsic

value as compared to storage cycles.23

23 The extrinsic value is determined by not only the spread between future prices for injection periods and future prices for withdrawal periods, but

also by the volatility of prices along the natural gas futures curves curve and the degree to which the individual months move together as measured

by correlation. The more volatile and less correlated the prices for individual months are, the greater the probability that the spread between prices

for an injection month and a withdrawal month will widen. This is in turn increases a storage facility’s potential profitability.

Difference Between Intrinsic and Extrinsic Value of Natural Gas Storage

Source: Based on New York Mercantile Exchange data $/MMBtu

Nymex Gas Contracts, July 2003 and January 2004

4

4.5

5

5.5

6

6.5

7

3/1/03 4/1/03 5/1/03 6/1/03 7/1/03 8/1/03 9/1/03 10/1/03 11/1/03 12/1/03

Intrinsic value of storage =

the difference between the cost of July '03 

gas (here at contract expiration) and the 

value of Jan '04 gas sold the same day

Jan. '04

contract

July '03

contract

Opportunity for additional value on July-January spread

Cost of July gas in storage 

fixed after contract expiration
23 Federal Energy Regulatory Commission • Staff Report • September 30, 2004

Extrinsic Value of Natural Gas Storage

Source: Analysis of New York Mercantile Exchange forward prices and Bloomberg data Storage Valuation

Turns (Cycles)

1 2 3 4 5 6 7 8 9

High Correlation Low Correlation

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

$1.80
24 Current State of and Issues Concerning Underground Natural Gas Storage

Least-Cost Planning

Least cost planning is storage valuation as typically

performed by local distribution companies and other

large-volume gas customers. Storage is valued by

considering the savings resulting from not having to use

a more expensive option. There is a wide range of

valuations that are highly dependent upon a gas

consumers’ load profile. The following hypothetical load

duration curve illustrates least cost planning.

Using this evaluation technique and assuming the

incremental storage capacity is priced relative to long haul

Pipeline Capacity

Storage

Capacity

Interruption

Peak Shaving (LPG)

Incremental 

Storage Capacity

Least Cost Planning for Gas Storage

Source: Based on representative industry data MMcfd of sendout

1 Days Per Year 365 

pipeline capacity, the unit value for market area storage

given a 50 percent load factor is 70¢ to $1.10.24

Economic Summar Economic Summary and Conclusions onclusions

A summary of current, alternative valuations, depending

on use of the facilities, and based on the proceeding

analyses, is shown below. These approaches are not

mutually exclusive, all of them are currently in use, and

most prudent customers will use some combination in

quantifying value.

24 Does not take into account additional transportation capacity to make storage comparable to pipeline delivery. Chart is an illustrative load duration

curve.
25 Federal Energy Regulatory Commission • Staff Report • September 30, 2004

Source: Summary of industry and financial data cited in this report

Type $/Mcf of Working Gas

Storage Median Cost-of-Service $0.64

Storage Seasonal Spread (Intrinsic) for Winter 05/06 as of August 2004 $0.47 to $0.62

Least-Cost Planning (Generally Applies to Reservoir Storage) $0.70 to $1.10

Salt Cavern Hypothetical Cost-of-Service (Gulf Coast) $2.93

Salt Cavern Market Value (Intrinsic plus Extrinsic Gulf Coast) $1.60 to $1.90

Varying Costs of Gas Storage 

Seasonal spreads, ranging from 47¢ to almost 62¢ for the

winter of 2005-06 as of September 2004, are comparable to

the cost expansions of reservoir storage, and indicate

storage supply and demand are reasonably in balance on

a national level. However, storage may be the best way

of managing gas commodity price volatility under more

extreme weather conditions, so the long-term adequacy

of storage investment depends on how much price

volatility is considered “acceptable”. The public policy

interest in volatility mitigation may be different than

wholesale market valuations.

Although storage costing less than or near its intrinsic or

seasonal arbitrage value will always be fully subscribed,

the market value of storage relative to its costs currently

does not provide incentives for most independent storage

development. Project economics are a challenge for salt

cavern storage. At a market value of approximately $1.60

to $1.90/Dth/year, it is difficult to justify developing salt

caverns outside of the low-cost Gulf Coast. Project

developers are not likely to achieve a cost-of-service

comparable returns that would require a rate approaching

$3 in the Gulf Coast and much higher elsewhere where

development is more expensive.

