Natural Gas as a Commodity
and the Role of Storage

Regulatory restructuring during the past 15 years has fostered
the development of natural gas as a commodity distinct from
the bundled sales and transportation service previously
provided by pipeline companies. Several events contributed
to this development, including:

© The deregulation of wellhead markets

© The development of active spot markets scattered
throughout the United States

© The opening up of the transportation system, which
allows gas to flow more freely between markets

© The growth of the futures market, which enables buyers
and sellers to obtain information on the expected price
of gas throughout the day.

These factors have contributed to making natural gas similar
to other commodities such as corn, sugar, copper, and cotton
in that prices for these commodities are:

© Dependent on current and expected supply and demand
conditions

© Readily available on a daily basis from printed and
electronic media

© Indicative of broad and regular trade on public markets
throughout the country.

In other ways, however, natural gas as a commodity has some
relatively unique characteristics that affect the price
consumers pay for the commodity and also the size of the
market. In contrast to agricultural foodstuffs, for example,
natural gas is produced throughout the year. Demand for gas
on the other hand is highly variable throughout the year and
depends greatly on the weather, whereas demand for most
commodities is relatively constant during the year.

These different patterns of supply and demand for natural gas
have resulted in a much more important role for storage than
in most other commodity markets. Moreover, underground
storage operations interact with all phases of the natural gas
market.

© Storage smooths the production of gas, which
continues throughout the year. Historically, the major
role of storage in production has been to smooth natural
gas production between the peak and off-peak seasons

by supplying places to store gas in the summer when the
use of gas is low in major residential and commercial
consuming regions. The smoothing of production
reduces the cost of gas to end-use customers.

© Storage withdrawals help satisfy sudden shifts in
demand and supply caused by weather. Changes in
the weather can greatly influence gas demand.
Extremely cold weather throughout the United States,
including in the major gas-producing areas, may also
influence the supply of gas if well freezeups occur.
Thus, weather can influence the price of gas through
both supply and demand effects. The availability of
stored gas can help consumers avoid the high cost of
gas at these times. Thus, stored gas is used to
supplement gas from production sites and also as the
primary source of natural gas for end-use markets at
such critical times.

© Underground storage operations are closely
coordinated with the entire gas distribution system.
Underground storage of gas is unique in comparison
with other commodities in terms of its integration with
the distribution system to maintain overall system
integrity. Storage reservoirs are used as a convenient
place to store gas when more gas is moving along
pipeline systems than currently needed, and a
convenient place to obtain gas when gas flow on the
pipeline system is insufficient to maintain the pressure
needed to sustain the system's deliverability capability.
Stored gas is also used to adjust a customer's scheduled
receipts and deliveries of gas from a pipeline company.
Thus, storage is used to balance the system. The
capability of storing gas underground in producing and
in consuming regions has great inherent value to the gas
industry.

The development of natural gas as a commodity has also
influenced the way storage is used. With the development of
active spot and futures markets, it is now possible regularly to
adjust purchase decisions to price conditions. For example,
buyers of gas are now encouraged to purchase amounts of gas
that exceed planned levels and place the gas in storage if
prices suddenly drop from expected levels. By doing this they
expect to be able either to sell the gas at a higher price in the
future or to avoid the expected higher cost of gas at a later
date, These responses tend to temper price increases and to
shorten the time during which high prices are sustained.

SThe development of futures markets has also influenced decisionmaking
in other energy markets. See Charles Dale and John Zyren, "The Effects of
Crude Oil Commoditization on Gasoline Markets," Atlantic Economic
Journal, 3, 33 (September 1994), p. 89, and the references cited therein,

6 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Table 1.

Monthly Natural Gas Injections, Withdrawals, and Working Gas Levels,

Heating Years, 1982-83 Through 1986-87 and 1989-90 Through 1993-94

(Million Cubic Feet)

Average Injections per Field Average Withdrawals per Field Average Working Gas per Field
Period 1982-83 | 1989-90 1982-83 | 1989-90 1982-83 | 1989-90
Through | Through | Volume | Percent | Through | Through | Volume | Percent | Through | Through | Volume | Percent
1986-87 | 1993-94 | Change | Change | 1986-87 | 1993-94 | Change | Change | 1986-87 | 1993-94 } Change | Change
Nonheating
Season
April 449 577 128 29 305 377 72 24 3,616 3,849 233 6
May 832 1,017 185 22 89 137 48 54 4,359 4,737 378 9
June 864 = 1,061 197 23 70 109 39 56 5,153 5,687 534 10
July 922 1,016 94 10 82 129 47 57 5,993 6575 582 10
August 862 991 129 15 101 147 46 46 6,754 7,419 665 10
September 787 960 173 22 68 134 66 97 7,472 8,214 742 10
October 584 77 133 23 164 260 96 59 7,892 8676 784 10
Monthly
Average 787 906 149 20 126 185 59 47 5,891 6,451 560 10
Heating
Season
November 264 342 78 30 572 757 185 32 7,401 8,356 955 13
December 158 239 81 51 1,285 1,456 171 13 6,274 7,072 798 13
January 112 220 108 96 1,673 1,535 138 8 5,041 5,551 510 10
February 151 173 22 15 1,166 1,384 218 19 4,026 4,340 314 8
March 249 Ht 62 25 799 997 198 25 3,476 3,655 179 5
Monthly
Average 187 257 70 37 1,099 1,217 118 1 5,247 5,734 487 9
Heating
Year
Monthly
Average 520 642 122 23 531 644 113 21 5,623 6160 537 10

Note: Before 1991, data were available only on a company-wide basis. For field-level data prior to January 1991, company totals were
apportioned based on the January 1991 ratio of the field’s working capacity to the company total working gas capacity. Only those fields
active throughout the 1982-1993 period were included. A heating year is from April of one year through March of the next year; for example,
Aprit 1982 through March 1983 is the 1982-83 heating year. Data are not adjusted for weather.

Sources: 1982-83 through 1990-91; Energy Information Administration, EIA-191/FERC-8, "Underground Gas Storage Report." 1991-92
through 1993-94: Energy Information Administration, EIA-191, "Underground Gas Storage Report."

As the industry adjusted to the more competitive environment
under open-access transportation programs, the lower
monthly inventories and increased injection and withdrawal
activities throughout the year seem to indicate a fundamental
adjustment relating to the economics of storage use and a
reassessment of what storage levels are adequate for supply
reliability. Certainly, the progressively lower inventory levels
from 1991 through 1993 for any given nonheating season
month equate to money saved on inventory costs and imply
that management of stored gas was becoming more efficient.

Changes in inventory management occurred in 1994,
however, that reversed some of these recent trends
(Figure 19). By contrast to the past few years, the percentage
of working gas capacity filled in 1994 was higher at the start
of the nonheating season than it had been the preceding year,
and by September had exceeded the point reached at the same

Energy Information Administration

time in the three previous years. By the beginning of the
1994-95 heating season, the percentage had reached 83
percent.

Another recent deviation has been the decline in weather-
adjusted withdrawal activity during the past two heating
seasons (Figure 18). Some of this change is attributable to the
effects of capacity constraints on storage assets: less storage
capacity was available for nonweather-related activities as
winter weather in the past two heating seasons returned to
normally cold temperatures (after the three preceding heating
seasons of warmer-than-normal weather). However, the larger
decline in the 1993-94 heating season may be attributed to the
changes taking place in inventory management and operations
during the first heating season under Order 636. Beginning
November 1, 1993, a significant proportion of working gas
capacity previously managed by interstate pipeline companies

27

The Value of Underground Storage in Today's Natural Gas Industry



Figure 16. Daily Spot Prices Rise as Cold Weather Index Increases

4.00 5

Feb. 2

.
3.50 - Feb. 3
Feb.1 +
.
.
3.00 . .
.

Trend Line

2,50 4

Henry Hub Spot Price (Dollars per Million Btu)

T T T T T 1
0 50 100 150 200 250 300

Cold Weather Index (Cumulative Fahrenheit Degrees Colder than Normal)

Note: The Trend Line is the result of a least-squares regression. Data are for January 3 through February 28, 1994, excluding weekends

and holidays,
Sources; Regression Results: Energy Information Administration, Office of Oil and Gas; derived from: Henry Hub Spot Prices— Pasha

Publications, Inc., Gas Daily; and Cold Weather Index—temperature data from National Oceanic and Atmospheric Administration, National
Climatic Data Center. (See Appendix D.)

Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry

23



The Premium and Temperature Deviations
(Page 18)

Specification and Estimation

After examining the relationship between monthly spot prices and storage requirements, the next analysis focuses on daily data.
The first objective is to examine how the value of having gas in storage might change between days. One way to estimate this
value is to compute the difference between the daily spot price (DSP) for natural gas at the Henry Hub and the daily futures price
(DFP) for natural gas for the nearby month contract (the contract that is next to terminate on the futures contract market).
(Deliveries under a futures contract take place at the Henry Hub.) The difference in these prices is referred to as the "premium"
in the main body of the text, and is denoted here as PR. It is also referred to as the basis by some, or the basis between the spot
and futures prices at the Henry Hub to distinguish it from a locational basis. After gathering appropriate price information from
spot and futures markets, it was observed that PR increased dramatically during the cold spell in mid-January 1994.

The magnitude of PR = DSP - DFP at different points in time is in part a consequence of the cost of storage and the cost of
borrowing money. These costs are implicitly contained in DFP. The magnitude of PR also reflects the convenience of having
gas on hand (a marginal convenience value or yield). If the cost of storage (CS) and the cost of borrowing money (CM) is first
subtracted from the futures price, then the difference between the spot price and this adjusted futures price is equal to the marginal
convenience value or yield (CY) (i.e., DSP - (DFP - CS - CM) = CY or PR+ CS + CM=CY).

The degree to which several other variables might be related to PR is examined next. The first step is to examine previous
investigations of the relationship between CY and other variables (early but still relevant investigations of CY include [10,11]).
It is difficult, however, to draw lessons from these analyses because they examined commodities with a relatively constant
demand throughout the year (for a theoretical discussion of distinguishing features of the economics of gas markets and gas
storage see [12]). For such commodities it is possible simply to regress PR on storage levels after adjusting the futures price for
the cost of storage and the cost of money. This adjustment is accomplished either directly by subtracting estimates of the cost
of storage and the cost of money from the futures price prior to any regression analysis or indirectly by means of an appropriate
variable in the regression equation. Even analysts that examined CY for heating oil[13,14], which exhibits a seasonal variability
in consumption similar to natural gas but less pronounced, tended to ignore this variability in their analysis. Not surprisingly, they
found it difficult to explain CY for heating oil using the methodology crafted by earlier analysts for commodities with relatively
constant demand throughout the year. Thus, they used very indirect tests of CY. They examined whether the variability in an
estimate of CY was significantly greater when storage levels were thought to be low. If the variability was significantly greater,
they concluded that storage had a significant influence on CY.

The demand for natural gas is not only highly variable throughout the year, but it is also strongly correlated with temperature
during the wintertime because of the large amount of space-heating demand satisfied by natural gas furnaces.[15] When the
temperature drops in the wintertime, demand for natural gas rises, which may put upward pressure on prices. Yet, the same
temperature drop at different times has a much different significance for the gas industry. A 5° drop from 30° Fahrenheit (F) at
the beginning of January in New York has much less significance than the same occurrence in March, when it is less likely for
temperatures to be that low. Thus, while absolute changes in temperature may be expected to influence the demand for gas,
temperature changes compared to normal temperatures for the time period should have a more significant influence.

The storage part of the gas industry, in fact, organizes itself around normal temperatures and reasonable expectations of deviations
from normal. It p!aces enough gas in storage, particularly in end-use market areas, to meet the expected demand associated with
normal temperatures, as well as variations in demand that occur from daily deviations from normal temperature. Colder than
normal temperatures may have a positive influence on price changes because prices are more likely to increase than decrease
when temperatures fali below normal.

The temperature variable used in this analysis is:

DT,=NT,-T, Q)

78 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Table 3.

Planned Versus Actual Storage Additions, 1993

Percent of Planned

Planned for 1993 In Service by 1993 Projects In Service by 1993
Type Working Working Working
Number Base Gas Deliver- Number | Base Gas Deliver- Base Gas Deliver-
of Gas | Capacity | ability of Gas | Capacity | ability | Gas | Capacity | ability
Projects | (Bc) | (Bcf) (MMeffd) | Projects | (Bcf) | (Bcf) (MMefid) | (Bcf) (Bef) | (MMcfidy
Reservoir
Type
Aquifer 2 15 13 160 0 0 O te) te) te) 0
Depleted 13 41 97 1,663 8 27 7 1,373 65 79 83
Field
Salt 9 17 34 2,950 7 8 20 2,300 49 58 78
Formation
Project
Type
New 13 42 114 3,755 8 23 80 3,109 54 72 83
Expansion 1 3 33 1,018 7 12 16 564 39 49 55
Ownership
Independent 5 18 34 1,005 1 7 20 720 41 58 72
Interstate an] 28 72 1,553 8 25 65 1,373 88 90 88
Pipeline
Intrastate 5 4 21 1,440 4 1 7 1,230 12 31 85
Pipeline
tbc 3 16 17 775 2 2 5 350 9 31 45
Total 24 73 144 4.773 15 35 97 3,673 48 67 77

Bef = Billion cubic feet. MMcffd = Million cubic feet per day. LDC = Local distribution company.
Note: Totals may not equal sum of components because of independent rounding.
Sources: Energy Information Administration (EIA). In Service: ElA-191, "Underground Gas Storage Report.” Planned: Office of Oil and
Gas, "Proposed Natural Gas Storage Projects," data base as of October 31, 1994, based on Federal Energy Regulatory Commission filings and
information from various industry news sources. .

Table 4. Changes to Working Gas Capacity and Daily Deliverability, 1990-1993
In Service* New Removed from Service
y Working Daily Working Daily Working | Daily
ear Number Gas Deliver- | Number Gas Deliver- Number ; Gas | Deliver-
of Capacity | ability of Capacity ability Capacity | ability
Sites (Bef) (MiMcfid) | Sites (Bef) (MMcfid) sites (Bcf) | (MMct/d)
1980 387 3,550 61,718 1 2 450 42
1991 366 3,596 63,506 9 46 1,740 3 7 120
1992 367 3,598 64,056 1 2 500 12 14 81
1993 375 3,695 67,729 8 80 3,109 5 18 244

*Includes expansions to existing capacity/deliverability that occurred during the year. Excludes abandoned, inactive, and standby sites.
Bef = Billion cubic feet. MMcffd = Million cubic feet per day.
Source: Energy Information Administration, Office of Oit and Gas; derived from EIA-191, "Underground Gas Storage Report."

32

Energy Information Administration
‘The Value of Underground Storage in Today's Natural Gas Industry



Summary

The factors influencing the relationship between price and
storage vary throughout the year as the immediacy of the need
for supplies from storage changes between the heating and
nonheating seasons. During the heating season, however, the
relationship between storage and movements in spot prices is

strong. Thus, in the short term, the relationship between
storage levels and expected deliveries during the heating
season is important in explaining changes on the spot market.
Over the longer term, there are other significant factors that
influence the operation of the industry and pricing of storage
services as well. In particular, regulatory changes during the
past decade have resulted in greater use of storage facilities,
suggesting efficiency gains throughout the industry.

xii Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Table B2. Summary of Proposed Storage Projects by Ownership Type

Capacity Additions (billion cubic feet) Additions (MMcfid)
Number of

Type of Owner Projects. Base Gas Working Gas Total Withdrawals Injections
Independent Co. 38 185 327 513 11,095 3,680
Interstate Pipeline Co. 20 83 68 151 4,326 1,825
Intrastate Pipeline Co. 12 37 55 92 3,280 1,290
Local Distribution Co. 1 22 45 67 2,035 1,009

Totat 81 328 495 824 20,746 7,804

MMcffd = Million cubic feet per day.

Note: Two liquefied natural gas storage projects (one new , one expansion) have also been proposed by an interstate pipeline company
affiliate, which would add 4 Bef working gas capacity, 1,000 MMcf/d withdrawal capacity and 15 MMcf/d injection capacity. Totals may not

equal sum of components because of independent rounding.

Source: Energy Information Administration, Office of Oil and Gas, "Proposed Natural Gas Storage Projects,” data base as of October
31, 1994, based on Federal Energy Regulatory Commission filings and information from various news sources.

long-distance pipelines. Several developers also envision
providing value added sales services to prospective buyers.
"Swing services" are a prime example. These involve a gas
supply contract that permits the purchaser to take less than
100 percent of the contracted volumes at variable rates that
match daily and seasonal swings in demands.

A number of producers are also actively developing or
participating in new underground gas storage projects.’”
Producers find storage attractive as a means of levelizing their
daily production flows. Putting gas in storage can be more
economic for producers than putting excess gas on the spot
market, or shutting in the gas. In this sense, storage serves as
an operational risk management tool that is essential if a
producer plans to compete as a firm supplier of gas in the
unbundled market. A producer's interest in storage includes its
use for:

® Aggregating supplies. In this case, storage serves as
the point where a producer's various gas supplies can
be pooled together and repackaged to meet customer
needs.