The financial and regulatory circumstances of storage

customers can hinder storage development. Even if a

proposed new storage facility is economic, state regulatory

policies may inhibit its development. Because state

regulators exercise prudence reviews for cost recovery of

new storage facilities, it may be easier for local distribution

companies to simply purchase gas at index rather than

invest in facilities to mitigate volatility. Thus, many

local distribution companies do not see the value of

entering into storage contracts that reflect extrinsic value.

The Arizona Corporation Commission (ACC) recently

released a policy statement embracing the need for new

storage capacity and may be amenable to addressing this

problem by altering the incentives to contract for storage

service.

The loss of a vibrant trading sector means fewer customers

will pay for the trading benefits of storage. For instance,

one developer said he would be lucky to get $1 for storage

valued intrinsically and $1.60 extrinsically. The market

will often only pay for 50 percent of the extrinsic value to

account for the likelihood of not being able to realize the

full value.

Electric generators can use inexpensive pipeline

imbalance management that makes third party storage

less attractive as an alternative. Park and loan rates are

typically less than 20¢ per day and more palatable to

independent electric generators, especially given their

weak credit and inability to make long-term commitments

to storage. Finally, at high gas prices, base gas becomes a

barrier to entry for reservoir storage development and

also provides incentives to abandon existing fields to sell

the base gas.
26 Current State of and Issues Concerning Underground Natural Gas Storage

POSSIBLE OPTIONS FOR STIMULATING

UNDERGROUND STORAGE DEVELOPMENT

In prior sections we discussed how underground natural

gas storage is a valuable resource that can ensure service

reliability, serve as a substitute for gas transmission and

thereby reduce overall delivery costs, and through hedging

help moderate gas commodity price volatility. By all

accounts, demand for the natural gas resource will

continue to grow over the next 20 years, particularly with

respect to gas-fired electric generation. Gas storage

development is an essential element of the infrastructure

that will be necessary to reliably and efficiently serve

these new demands.

While current and projected storage development is

keeping pace with aggregate storage demands,

underground storage development in some market areas,

such as the Southwest and New England, has been

virtually non-existent. Few new projects in the Southwest

have been proposed and several have failed or face

significant opposition.25 The geology in these areas is

also not favorable to large scale underground storage

development, and competition from pipeline expansions

and LNG development may be dampening demand for

new underground gas storage. Further, state unbundling

initiatives limit the ability of LDCs, the traditional

purchasers of storage services, to renew or enter into new

contracts for long-term storage service, primarily due to

uncertainty over cost recovery at the local level and to

stranded cost considerations. Additionally, in the

Southwest, until the Commission reformed services on

the El Paso Natural Company system to put in place firm

contract demand levels for all of its customers,26 market

signals for new storage services were virtually nonexistent. Almost all gas service in the East-of-California

market was provided on a full requirements basis and El

25 The Red Lake storage project failed after being denied market-based rate authority for failing the Commission’s market power test. The Desert

Crossing storage and transportation project failed due to environmental issues and the contract support that did not materialize. The developers of

the Copper Eagle storage project failed to secure contractual support and have sold development rights to the project to El Paso Natural Gas Company

(El Paso). El Paso has yet to overcome local opposition to the project, secure contractual commitments and file for certificate authorization. Additionally,

no LDCs in these areas have pursued development of storage projects, which could be another indicator of demand for new storage.

26 See El Paso Natural Gas Co., 99 FERC ¶ 61,244 (2002); El Paso Natural Gas Co., 100 FERC ¶ 61,285 (2002); El Paso Natural Gas Co., 104 FERC ¶ 61,045 (2003).

Paso had no daily penalties for service imbalances. As a

result, El Paso’s customers had no need to individually

contract for storage services to meet peak demand or

pipeline balancing requirements.

Some independent storage developers, such as Red Lake,

assert that storage development is considerably more risky

than pipeline construction primarily because of the

inability to secure similar long-term contractual

commitments. They assert that in contrast with new

pipeline construction, where contract commitments are

typically in the 10 to 20 year range, contract commitments

for storage service exceeding a 1 to 5 year range are rare.

They contend that traditional cost-based storage rate

design will not encourage further development of storage

due to the evolving and risky nature of storage services,

the fact that the primary users of these new services (e.g.,

daily and intraday balancing, and commodity arbitrage)

are often not the traditional creditworthy LDCs, and that

traditional cost-based rates do not reflect the value of

service on peak, and do not reflect rates of return that

adequately account for the risky nature of these

investments. Additionally, they imply that affiliated

storage development has subtle, and in some instances,

tariff advantages over storage provided by independent

third parties, which may lead to increased costs and service

inefficiency for all customers. According to Red Lake, the

best and preferred way to permit them to fairly compete

and recover their costs is through the flexibility of marketbased rates. Pricing schemes short of market-based rates

may provide too little flexibility and shift too much risk

to independent storage providers to encourage storage

development.
27 Federal Energy Regulatory Commission • Staff Report • September 30, 2004

It is not entirely clear as to why, but the paucity of

underground storage project development in some areas

of the country may simply be attributable to market forces

and alternative service options. Whether regulatory

policies act as unnecessary barriers to further storage

development is a question that merits further inquiry.

Traditional cost-based storage service rate design, which

prices service on an average basis, may not accurately

reflect the value of service in peak periods; and rates of

return on equity may not reflect today’s risk and

shareholder expectations, or may no longer be appropriate

for new storage services at all. The Commission’s test for

authorizing market-based rates may not accurately capture

or measure the market power of storage providers

generally, or more narrowly of independent storage

providers. Also, pipeline services and tariff requirements,

as well as certificate applications filing requirements and

procedures, may be seen as a barrier to entry and

development.

Discussed below are various rate, service, tariff and policy

approaches the Commission could take to encourage the

development of additional underground storage projects.

These include: (1) options to traditionally developed costbased rates and incentive rates, as well as options for

periodic cost and revenue review; (2) market-based rates

for all new entrants; and (3) Commission policies to

increase service options or reduce costs.

Cost-Based Rate Options for Storage Development elopment

Peak/Off-Peak Rates and Term Differentiated Rates

The current storage rate design policy was developed for

storage service with a single yearly cycle of injection and

withdrawal. This rate design policy is known as the

Equitable method. Under this policy, 50 percent of a

project’s fixed costs are collected based on storage

deliverability and fifty percent are collected based on

storage capacity; no return on equity and related taxes are

permitted in the variable rate component (injection and

withdrawal charges). Furthermore, injection and

withdrawal charges are designed to recover only variable

costs. Potential storage providers fear that under this rate

design, capital costs will not be recovered,27 i.e., uniform

monthly rates do not adequately reflect variations of

service value, and may result in underrecovery of costs in

periods of low demand.

In Order No. 63728 the Commission recognized that

traditionally-designed rates with uniform maximum

prices permit short-term service customers to purchase

capacity at prices that may be lower than the market value

of the capacity, while off-peak capacity may go unused

without discounting. The Commission found that flexible

peak/off-peak or seasonal rates based on value of service

concepts (rather than specific costs), promotes allocative

efficiency by providing more efficient pricing signals.

Under this approach, customers that value capacity more

highly should be expected to pay higher prices when

capacity is scarce. Conceptually, peak/off-peak or flexible

rates may be designed in any number of ways. For

example, the value of service between peak/off-peak may

be determined using price differentials between specified

points. Alternatively, load factors or other measures for

attributing value may be used. However, under this

approach, any increase in rates at peak must be offset by

decreases in off-peak rates, such that the annual revenue

requirement is not exceeded. This ensures that the rates

remain cost based.

27 Seesupra note 5.

28 Regulation of Short-Term Natural Gas Transportation Services and Regulation of Interstate Natural Gas Transportation Services, Order No. 637, FERC Stats. &

Regs., Regulations Preambles, 1996- 2000 ¶ 31,091 (2000), order on reh’g, Order No. 637-A, FERC Stats. & Regs., Regulations Preambles, 1996- 2000 ?

31,099 (2000), order denying reh’g, Order No. 637-B, 92 FERC ¶ 61,062 (2000), aff ’d in part and remanded in part, Interstate Natural Gas Association of America

v. FERC, 285 F.3d 18 (D.C. Cir. 2002), order on remand, 101 FERC ? 61,127 (2002).
28 Current State of and Issues Concerning Underground Natural Gas Storage

While an annual revenue cap would limit the rates the

storage service provider may charge, it should allow

storage providers considerable flexibility to develop rates

that would allow full recovery of costs and encourage entry

into the market. Additionally, these flexible rates would

serve as the recourse/backstop rates in any negotiated

rate program. 2 9 Rates could be negotiated between

customers and the storage provider which are mutually

efficient and beneficial. Further, increased revenues from

peak short-term services reduces the level of costs that

need to be recovered from long-term customers, and

reduces the need for rate discounts in off-peak periods

and the associated cost shifting that occurs through rate

discount adjustments.