Improving the reliability of the producer's supplies.
In this case, storage acts as an emergency backup
supply in the event of equipment failures, well
freezeups, or hurricanes.

Offering value-added services to consumers. In this
case, storage is used to provide services to consumers
in addition to the sale of gas.

“For instance, Chevron, which is participating in the Petaf Salt Dome
project; Texaco, which is participating in the Avoca project; and, Amoco,
which is participating in the Stratton Ridge project.

60

In addition, a number of proposed new storage projects are
being developed on behalf of, or are geared toward attracting,
electric utility users. Some examples include: the Hilbig
project in Bastrop, Texas, which will be used for the Lower
Colorado River Authority's gas-fired units; the Nichols
Station Plant project, which is under consideration by
Southwest Public Service as a backup supply source for its
Nichols Plant; the Spindletop project being developed by
Sabine Gas Transmission to serve Gulf States Utilities; and
several California projects that are competing to supply the
Sacramento Municipal Utility District, including the Wild
Goose, the Lodi, and the Putah Sink projects These users in
particular need high-deliverability type storage to service their
varying weekly, daily, and even hourly peaking needs.

New storage is also being marketed by some storage
developers as a potential price arbitrage and futures trading
hedging tool. Many in the industry, however, feel this service
will evolve into only a very small niche market, offering little
in the way of a major income source or opportunity for profit.

Emphasis on Salt Facilities

Conversions of depleted fields are expected to provide 65
percent of proposed additional working gas capacity. In
general, depleted field conversions still offer the most cost-
effective choice for seasonal baseload storage supply, and
about 29 percent of the depleted field projects are expansions
of existing storage fields. Salt cavern facilities (both bedded
and dome) account for an additional 33 percent of proposed
additions to working gas capacity, and aquifers 2 percent. The
salt cavern facilities, however, account for the large majority
of additions to withdrawal capacity (68 percent in total or

Energy Information Administration

The Value of Underground Storage in Today's Natural Gas Industry





rights. For example, several releases of capacity have been for
less than 14 days. (Posted daily rates for these short-term
releases have been $0.0329 per thousand cubic feet or even
lower.) Second, capacity releases can be large. Several
capacity releases have been for several years and have
involved more than a billion cubic feet of capacity. Third,
sellers of capacity may discount the cost of storage capacity.
Holders of unutilized storage capacity have an economic
incentive to sell this unused capacity. As the return from
unused capacity is zero, any rate received represents income
that would not have been received otherwise. Using
information available from pipeline company EBB's,
marketers will increasingly canvass holders of storage
capacity to see if they want to release any unused capacity. If
the capacity release market follows the path of the
transportation capacity release market, sellers of capacity
rights will continue to discount the cost of capacity. As
discounting becomes common, the size of the market should
grow.

Growth of the capacity release market is important for several
reasons. If a large percentage of owners of capacity rights
enter the market when they have more than they need, the
market will provide information on where excess capacity
exists, When the cost of storage service is known in terms of
the additional cost of delivered gas per million Btu, buyers of
storage service will be better equipped to compare the cost of
underground storage service to other means of obtaining
peaking service. In addition, when the cost of storage is
known, buyers will have incentives to practice efficient
behavior in the utilization of storage. When cost information
is available for different regions, buyers will be able to factor
in transportation rates and may be able to use more of the
storage in regions where the storage is relatively cheap and
less in regions where the storage is expensive.

“The posted rate may not include all costs.

40

As storage capacity is used more and more efficiently, the
price charged for storage rights will indicate whether or not
the value of storage is great enough to support additional
investment in storage. Thus, some of the currently planned
storage projects may be canceled because they will be unable
to be price competitive. This result has already been observed
in the transportation market, where various planned pipeline
construction projects have not survived because of the effects
of open access. A similar result can be expected in the area of
storage capacity.

Summary

Trends toward customer ownership of working gas and
greater emphasis on inventory management are expected to
continue under Order 636. New market requirements are
driving the addition of new underground storage facilities and
the performance characteristics of these facilities, such as high
deliverability rates and the ability to withdraw and inject gas
year round with little or no notice. Salt cavern storage has
become a more important source for meeting customers’ peak
demands, even though there is a limited volume of working
gas and the cycling potential has yet to be fully exploited.

The newest trends in underground storage are in market-based
rates and capacity release, the latter being a direct
consequence of Order 636. Experience is limited in both
areas, but both have the potential to make natural gas storage
a more useful and efficient tool for meeting the needs of the
gas consumer.

Energy Information Administration

The Value of Underground Storage in Today's Natural Gas Industry



Table A2. Summary of Existing Underground Natural Gas Storage, by Type of Ownership and Jurisdiction,

1993
Depleted Gas/Oil Aquifer Storage Salt Cavern Storage Total
State Working] Daily Working| Daily Working| Daily Working| Daily
Number] Gas Deliver- |Number} Gas Deliver- {Number] Gas Deliver- |Number} Gas Deliver-
of |Capacity) ability of |Capacity| ability of |Capacity| ability of |Capacity| abitity
Sites | (Bcf) |(MMctiday)| Sites | (Bcf) |(MMct/day)} Sites | (Bcf) |(MMcfiday)) Sites | (Bcf) |(MMcffday)
Nonjurisdictional
Independents 6 51 823 0 ) ° 7 a 1,950 13 72 (2772
93 567 13,924 24 263 4,298 5 19 1,224 428 849 19,448
Intrastate 9 133 2,486 0 ° 0 2 5 1,100 "1 137 3,586
Total 114 750 17,233 24 263 4,298 14 44 4,274 152 1,058 25,805
Under FERC
Jurisdiction
Independents 9 197 1,629 0 0 0 2 6 375 ca) 203 2,004
Interstate 167° 1,971 29,812 13 164 2,484 4 25 1,796 184 2,160 34,091
Loc 26 251 4,707 1 15 525 1 7 597 28 274 (5,828
Total 202 2,420 36,148 14 479 3,009 7 38 2,767 223-2637 44,923
Total
Independents 15 248 2,451 0 0 ) 9 26 2,325 24 278 4,778
Interstate 167 «1,971 29,811 13 164 2,483 4 25 1,795 184 2,160 34,091
Loc 125 818 18,630 25 279 4,823 6 26 1,820 156 4,123 25,274
Intrastate 9 133 2,486 0 ° 0 2 5 4,100 4 137° 3,586
Total 316 3,470 53,380 38 443 7,308 a 82 7,044 375-3695 «67,729

Note: Bef = Billion cubic feet; MMcf = Million cubic feet. Totals may not equal sum of components because of independent rounding.
Source: Energy Information Administration, E[A-191, "Underground Gas Storage Report.”

high-deliverability sites currently being developed have been
initiated by independent storage service operators. If the
independent operators principally serve the interstate market
they are subject to FERC regulations; otherwise, they are
State regulated. Several independent storage operations are
joint ventures that include major interstate pipeline companies
and LDC's as partners, or they are subsidiaries of interstate
pipeline companies operating as independent entities.

Types and Uses of
Underground Storage

Most existing gas storage in the United States is held in
depleted natural gas or oil fields (Figure A2) located close to
consumption centers. Conversion of a field from production
to storage duty takes advantage of existing wells, gathering
systems, and pipeline connections. The geology and
producing characteristics of a depleted field are also well
known. However, choices of storage field location and
performance are limited by the inventory of depleted fields in
any region.

In some areas, most notably the Midwestern United States,
natural aquifers have been converted to gas storage reservoirs.

An aquifer is suitable for gas storage if the water-bearing
sedimentary rock formation is overlaid with an impermeable
cap rock. While the geology of aquifers is similar to depleted
production fields, their use in gas storage usually requires
more base (cushion) gas and greater monitoring of withdrawal
and injection performance. Deliverability rates may be
enhanced by the presence of an active water drive.

Salt caverns, the third main type of storage, provide very high
withdrawal and injection rates compared with their working
gas capacity. Base gas requirements are relatively low. The
large majority of salt cavern storage facilities have been
developed in salt dome formations located in the Gulf Coast
States. Salt caverns leached from bedded salt formations in
Northeastern, Midwestern, and Western States are also being
developed to take advantage of the high volume and flexible
operations possible with a cavern facility (see Appendix B).
Cavern construction is more costly than depleted field
conversions when measured on the basis of dollars per
thousand cubic feet of working gas, but the ability to perform
several withdrawal and injection cycles each year reduces the
per-unit cost of each thousand cubic feet of gas injected and
withdrawn.