Similarly, storage providers could develop termdifferentiated rates, as contemplated in Order No. 637.

Term-differentiated rates do not differentiate between

seasons, as in the above discussion, but instead

differentiate based on the length of contract term. Rates

designed to reflect differences in contract terms recognize

that shorter term contracts subject the service provider to

more risk, and higher rates may be appropriate to

compensate the service provider for the additional risk.

Conversely, long-term contracts would reflect lower rates

for service on a comparable basis.

An alternative approach to flexibly marketing storage

services for storage operators would be through the use of

voluntary auctions. Auctions can be used in both the cost

(e.g., with an annual revenue cap) and market-based rate

regimes. As discussed in Order No. 637, properly designed

auctions can provide for efficient allocation of services,

reduce transactions costs and provide for more accurate

dissemination of relative pricing information to the

marketplace.30 Auctions also can be used as methods of

mitigating the effects of market power by limiting the

ability of sellers to withhold capacity, to price

discriminate, or to show favoritism.

Cost of Service Adjustments

An additional cost-based rate option for encouraging

investment in underground storage could be accomplished

through adjustments to the cost of service, i.e., the annual

revenue requirement of the project. For example, an

equity return premium to reflect higher risks associated

with storage development, or accelerated depreciation

could induce entry by allowing higher maximum rates.

In this example higher rates would occur because (1) the

normal cost of equity would be increased by a premium to

reflect higher risk or simply to incent development, and

(2) the depreciable life of the storage project’s assets would

be shortened. Accelerated depreciation allows the full

cost of capital to be recovered more quickly.31 It may

seem counter-intuitive to grant cost adjustments that

would increase costs when storage developers argue they

cannot recover costs under traditionally designed costbased rates. However, the higher maximum rates allow

more revenue collection during periods of peak demand.

Further, these cost adjustments could be coupled with

flexible peak/off-peak, seasonal or other rate design

methods that reflect periodic differences in the value of

service.

Additional rate policy options could be considered to

address storage developer cost recovery concerns. One

such option would be to permit storage developers to use

unit of throughput depreciation. Under this approach,

accounting would follow revenues and storage developers

might avoid losses in the early years of a project.

Alternatively, regulatory asset treatment could be

29 Under the Commission’s negotiated rate policy, rates can be negotiated as long as customers can always choose service under an approved cost-ofservice recourse rate, also known as the recourse rate. Alternatives to Traditional Cost-of-Service Ratemaking for Natural Gas pipelines and Regulation of

Negotiated Transportation Services of Natural Gas Pipelines, 74 FERC ¶ 61,076 (1996), reh’g and clarification denied, 75 FERC ¶ 61,024 (1996) (Policy Statement).

30 Minimum bid criteria could be established to ensure full cost recovery.

31 Accelerated depreciation may require the Commission to waive its tax normalization policy regarding adjustments to the rate base.
29 Federal Energy Regulatory Commission • Staff Report • September 30, 2004

conditioned for unrecovered costs in the short term.

These unrecovered costs would be reflected in future rates.

While such an option would deviate from traditional

Commission cost-based ratemaking policy, it would better

ensure full recovery of storage development costs over

the long term and thereby incent development.

Modification of the Requirement for a Three-Year

Revenue Review

Another approach for incenting development of

underground storage would be to modify the

Commission’s current certificate policy of requiring cost

and revenue studies to be filed within three years of

certification of new projects. Elimination or modification

of this requirement would, at a minimum, delay or

lengthen the maximum time for a review of a project’s

costs and revenues. Under such an approach, storage

providers will be afforded greater certainty with respect

to the initial rates, which could translate into additional

incentives to construct and operate storage projects. As

above, this option maintains the Commission’s ability to

use Section 5 of the Natural Gas Act to ensure that the

cost-based recourse rate remains just and reasonable.

Market-Based Rates

The Commission’s authority to authorize market-based

rates is premised on the theory that the just and reasonable

standard of the Natural Gas Act, the Federal Power Act

and the Interstate Commerce Act does not limit the

Commission to any particular ratemaking methodology;

rather, the Commission has flexibility in selecting rate

making methods. The Commission has developed tests

of competitiveness for the purpose of determining if

market-based rate authority should be granted. These

tests are based on the market competitiveness analysis in

the U.S. Department of Justice and the Federal Trade

Commission, Horizontal Merger Guidelines (1997).

In 1996, the Commission issued Alternatives to Traditional

Cost-of-Service Ratemaking for Natural Gas Pipelines and

Regulation of Negotiated Transportation Services of Natural Gas

Pipelines (Policy Statement)3 2 which established a

framework for analyzing market-based rate proposals in

gas pipelines (which includes gas storage). The Policy

Statement’s framework addresses whether the applicant

has market power; that is, can the applicant: (1) withhold

or restrict services to increase price a significant amount

for a significant period of time, or (2) discriminate unduly

in terms of price or conditions. Before the Commission

can conclude that a seller cannot exercise market power it

must either (1) find that there is a lack of market power

because customers have sufficient “good alternatives” or

(2) mitigate the market power (i.e. ,permit market-based

pricing only if specified conditions are met that prevent

the exercise of market power).

In Order No. 572, the Commission amended its

regulations to adopt filing requirements with respect to

applications for market-based rates by oil pipelines.33 The

framework created by these required filings is essentially

the same as described above for the competitive analysis

of gas pipelines.

With respect to granting a public utility the authority to

make market-based sales of electric power, the

Commission must determine that the applicant does not

have the ability to exercise market power in generation.34

The Commission determined in Kansas City Power &

Light Company35 that it is no longer necessary to examine

generation market power when considering market-based

rate applications for sales from new generation units. This

was codified in Order No. 888, section 35.2736 of the

Commission’s regulations, providing, in relevant part,

the following:

Notwithstanding any other requirements, any public

utility seeking authorization to engage in sales for resale

3274 FERC & 61,076 (1996), reh’g and clarification denied, 75 FERC & 61,024 (1996); see supra note 27.

33 Market-Based Ratemaking for Oil Pipelines, FERC Stats. & Regs., Regulations Preambles 1991-1996 ¶ 31,007 (1994) ; 18 C.F.R. § 348.

34 The other considerations are whether the applicant has transmission market power, whether the applicant can erect barriers to entry, and whether

there is potential for affiliate abuse and reciprocal dealing. See Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation

Policy, 107 FERC ¶ 61,018 (2004).

35 67 FERC ¶ 61,183 (1994).

36 18 C.F.R. § 35.27 (2003).
30 Current State of and Issues Concerning Underground Natural Gas Storage

of electric energy at market-based rates shall not be

required to demonstrate any lack of market power in

generation with respect to sales from capacity for which

construction has commenced on or after July 9, 1996.37

However, as the Commission stated in Order No. 888, it

will consider whether an applicant, properly citing section

35.27, nevertheless possesses generation market power if

specific evidence is presented by an intervenor.38

As noted above, independent storage developers assert

that pricing schemes short of market-based rates may

provide too little flexibility and shift too much risk

therefore discouraging storage development. But, under

the Commission’s traditional tests for market

competitiveness, demonstrating lack of market power may

not be possible in all areas of the country. For example,

conditions in western storage markets, particularly market

concentration and entry conditions, make it impossible

for significantly-sized storage projects to demonstrate that

they lack market power under tests the Commission has

developed to evaluate market competitiveness.39

However, to the extent that it is desirable to encourage

further storage development, the following options or

alternatives for granting market based rate treatment

could be considered.

Market-Based Rates for New Independent Storage

Projects

In this first approach, Commission policy would be

modified to allow market-based rates for new independent

storage providers, subject to possible mitigation measures,

on the grounds that new storage projects add incremental

capacity to existing markets, thereby giving customers

new choices for services, and with the provision that all

market risks lie with the projects’ owners (i.e., no captive

customers). The Commission could determine marketbased rates for new independent storage projects to be

just and reasonable because customers are better off than

they would be if the project was not built, and customers

will face additional service options because of the new

infrastructure provided by the new storage project.

Since the new project’s owners assume all market risk

and have no captive customers to pass costs on to, they

must successfully sell storage in order to cover fixed costs

and try to make a profit. Under this theory, customers

can always choose to not use the new project and act as

they would if the project had not been built.40 As a result,

project sponsors must price their services at rates that are

low enough to attract customers. That is, customers are

better off paying the market-based rates than they would

have been if the project had not been built.