Storage facilities may be classified as seasonal supply
reservoirs (depleted gas/oil fields and aquifers for the most

46 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Figure A4. Typical Configuration of Salt Dome Storage

ei &

Compressed natural gas storage:

1 Cavern for compressed
natural gas

Wellhead

Coalescer fiter/separator

Line heater

Dehydration

Pressure reduction station

Consumer

Long distance pipeline

Iniet scrubber

Gas compressor units,

Cooler

Gas flow meter

Satt rock

Overburden

Ground

OB>HIZoorvH MAN

Source: PB-KBB Inc., "Underground Storage and Subsurface Systems’

Management, and Information Services.

There are two basic types of salt formations used to store
natural gas: domes and beds. Salt domes are very thick salt
formations. A salt dome formation might be a mile in
diameter, 30,000 feet in height, and begin about 1,500 feet
below the surface. The depth of the caverns that are hollowed
out within the formation is critical for reasons of pressure and
structural integrity. The pressure at which the gas can be
stored is a function of the depth of the cavern. However, at
extreme depths, as temperature and pressure increases, salt
behaves as a plastic and will creep or flow, which can become
a major consideration in cavern construction possibly leading
to cavern closure. Thus, salt storage is generally limited to
depths shallower than 6,000 feet.

": Recreated by Energy Information Administration, Office of Planning,

A salt bed storage site, on the other hand, is generally
developed from a much thinner salt formation (1,000 feet or
less) located at shallower depths. As a result, the height-to-
width ratio of the leached cavern is much less than with dome
reservoirs, which are relatively high and narrow. Salt bed
storage formations also contain much higher amounts of
insoluble particles (shale and anhydrite rock) than salt dome
formations. These materials remain in the reservoir after the
leaching process and affect the flow velocity and capacity of
the reservoir itself. In addition, because the height/width
aspect is thin, the flatter reservoir ceiling is subject to greater
stress and potential wall deterioration. As a result of these as
well as other factors, salt bed storage development and
operation can be more expensive than that of salt dome
storage.

50 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



In general, if an applicant's market analysis is: (1) based on a
geographic and product-alternative definition of the market
acceptable to FERC, and (2) produces low market share and
HHI, the applicant's chances for approval are excellent. On
the other hand, relatively large market share and/or high HHI
is/are not necessarily "fatal" to the application. FERC has
pointed out that it would consider a number of other
competitive factors in determining whether or not an
applicant could have market power, such as excess capacity
in the market, ease of entry by other competitors and/or
impending entry by other competitors, and the presence of
large and sophisticated buyers in the market. For example,
sophisticated buyers are capable of purchasing storage service
from that market where the price or quality of service is most
competitive.

Market Power: Some Guiding
Principles from FERC

Several important points have emerged from the cases that
FERC has considered to date. For example, in the case where
FERC denied market-based rates for Cove Point LNG (CPL),
the company's business affiliations were a key factor both in
evaluating market share and HHI, as well as in assessing the
potential for deals with customers that might be negotiated at
less than “arm's length." CPL had proposed to provide "winter
peaking" services in 3-, 5-, and [0-day arrangements at
negotiated, market-based rates. CPL is a limited partnership
whose general partners are affiliated with Columbia Gas
System, Inc., and the Potomac Electric Power Co. (PEPCO).
At the same time, PEPCO is also identified as a potential
customer of CPL.

One concern expressed by FERC was the potential for a
customer of CPL, which also happens to be a regulated
affiliate, to pay “negotiated” but higher-than-competitive rates
for storage service, then pass along these higher rates to their
captive customers downstream. Further, in reviewing the
market analysis offered by CPL, FERC established the
principle that it will treat affiliated companies selling the same
or substitute products as being a single seller. Thus, all of the
underground storage facilities and LPG facilities of the
Columbia Gas System that would be suitable for similar
peaking services as proposed by CPL were added to CPL's
capacities for purposes of the market share and HHI
computations.

Outlook for Market-Based Rates

It is easier for relatively small, individual facilities with few
or no affiliations to justify market-based rates, especially
those serving market areas that already have plenty of good

storage alternatives available. Demonstration of lack of
market power may be even easier for new entrants, because
they essentially start with no market share and therefore must
offer customers a better deal than what is currently available
in the market. To date, most of the applications have come
from independent companies with facilities in producing
areas. These areas, in addition to having numerous natural gas
producers, have more pipelines and storage operators than do
consuming areas. Thus, it is possible that market entry for a
new storage operator is easier in producing areas because
access to more pipelines provides access to more potential
customers, and because it is less likely that one or a few
storage providers dominate the market.

Market-based rates from existing storage providers in market
or consuming areas will probably be harder to justify, because
in many instances much or most of the existing storage
capacity is owned or controlled by only a few storage
operators, oftentimes the few major pipeline suppliers for
these areas. Market-based rates for storage services from new
entrants in consuming areas are certainly feasible; in fact two
have been approved to date. In addition, there are a number
of planned projects in consuming areas that could qualify. As
these projects proceed, it is expected that some will generate
additional applications for market-based rates.

As already stated, FERC has yet to approve market-based
rates on a company-wide basis. However, to date only two
companies have requested such broad authority: Michigan
Consolidated Gas (MichCon) and ANR Pipeline Company.>”
Neither presented any market power analysis. MichCon relied
on the Michigan Public Service Commission's earlier
approval of market-based rates for its intrastate storage
services. ANR included its request for market-based rates in
arecent rate filing.

To gain company-wide market-based rates for storage, large
pipeline companies will have to argue convincingly that
industry restructuring and "interconnectedness" have
effectively broadened the market for storage beyond some
narrow geographic area where that company predominates,
and that prospective storage customers in actuality have many
good alternatives. Alternatively, or perhaps in conjunction
with this argument, the company could argue that the
secondary or capacity release market is a guarantee against
the accumulation or exercise of market power.

“ANR Pipeline is an interstate pipeline company subject to the
jurisdiction of FERC. It owns and operates 14 underground storage facilities,
all of which are in Michigan. Its storage fields have a total working gas
capacity of approximately 189 Bef, and daily deliverability of more than 3.4
Bef per day. Altogether, 11 companies operate storage fields in Michigan,
with aggregate working gas capacity of about 617 Bef and deliverability of
about 11.2 Bef per day. (ANR Pipeline and ANR Storage are different and
‘unrelated companies.)

38 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Figure 7. During the Heating Seasons in the 1990's, Storage Withdrawals and Imports Have Generally
Increased as a Percent of Consumption While Production Has Declined

100 Il Dry Gas Production

(J Withdrawals from Storage
4 Imports

ce 804

3

a

€

a

s 60 4

°

g

er

= 404

ro}

=

oy

2

a 20-4

0 Es

T T T T
1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994
Heating Season

Source: Energy Information Administration, Office of Oil and Gas; based on Natural Gas Monthly, historical data series.

10 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Figure 18. Utilization of Storage Facilities Has Increased During the Heating Seasons

Withdrawals Unadjusted for Weather

~ 8004
ro
°
wo
2 6004
a
3
°
§ 4004
a
200-4
0 her 1-1 11+ 1-1
nooUFM NDJFM NOYFM NOVEM NDOJFM NOVEM NOUFM WNOUFM NDF M
1985-86 1986-87 1987-88 1988-89 1989-90 «1990-91 «1991-82 1882-93 1993-94
Heating Season
4005 Withdrawals Adjusted for Weather
3
2 3004 JN
g
2
3
So 200-4 \4 \/
c
= 1004
oO T TI TI 7
nOJFM WOSFM NDJFM NOJEM NOJEM NOSFM NOJFM NOUJFM NDJFM
1985-86 1986-87 1987-88 1988-89 1989-90 1990-91 1991-82 1992-93 1993-94
Heating Season
120. Weather-Adjusted Change from 1985-86 Heating Season
_ 100-4
°
2 804
2
a 60-4
$
°c 404
<
204
o4
(204
(40)

1986-87 1987-88 1988-89 1989-90 1990-91 1991-92 1992-93 1993-34
Heating Season

Note: Because vertical scales differ, graphs should not be directly compared. Monthly withdrawals have been adjusted for weather by
‘subtracting the estimated influence of heating degree days from withdrawals. The estimated influence is obtained by regressing withdrawals
on heating degree days.

Sources: 1985-86 through 1990-91: Energy Information Administration, EIA-191/FERC-8, "Underground Gas Storage Report." 1991-92
through 1993-84: Energy Information Administration, EIA-191, "Underground Gas Storage Report." Heating Degree Days: National
Oceanic and Atmospheric Administration, National Climatic Data Center.

28 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Table B1.