The rate flexibility provided by this option allows an

unlimited upside for rates in periods when storage has

high demand41 to compensate for the periods when storage

has low demand and investment costs are not recouped.

Further, to the extent the Commission is concerned with

the potential for high market-based storage service prices

in times of great scarcity, it could consider mitigation

measures, such as requiring that capacity be sold through

open and transparent auctions. While this requirement

may not mitigate prices under all supply and demand

scenarios, it would ensure that the storage service provider

did not withhold capacity to drive up prices.

Alternatively, the Commission could require periodic

review of market-based rate storage services. Again, this

approach may not directly mitigate high prices in all

situations, but it would provide the Commission an

opportunity to review rates and services.

37 See 18 C.F.R. § 35.27 (2003).

38 See Promoting Wholesale Competition Through Open-Access Non-Discrimination Transmission Services by Public Utilities; Recovery of Stranded Costs by Public

Utilities, Order No. 888, FERC Stats. & Regs., Regulations Preambles 1991-1996 ¶ 31,036 (1996) .

39 See supra note 5.

40 The California Public Utility Commission largely authorized the construction and operation of the Wild Goose Storage Inc. project on this basis

(see Appendix B for full description).

41 This is, in part, what happened in California electricity and gas markets in 2000-2001.
31 Federal Energy Regulatory Commission • Staff Report • September 30, 2004

Finally, the Commission might consider removing the

rate cap on capacity release transactions and other shortterm and interruptible services. The theory behind this

alternative is that service providers and customers with

existing cost-based storage or transmission capacity would

have an incentive to compete with the storage provider,

and thereby keeping storage prices down.

Reviewing the Market Power Test for Adequacy in

Storage Markets

An alternative to granting market-based rates to all new

independent storage projects, would be to find that the

current test for market power does not accurately measure

it. Some storage developers assert that they are unable to

secure long-term service agreements as pipelines do in

construction applications. Accordingly, to the extent a

storage provider could demonstrate an inability to secure

firm service contracts for the entire capacity of its storage

field, for terms exceeding some specified time, such as 1,

2 or 5 years, the Commission could find it lacked market

power, and grant market-based rate authority. The

Commission would likely want to establish guidelines,

in advance, for such capacity offerings to ensure they were

conducted on an open and transparent basis, and barriers

to longer term contracts were not established.

The mitigation measures discussed in the previous section

could be applicable to these alternative approaches, as

well.

Revise or Waive Commission Policies olicies

It has been suggested in informal discussions with

companies that are considering storage projects, that entry

into storage would be assisted by waivers or exemptions

of certain environmental and certificate analyses, affiliate

rules, open access requirements for offering firm and

interruptible service, and prohibitions against making

bundled sales. The Commission could consider initiating

an industry dialogue to explore possible improvements

to the current process for environmental review and

certificate authorization. For instance, the current blanket

certificate program is not available for storage related

activities except for initial testing and development.

However, since the existing regulations have long

indicated that certain types of storage projects are usually

not major federal actions, and because the issues that are

unique to the development of storage fields are very

limited, the Commission could consider revising its

regulations to add certification of storage projects to the

blanket program. In addition, the industry is only

beginning to avail itself of existing Commission programs

such as the Pre-Filing Process for storage fields. Either or

both of these possible avenues may assist in allowing

storage projects to be approved more quickly.

Further, storage providers have asserted that waivers of

various open-access requirements and limitations on

operators to engage in commodity arbitrage for their own

account limit their ability to maximize or capture the value

of their investment. To the extent the Commission

believes development of storage assets is essential for

ensuring service reliability in all markets, it could consider

revising open-access requirements to encourage storage

development. The Commission could protect against

potential market abuses by requiring the storage

providers to file periodic reports on their activities and

revoke any waivers after considering complaints by

customers or potential customers.
32 Current State of and Issues Concerning Underground Natural Gas Storage

ANR $2.3999 $0.2449 $0.0084 $0.74 181.3 333.5 TX Depleted Reservoir

BLUE LAKE GAS STORAGE $1.8027 $0.0258 $0.0990 $0.58 42.0 49.0 MI Depleted Reservoir

COLUMBIA GAS TRANSMISSION $1.5080 $0.0290 $0.0153 $0.69 243.1 669.6 WV Depleted Reservoir