Summary of Proposed Storage Projects by Reservoir Type and Projected Year in Service

Depleted Gas/Oil Aquifer Storage Salt Cavern Storage Total
Year Working; Daily Working] Daily Working} Daily Working] Daily
Number} Gas | Deliver-|Number| Gas | Deliver-|Number} Gas | Deliver-| Number} Gas | Deliver-
of Capacity) ability of Capacity} ability of Capacity} ability of Capacity] ability
Projects| (Bcf) | (MMCcf) | Projects} (Bcf) | (MMctf) | Projects| (Bcf) | (MMcf) | Projects} (Bcf) | (MMch
Existing 1993316 3,170 53,380 38 443 (7,306 21 82 7,041 375 = 3,695 = 67,729
1994
New 10 144 2,600 1 3 35 6 23 1,630 17 172 4,265
Expansion 5 17 383 1 4 75 5 1 990 11 33 1,448
Total 15 164 2,983 2 8 110 1 34 2,620 28 205 5,713
1995
New 8 114 2,312 0 0 0 11 45 4,575 19 159 6,887
Expansion 1 5 50 0 0 0 6 16 1,040 7 21 1,090
Totat 9 119 2,362 0 t) 0 17 61 5,615 26 180 7,977
1996
New 3 13 940 0 0 te) 4 12 970 7 25 1,910
Expansion 4 6 60 1 1 0 3 8 800 5 15 860
Total 4 19 4,000 1 1 0 7 20 1,770 12 40 2,770
1997
Expansion 0 0 O 0 i) 0 6 22 2,000 6 22 2,000
Total 0 0 o 0 te) 0 6 22 2,000 6 22 2,000
1998
New 0 0 oO ti) 0 0 1 9 1,000 1 9 1,000
Expansion 0 0 oO i) i) 0 5 16 1,100 5 16 4,110
Total 0 0 0O 0 0 to) 6 25 2,110 6 25 2,110
1999
New 3 21 176 t) 0 0 tt) oO 0 3 at 176
Total 3 21 176 0 0 0 tt) 0 0 3 21 176
Total 1994-99
New 24 293 6,028 1 3 35 22 89 8,175 47 387 14,238
Expansion 7 28 493 2 5 75 25 74 5,840 34 108 6,508
Total 31 322 6,521 3 9 110 47 164 14,115 81 495 = 20,746

Bcf = Billion cubic feet. MMcf = Million cubic feet.
Note: Two liquefied natural gas storage projects (one new , one expansion) have also been proposed for 1995 and 1998, respectively,
which would add 4 Bef working gas capacity and 1,000 MMcf daily deliverability. Totals may not equal sum of components because of
independent rounding.
Source: Energy information Administration, Office of Oil and Gas, "Proposed Natural Gas Storage Projects," data base as of October
31, 1994, based on Federal Energy Regulatory Commission filings and information from various news sources.

The Value of Underground Storage in Today's Natural Gas Industry

Energy Information Administration

59



Preface

The Value of Underground Storage in Today's Natural Gas
Industry has been prepared by the Energy Information
Administration (EIA) to provide the latest information on
storage activities. The contribution of storage to the overall
efficiency of the production and transmission segments of the
industry is well known. However, traditional ideas about
storage management have changed and new uses for storage
have developed, as the result of both market pressures and
regulatory changes. This report analyzes these important
changes in the industry.

The report consists of three chapters and four appendices.
Chapter | provides basic information on the role of storage in
today's marketplace where natural gas is treated as a
commodity. Chapter 2 provides statistical analyses of the
relationship between storage and spot prices on both a
monthly and daily basis. For the daily analysis, temperature
data were used as a proxy for storage withdrawals, providing
a new means of examining the short-term relationship
between storage and spot prices. Chapter 3 analyzes recent
trends in storage management and use, as well as plans for
additions to storage capacity. It also reviews the status of the
new uses of storage resulting from Order 636, that is, market-
based rates and capacity release.

Appendix A serves as a stand-alone primer on storage
operations, and Appendix B provides further data on plans for
the expansion of storage capacity. Appendix C explains recent
revisions made to working gas and base gas capacity on the
part of several storage operators in 1991 through 1993. The
revisions were significant, and this appendix provides a
consistent historical data series that reflects these changes.
Finally, Appendix D presents more information on the
regression analysis presented in Chapter 2.

Data and sources used in the report include: national-level
storage data from EIA's Natural Gas Monthly, field-level
storage data from Form EJA-191, "Underground Gas Storage
Report"; capacities of proposed storage projects from the
Office of Oil and Gas' "Proposed Natural Gas Storage
Projects" data base; information on market-based rates and
capacity release from filings at the Federal Energy Regulatory
Commission; Henry Hub spot prices from Pasha Publications
Inc., Gas Daily, and McGraw Hill, Inside F.E.R.C's Gas
Market Report, estimated weekly storage data from the
American Gas Association's American Gas Storage Survey;
and temperature data from the National Oceanic and
Atmospheric Administration, National Climatic Data Center.
Unless otherwise stated, historical data through 1992 on

natural gas production, consumption, and price come from
EIA, Natural Gas Annual 1992, Vols. 1 and 2, DOE/EIA-
0131(92)/1 and 2 (Washington, DC, November 1993). Similar
annual data for 1993 and monthly data for 1993 and 1994
come from various issues of EIA's Natural Gas Monthly
(NGM), DOE/EIA-0130 (Washington, DC). Data from the
NGM are preliminary estimates.

The Value of Underground Storage in Today's Natural Gas
Industry was prepared by the Energy Information
Administration, Office of Oil and Gas, under the direction of
Diane W. Lique (202/586-6401). General Information
concerning this report may be obtained from Joan E. Heinkel
(202/586-4680), Chief of the Natural Gas Analysis Branch.
Detailed questions may be addressed to the following
analysts:

© Chapter 1. "Importance of Storage in the Gas
Industry," John H. Herbert (202/586-4360).

© Chapter 2. "Relationship Between Natural Gas Prices
and Storage Activity," Mary E. Carlson (202/586-
4749) and John H. Herbert (202/586-4360).

e@ Chapter 3. "Changes in Storage Operations," Philip
Shambaugh (202/586-4833), James M. Thompson
(202/586-6201) and James Tobin (202/586-4835).

e@ Appendix A, “Underground Natural Gas Storage
Operations," James Tobin (202/586-4835).

© Appendix B, "Proposed Additions to Underground
Natural Gas Storage," James M. Thompson
(202/586-6201).

@ Appendix C, "Revisions to Working Gas Storage
Data," Philip Shambaugh (202/586-4833).

e@ Appendix D, "Regression Analysis Results,” John H.
Herbert (202/586-4360).

Overall coordination of the report was provided by John H.
Herbert. Significant analytical contributions were made to
Chapters 1 and 3 by Lillian (Willie) Young.

Editorial support was provided by Doris Wells, Ann C.
Whitfield, and Willie Young. Desktop publishing support was
provided by Margareta Bennett.

Energy Information Administration iti
The Value of Underground Storage in Today's Natural Gas Industry



Table B3. Proposed Underground Storage by State, 1994-1999

Expansion FERC
Year in Project? Docket Reservoir
Project Name/State Operator County Service (X=Yes) Number Type
ALABAMA
SOUTH BAY GASSTG-MOBILE WASHINGTON 1994 SALT DOME
ALABAMA-MCINTOSH.
ARIZONA
PATAYA PHASE 1 GOLDEN STORAGE MOHAVE 1998 SALT BED
SERVICES
PATAYA PHASE 2 GOLDEN STORAGE MOHAVE 1998 x SALT BED
SERVICES
TRANAM PHASE 4 ‘TRAN AM ENERGY MOHAVE 1995 SALT BED
‘TRANAM PHASE 2 ‘TRAN AM ENERGY MOHAVE 1998 ‘SALT BED
CALIFORNIA
tool NORTHERN CA. GAS SAN JOAQUIN 1995 DEPL FIELD
STORAGE
PUTAH SINK NAHAMA & WEAGANT SACRAMENTO 1995 DEPL FIELD
TEN SECTION MCFARLAND ENERGY KERN 1995 DEPL FIELD
WILD GOOSE WILD GOOSE GAS BUTTE 1995 DEPL FIELD
STORAGE
COLORADO
DOUGLAS CREEK WILLIAMS STORAGE RIO BLANCO 1994 DEPL FIELO
YOUNG c1G MORGAN 1994 DEPL FIELD
ILLINOIS
HILLSBORO EXPANSION ILLINOIS POWER MONTGOMERY 1994 x AQUIFER
JOHNSON CITY CENTRAL ILLINOIS WILLIAMSON 1996 DEPL FIELD
PUBLIC
INDIANA
CARBON-CALCUTTA MIDWEST GAS STORAGE CLAY 1994 CP90-454 AQUIFER
KANSAS
MID-CONTINENT PHASE 1 HNG STORAGE KIOWA 1995 SALT BED
MID-CONTINENT PHASE 2 HNG STORAGE, KIOWA 1996 x SALT BED
MID-CONTINENT PHASE 3 HNG STORAGE, KIOWA 1997 x SALT BED
MID-CONTINENT PHASE 4 HNG STORAGE KIOWA 1998 x SALT BED
MULLINVILLE ENRON STORAGE KIOWA 1995 SALT BED
RICHFIELD WEST FIELD CENTENNIAL STORAGE, | MORTON 1994 CP92-285 - DEPLFIELD
EVO
RICHFIELD WEST FIELD CENTENNIAL STORAGE, © MORTON 1994 x EPL FIELD
NUEVO
KENTUCKY
ELK CREEK HAR-KEN SPENCER 1999 DEPL FIELD
SOUTH ST. CHARLES HAR-KEN HOPKINS 1999 DEPL FIELD
ST. CHARLES HAR-KEN HOPKINS 1999 DEPL FIELD
LOUISIANA
CHANDELEUR ENTRE ENERGY OFFSHORE 1994 CPs4-388 © DEPL FIELD
COTTON PLANT SWIFT/NG CLEARING CALDWELL 1994 DEPL FIELD
HOUSE
62 Energy Information Administration

The Value of Underground Storage in Today's Natural Gas Industry



approximately 2.1 times their contribution to working gas
capacity).

The large number of proposed salt cavern projects represents
an interesting departure from the historical trend of storage
development in depleted fields. Salt cavern facilities are
essentially large underground caverns that act as pressure
vessels (see Appendix A). As a result, these facilities have
very high withdrawal rates relative to their working gas
capacities. Most salt cavern facilities are designed to deliver
their total working gas capacity in a period of 10 to 15 days
and have sufficient injection capacity to replace this working
gas in 20 to 30 days. The high-deliverability, low-volume
capacity associated with these facilities, and their ability to
inject and withdraw gas on a continuing basis throughout the
year, make salt cavern facilities particularly attractive for
providing a number of upstream storage services now in high
demand in the unbundled market environment (ie., balancing,
emergency backup). In contrast, storage in depleted fields and
aquifers is not easily configured to provide these services as
the withdrawal and injection rates for storage in these fields
are restricted by the much lower permeability of the storage
formation.

Several developers are also marketing salt dome and salt bed
facilities as 2 peaking supply source. The high-deliverability
rates possible from these facilities make them attractive for
peaking uses, However, peaking facilities generally need to be
located in close proximity to the customer purchasing the
service in order to assure prompt delivery of the gas. Salt
domes in the producing regions, therefore, generally cannot
offer peaking service to customers in other regions of the
United States. However, several proposed projects using salt
bed deposits are located in, or relatively near, major market

areas in the Northeast and Western United States, making
them attractive for development and use as peaking supply.

Proposed salt cavern facilities also differ from existing
storage with respect to the planned operation of the facilities.
Most proposed salt caverns are designed with the intent of
cycling the entire working gas capacity several times each
year. This requires the installation of substantial compressor
capacity for re-injecting gas in a short period.

Locations of New Storage

Most of the increased storage capacity is slated for
development in Texas. With 15 projects, Texas storage
deliverability could increase by 44 percent by 1998 while
working gas capacity could expand by 22 percent, adding
over 4 billion cubic feet per day to deliverability and 80
billion cubic feet of working gas capacity overall. But on a
percentage basis, Louisiana's planned growth is even more
remarkable, with a 38-percent increase in working gas
capacity and more than double the current daily deliverability.
New York and California will also see significant growth in
their underground storage services. All of these States are
homes of major market hubs and, with the exception of
California, have geologic salt formations which will be used
for much of the planned storage. California, however, does
possess the geology to permit development of
high-deliverability storage in nonsalt reservoirs—for example,
the Wild Goose project in Butte County.

Each project, by location, is detailed in Table B3.

Energy Information Administration 61
The Value of Underground Storage in Today's Natural Gas Industry



Table B3. Proposed Underground Storage by State, 1994-1999 (Continued)

Expansion FERC
Year in Project? Docket Reservoir
Project Name/State Operator County Service (X=Yes) Number Type
JEFFERSON ISLAND EQUITABLE RESOURCES —_ IBERIA AND 1995 SALT DOME
VERM
JENNINGS SALT DOME EGAN GAS STORAGECO —ACADIA 1995 cP94-217 SALT DOME
LA4 PHASE 3, 4 ‘TEJAS POWER CORP ACADIA 1996 x SALT DOME
LAs PHASE 5,6 ‘TEJAS POWER CORP ACADIA 1997 x SALT DOME
LA-i/EGAN PHASE 1, 2 ‘TEJAS POWER CORP ACADIA 1995 SALT DOME
NAPOLEONVILLE PHASE 1 ENRON STORAGE ASSUMPTION 1994 ‘SALT DOME
NAPOLEONVILLE PHASE 2 ENRON STORAGE ASSUMPTION 1998 x SALT DOME
OUACHITA RIVER MATRIX PARTNERS, UNION 1995 CP94038 = DEPLFIELO
SULPHUR MINES HNG STORAGE CALCASIEU 1995 CP93.716 = SALTDOME
MICHIGAN
GRANDS LACS TEJAS POWERICMS GAS = STCLAIR 1995 SALT BED
KALKASKA 30 CMS ENERGY KALKASKA 1994 DEPL FIELD
LEES PANHANDLE CALHOUN 1995 DEPL FIELD
STORAGEMG
VENTURES
LIVINGSTON EXPANSION GRI, PANHANDLE, LIVINGSTON 1994 x DEPL FIELD
EASTERN
WASHINGTON TOWNSHIP MCN INVESTMENT MACOMB 1996 EPL FIELD
MINNESOTA
WATERVILLE-WASECA MINNEGASCO LE SUEUR 1996 x AQUIFER
MISSISSIPPI
EMINENCE EXP PHASE 2 ‘TRANSCO COVINGTON 1994 x CP90-2230 SALT DOME
EMINENCE EXP PHASE 2 ‘TRANSCO COVINGTON 1995 x CP90-2230 SALT DOME
HATTIESBURG PHASE 2 HATTIESBURG GAS FORREST 1995 x CPs3-69 ‘SALT DOME
STORAGE
MS-1 PHASE 1,2 TEJAS POWER CORP COPIAH 1995 CP92-586  SALTOOME
MS-1 PHASE 3, 4 ‘TEJAS POWER CORP COPIAH 1996 x cpe2-586 SALT DOME
MS-1 PHASE 5 TEJAS POWER CORP COPIAH 1997 x CP92.588 SALT DOME
PETAL PETAL GAS/CHEVRON FORREST 1994 CP93-69 SALT DOME
MONTANA
BAKER EXPANSION WILLISTON BASIN FALLON 1994 x CP93.285 EPL FIELD
NEW YORK
AVOCA PHASE 1 J.MAKOWSKI& ASSOC. STEUBEN 1996 SALT BED
AVOCA PHASE 2 J. MAKOWSKI & ASSOC. STEUBEN 1997 x cP94-161 SALT BED
AVOCA PHASE 3 J.MAKOWSKI & ASSOC. — STEUBEN 1998 x CP94-161 SALT BED
CAYUTA PHASE 1 BOWDOIN STORAGE SCHUYLER 1996 SALT BED
CAYUTA PHASE 2 BOWDOIN STORAGE SCHUYLER 1997 x SALT BED
CAYUTA PHASE 3 BOWDOIN STORAGE SCHUYLER 1998 x SALT BED
LAUREL FIELDS-ALLEGANY NATIONAL FUEL GAS CATTARAUGUS 1998 x CP90-2088 — DEPLFIELD
SENECA LAKE NGE ENTERPRISES SENECA 1996 SALT DOME
THOMAS CORNERS ARLINGTON STORAGE STEUBEN 1995 x CP95-119  DEPL FIELD
WATKINS GLEN ANR STORAGE, NGE ‘SCHUYLER 1995 SALT DOME
ENTERPRISES
64 Energy information Administration

The Value of Underground Storage in Today's Natural Gas Industry



Figure 15. Henry Hub and Iroquois Have Largest Increase in Spot Prices, January 13-24, 1994

3.50 5
= High
a l II
ao
< 300. Low
a
= 4
a
a 2.50 4 I Il
°
& x re moe [rz
8 “= II
@ 2.00 4 = cs I]
g I
8
oa
g
& 1.504
0 TTTTit4rys TTTTTrTy TUETITTrye TTTETEer
131414819202124 13141819202124 13141819202124 13141819202124
Henry Hub Iroquois (Canadian) © TETCO (Katy) PEPL (Oklahoma)
3.60 5
S
ao
2 3.00 4
s
2 IT
& 2504 2o5
2
s
3
S 2.00
Q * 7 =x
o I. = I
2 I tt slo =x
a = Behe be bs ha bs he
2 150
no
0 TrTityirye TITitirirye TTrTTTgTy. TITtiTrre
13141819202124 13141819202124 13141819202124 131418192021 24

Columbia (Appalachia) E1Paso (San Juan) El Paso (Permian) Northwest (Rockies)

TETCO = Texas Eastern Transmission Corporation. PEPL = Panhandle Eastern Pipeline Company.
Note: Data are not available for weekends and holidays.
Source: Pasha Publications Inc., Gas Daily.

Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry

2



Value of Underground Storage

The gas industry is willing to invest in storage because it
provides considerable value in terms of increased efficiency,
increased reliability of service, and consequently market
growth. As previously stated, underground storage has helped
the gas industry reduce the variability in the amount of natural
gas produced monthly. Without storage the natural gas
industry would require more production wells to satisfy
demand. This savings in production wells is viewed as an
efficiency gain traceable to the availability of storage
reservoirs. Without storage the gas industry would also need
to bring less cost-effective wells on line during the winter to
satisfy the increase in winter demand. This increase in the
operation of less efficient wells would increase the cost of
delivered gas. Accordingly, the existence of adequate storage
provides value to producers and to consumers through lower
prices for gas,

The availability of storage also allows more efficient
operation of the pipeline system. Without storage, pipelines
would have little or no spare capacity during the winter, yet
would be underutilized during the spring and summer when
space-heating demands by households and businesses decline.
Additional capacity would be required to satisfy winter
demand, which would increase the fixed costs that are
allocated to the per-unit price of gas. If these fixed costs were
spread proportionately to the amount of sales, it would
significantly increase the cost of gas in the winter. If the costs
were spread evenly over sales throughout the year, it would
raise the cost of gas significantly in the summer. One reason
why the industry has invested in storage is that it helps reduce
the amount of capital allocated to the building of pipeline
systems. Part of the efficiency gains or value of storage can be
expressed as the difference in the capital cost of the gas
system with and without storage per unit of delivered gas.

The availability of storage also helps pipeline companies
control gas pressure in the pipeline system and optimize
pipeline performance in terms of flowing the required
amounts of gas to customers when needed. Thus, the delivery
capability of the pipeline system is improved because of
storage,

When average monthly variability in consumption of a
commodity is much greater than average monthly variability
in production, it suggests that storage plays a significant role

“Such calculations are actually made by companies when they are
evaluating whether to add storage or pipeline facilities to their system to
satisfy increased demand,

in the market.” In these instances, monthly shifts in
consumption are not only managed by varying monthly
amounts of production but also by varying the amount of the
commodity placed into and taken out of inventory (or in the
case of natural gas, underground storage). The fact that
monthly gas production varies much less than monthly gas
consumption underlines the importance of storage in the
natural gas industry (Figure 4). During the period from 1983
through 1993, the variability in production was less than
25 percent of the variability in consumption.® The variability
in production declined significantly during the period from
1989 through 1993 relative to the earlier period from 1983
through 1988,” suggesting that the role of storage within the
gas industry has grown (Figure 4). Some of the decline in
consumption variability is explained by consumers continuing,
to use more efficient end-use equipment to cut peak demands
during the winter. Another contributory factor was industrial
demand for gas, which has increased dramatically during the
summer since the late 1980's, predominantly because of the
increased number of independent power producers and
electricity cogenerators that burn natural gas.'° Furthermore,
natural gas demand for direct use in air-conditioners and other
summer gas services continued to grow." This increase in
demand during the summer also tends to stabilize both
production levels and the flow of gas along pipeline systems
by providing markets for gas during off-peak periods when
demand is generally much lower. Thus, some of the decline
in the variability of production can be explained by a
reduction in the variability of consumption.

Nonetheless, much of the decline in the seasonality of
domestic production in the late 1980's and early 1990's is due
to the combined influence of increased imports of gas from

*For additional discussion and references on both the rote of inventories
in reducing the variability in production and in satisfying the variability in
consumption and the relationship between variability in production and
variability in consumption or sales, see Ray C. Fair, “The Production-
Smoothing Model is Alive and Well," Journal of Monetary Economics, 24
(1989), pp. 353-370.

“For an examination of similar ratios for heating oi! and other
commodities, see Robert S. Pindyck, "Inventories and the Short-run
Dynamics of Commodity Prices," RAND Journal of Economics, 25 (Spring,
1994), pp. 141-159.

°When the equality of the variances of monthly production for both sets
of years was tested using an F-test, the hypothesis was rejected at the 5-
percent significance level,

"For the summer month of July between 1988 and 1994, deliveries to
industrial, commercial, and residential customers grew from 418 to 618
billion cubic feet (Bef), 109 to 140 Bef, and 123 to 129 Bef, respectively.

‘Natural gas use at electric utilities grew by 74 billion cubic feet (Bef)
for the key air-conditioning load months of July and August in 1993. This
is a large increase from the year-earlier level and ftom the average for the 10
years between 1983 and 1992. Much of this increase (58 Bcf) occurred in
Texas, thus helping to smooth production in that year. However, the change
in production during the previous 5 years did not exhibit any trend and
ranged between -42 and 39 Bcf. Thus, natural gas use at electric utilities has
not made a systematic contribution to the smoothing of production that has
occurred in the past several years.

Energy Information Administration 7
The Value of Underground Storage in Today's Natural Gas Industry



For example, deliverability from storage sites can be expected
to decline during this period, in part because of decreased
pressure in storage reservoirs. Thus, it is more likely that
buyers will have to supplement storage supplies by making
purchases on short-term spot (cash) markets in major
producing regions. This increases the chance that prices will
rise.

The strength of the interaction between storage and price can
be estimated by analyzing data that represent storage
requirements and spot prices during the latter part of the
heating seasons from 1991 through 1994. Storage
requirements are represented using the ratio of total gas in
storage at the end of January, February, and March, to
expected deliveries for the next month. (Expected deliveries
are estimated by actual consumption for the month from the
previous year.) This ratio indicates the availability of storage
gas to meet consumption for the upcoming month, and would
be expected to influence the spot price of gas for the next
month. Thus, the price series analyzed consists of beginning-
of-month spot prices for February, March, and April. The spot
prices used are those for the Henry Hub. This price series is
used widely by the industry as a benchmark and as the price
index in longer term indexed contracts.'*

A greater availability of gas would be expected to put
downward pressure on prices, and indeed there is a strong and
inverse relationship between the two series (Figure 9) with 59
percent of the variability in price associated with the
variability in the storage ratio. Each unit increase in the ratio,
that is an additional month's worth of available supply, on
average, is associated with a $1.09 per MMBtu decline in
price.

The Premium Value of Stored
Gas in the Short Term

For some commodities with active futures markets, the
futures price is sometimes less than a spot price for current
delivery, indicating the value of having gas available for

“The ratio representing storage requirements consists of total storage at
the end of the month (January, February, and March) divided by total
consumption expected for the next month (February, March, and April).
Expected consumption for a month is actuat total consumption for that
month in the previous year. The industry frequently uses this as an estimate
of expected consumption. Expected consumption based on normal heating
degree days could have been used, but this would have captured only space-
heating needs, It would have missed industrial sales that have increased
significantly in the past several years largely because of greater gas use by
cogenerators, The price data are the average price at the Henry Hub
negotiated prior to delivery for each month, based on the beginning-of-the-
month price series from Inside F.E.R.C.'s Gas Market Report.

immediate delivery rather than at a future time.'> Storage
provides one option for immediate delivery. Under most
circumstances, the difference between the spot and futures
prices, called the premium,’ is relatively small for natural gas
because the industry can anticipate changes in consumption
and ensure adequate pipeline supplies. However, under
extreme weather conditions when pipeline capacity is fully
used, the premium can be substantial. Thus, the value
associated with having access to gas in storage is also
substantial on those days. The weather patterns of January and
February 1994 provide a good example of such extreme
conditions (see box, p. 16).