DOMINION $1.7984 $0.0145 $0.0154 $0.56 382.2 755.8 WV Depleted Reservoir

MICHIGAN GAS STORAGE $0.8357 $0.0136 $0.0190 $0.21 34.0 109.5 MI Depleted Reservoir

MIDWEST GAS STORAGE $4.5272 $0.0463 $0.0056 $0.96 0.9 4.5 IL Aquifier

NATIONAL FUEL $2.1556 $0.0432 $0.0139 $0.47 149.3 317.9 NY Depleted Reservoir

NATURAL GAS PIPELINE CO $1.2900 $0.2881 $0.0197 $0.59 205.3 603.3 TX Depleted Reservoir and Aquifier

NGO TRANSMISSION $1.6373 $0.0320 $0.0726 $0.36 1.5 5.1 OH Depleted Reservoir

NORTHERN NATURAL GAS CO $1.5874 $0.3854 $0.0225 $0.75 55.3 206.0 TX Depleted Reservoir and Aquifier

PANHANDLE $2.9700 $0.4246 $0.0385 $0.71 74.0 TX 

QUESTAR $2.8533 $0.0238 $0.0105 $0.63 53.0 139.5 UT Aquifier

SOUTHWEST GAS STORAGE $2.8496 $0.3419 $0.0015 $0.91 57.1 165.5 TX Depleted Reservoir and Aquifier

TEXAS GAS TRANSMISSION $1.4318 $0.0304 $0.0166 $0.68 86.2 176.2 KY Depleted Reservoir and Aquifier

TRANSCO $2.7208 $0.0152 $0.0322 $0.78 182.7 312.9 TX Depleted Reservoir and

Salt Cavern

TRUNKLINE GAS COMPANY $3.5985 $0.5767 $0.0005 $0.77 12.9 42.8 TX Depleted Reservoir

YOUNG GAS STORAGE $1.5620 $0.0590 $0.0200 $0.41 5.3 9.9 CO Depleted Reservoir

APPENDIX A

Pipeline Company Max Daily

Deliverability

Max

Seasonal

Capacity

Gas Storage Tariff Rates

Injection /

Withdrawal

Commodity

Rate

Annual

100% Load

Factor

(60 storage days)

Working

Capacity

(Bcf)

Total

Capacity

(Bcf)

Facility

State Facility Type

[ Revised October 15, 2004 ]

Sources: Capacity data from Platts GASdat; tariff information from company filings with FERC.
33 Federal Energy Regulatory Commission • Staff Report • September 30, 2004

APPENDIX B

Example of State Regulatory Approach

In late June 1997, Wild Goose Storage Inc. became

California’s newest gas utility and the state’s first

independent storage provider. The Wild Goose storage

field is located in the southwest corner of Butte County in

California at the site of the depleted Wild Goose natural

gas field. It has a working gas volume capacity of 24 Bcf,

a maximum injection rate of 450 MMcf/d, and a maximum

withdrawal rate of 480 MMcf/d. The field is connected to

the PG&E transmission system and can be used to manage

imbalances and OFOs on the PG&E system.

The California PUC set out rules for independent natural

gas storage facilities which exempt independent gas

storage providers from traditional cost-of-service

ratemaking, but subjected them to the regulatory

jurisdiction of the PUC. The developers of the project

must take the risks for its commercial performance without

any direct recourse to the customer of the utility system.

Finding that as a new entrant without market share Wild

Goose will lack market power, the CPUC authorized Wild

Goose to offer its storage services at market-based rates

under tariffs that set rates within a rate window.

In order to prevent predatory pricing, the floor rate could

not be set below Wild Goose’s short-run marginal cost,

but Wild Goose had substantial freedom to set the ceiling

rate, under the theory that its potential customers would

not be captive but may choose other storage providers.

The CPUC was unable to determine that Wild Goose could

not exercise market power. Neither could the CPUC

determine that the potential for Wild Goose to exercise

market power was fully mitigated by its lack of control of

the transportation system or by other factors.

The CPUC revoked the relaxed reporting requirements

approved in prior decisions. The CPUC placed reporting

requirements such as interactions between a utility and

its affiliates, changes in status that would reflect a

departure from the characteristics the Commission relied

upon in approving market-based rates, and providing

service agreements for short-term transactions (one year

or less).