To obtain some indication of the high value of having gas on
hand in storage, the difference between the daily spot price at
the Henry Hub and the futures price for the expiring contract
for January and February 1994 is examined (Figure 10)."” The
Henry Hub price is used because substantial volumes of gas
move through this hub and it is also the delivery point for the
futures contract. The analysis shows that even during this
period of bitterly cold temperatures, the magnitude of the
difference is often small,'* and large differences do not
persist.

Until January 13, 1994, there was little difference in the two
price series. However, on the 13th, when it became clear that
acold front was heading for the major gas consuming regions,
spot prices rose. On January 18, the Monday following the
weekend the cold front hit, prices on the spot market soared
and the difference in the two series was nearly $0.80 per
MMBtu. Thus, the value of having gas readily available in
storage reservoirs increased greatly in a single day.

'SFor a detailed discussion of the relationship between futures and spot
prices, several articles are recommended: Robert S. Pindyck, “Inventories
and the short-run dynamics of commodity prices," RAND Journal of
Economics, Vol. 25 (Spring 1994), pp. 141-159. Czarnikow Energy,
"Backwardation and Contangos in Gas Oil Futures Prices,” Petroleum
Futures Report (July 1991). Lester G. Telser, "Futures Trading and the
Storage of Cotton and Wheat," Journal of Political Economy, Vol. LXVI,
3 (June 1958), pp. 105-128. There are very specific terms for the relationship
between futures and spot prices. If the spot price exceeds the futures price,
this is known as backwardation. If the spot price is less than the futures
price, this is known as contango.

“The premium, defined here as the spot price minus the futures price, is
an approximation of a measure known as the “convenience yield." The
convenience yield is defined as the difference between the spot and futures
price after the futures price has been adjusted by subtracting out the cost of
storage and the cost of borrowing money. Thus, when the premium is zero,
the convenience yield is equal to the cost of money and storage, Sce
Appendix D for further discussion of these concepts.

“The expiring futures contract is frequently referred to as the nearby
month contract. It is the contract that is next to expire on the futures market.
On the last day of trading for the expiring contract, the daily spot and futures
prices should, and for the two series considered here do, differ largely by the
difference in the cost of transacting business in the two markets.

"Those days on which the premium is small are examples of conditions
under which the convenience yield is approximately equal to the cost of
storage and borrowing money. See Appendix D for further discussion.

Energy Information Administration 13
The Value of Underground Storage in Today's Natural Gas Industry



Figure 5. Recently, Seasonality in Production Appears to Have Declined as Withdrawals and Imports Have
Increased

2,000 —

1,500 4

1,000 4

500 +

te)

ones Dry Gas Production
--- Storage Withdrawals
— Imports

T T T T T T T T T T T T
1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994

Source: Energy Information Administration, Natural Gas Monthly, historical data series.

Figure 6. By 1993, Average Variability in Production Was About Half of Its 1986 Value

350 5

300 4

in Cubic Feet)

250 4

200 +

150 4

100 4

Dry Gas Production (M

50 4

I Standard Deviation

o Range

t
1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993

Note: The standard deviation is taken over all months in each year. The range is the difference between the maximum and minimum monthly

values in each year.

Source: Energy Information Administration, Office of Oil and Gas; based on Natural Gas Monthly, historical data series.

Energy Information Administration 9
The Value of Underground Storage in Today's Natural Gas Industry



This movement in the spot price indicates that other forces
were at work in driving up prices in early February. The
response probably resulted from a combination of factors. The
industry had passed through the severe cold of mid-January,
and then experienced another dip in temperatures at the end
of the month. Then, even though temperatures were rising in
early February, another blast of cold weather was forecasted.
Storage had been used extensively during January, pipeline
capacity was tight, and spot prices had been volatile during
January's bid week, leaving traders wondering what was
going to happen next.

Price movements on the futures market also may have
influenced the spot price in early February. Futures settlement
prices had been rising consistently since January 25, from
$2.25 to $2.64 per MMBtu on February 1. Thus the increase
in price on the spot market, in part, could have been a lagged
response to changing expectations as represented by prices on
the futures market. Futures prices then fell precipitously by
$0.20 per MMBtu on February 3, which was followed by a
large drop in price on the spot market on February 4.

An analysis of the two data series shows an overall, positive
relationship between the spot price and the cold weather
index, that is, price increases when the index increases
(Figure 16). However, the index explains only 26 percent of
the variability in the spot price. This low percentage is due to
the inability of the index to explain the three very high prices
at the beginning of February.” When these extreme values are
given less weight, the index explains 41 percent of the
variability. Each 100-unit increase in the index is associated
with a $0.27 per MMBtu increase in the spot price under the
first analysis, and with a $0.22 per MMBtu increase when the
outliers are given less weight.

"February Pricing Picture Confused By Late January's Dizzying
Heights" and "Special Report: If You Thought Mid-January's Weather-
Driven Market Was Intense...." Inside F.E.R.C.'s Gas Market Report,
January 28, 1994, p. 1, and February 2, 1994, pp. 1, 9-10, respectively.

The observations for February 1, 2, and 3 were identified as outliers by
using the ratio of the residual (the difference between the line and the
observed value), relative to the standard error of the residual. The ratio was
2.2 or greater in all three instances.

Summary

The factors influencing the relationship between price and
storage vary throughout the year as the immediacy of the need
for supplies from storage changes between the heating and
nonheating season. During the heating season, however, there
is a strong relationship between storage and movement in spot
prices,

© During the latter part of the heating season, the ratio of
storage levels and expected requirements for the next
month is strongly related to changes in spot prices.
When the amount of gas in storage relative to expected
deliveries rises by one unit (e.g., from a ratio of three to
four), spot prices during the following month can be as
much as $1.09 per MMBtu lower as a result.

@ There is a large premium associated with having ready
supplies of gas in storage when very cold weather
occurs. During the extreme weather conditions
experienced in January 1994, the value of having
supplies from storage readily available was as high as
$1.12 per MMBtu.

In the short term, the relationship between storage levels and
expected deliveries during the heating season is important in
explaining changes in prices on the spot market. Over the
longer term, there are other significant factors that influence
the operation of the industry and pricing of storage services
as well. The next chapter discusses some of the ways the
industry has responded to FERC Order 636 and other
institutional changes. One particular example has been the
increased development of storage in gas producing areas. This
should enhance the reliability and flexibility of the gas
industry because much of the new storage is salt dome
storage. This increased flexibility should further reduce the
seasonality of wellhead prices and also reduce the persistence
of high premium prices for gas when extraordinarily cold
weather hits.

22 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Storage Played a Key Role During the Record Cold in January 1994

The severe winter of 1993-94 placed enormous demands upon the natural gas industry. Record cold temperatures and heavy
snowfall in the Northeast and Midwest during January 1994 led to record monthly natural gas demand, with consumption
nationwide reaching 2,538 billion cubic feet (Bcf), 10 percent higher than during the previous January. Storage facilities were
extensively used to respond to the immediate needs of space-heating customers (Figure 2). Many companies reached all-time
daily withdrawal and sendout levels, particularly during the third week of January. On January 19, Consumers Power,
Michigan's largest gas and electric utility, and Michigan Consolidated delivered record volumes (3.1 and 2.5 Bef, respectively)
of which about 70 percent was from storage. On both January 18 and 19, ANR Pipeline withdrew a record 3.3 Bef per day
from its Michigan fields—almost 4 percent of working gas levels at the beginning of the heating season and substantially
more than the previous peak of 2.8 Bef per day.

Working gas levels were drawn down sharply during the month with withdrawals totaling 756 Bef, equivalent to 30 percent
of gas consumed. During the extremely cold third week of the month, the volume of total working gas in storage dropped 253
Bef, as estimated by the American Gas Association (AGA) (Figure 3). This change was 33 to 54 percent greater than the
decline in each of the previous 2 weeks and was 11 percent of the working gas in storage on December 31. The most extreme
drawdowns in January occurred in the AGA's Consuming East Region (mainly the gas-consuming States east of the
Mississippi River), where estimated net withdrawals of 489 Bcf were approximately 36 percent of the gas consumed. The
interstate pipeline and local distribution companies (LDC's) serving this area rely on storage withdrawals for a substantial
portion of supply during the heating months and have extensive storage facilities already in place. In the producing States,
during the heating season, storage facilities are used primarily to balance flows on main interstate transmission lines.
However, in the single week from January 14 to 21, working gas levels in the Producing Region declined significantly (76
Bef), showing that producers and marketers were relying on storage as well as wellhead production from the region to meet
gas demands. This drop in the level of working gas was 49 to 90 percent greater than the decline that occurred in each of the
previous 2 weeks in this region.

Markets in the West are less weather-sensitive and seasonal storage requirements are correspondingly lower. In addition,
extensive transmission capacity is now available into California and other major western markets. The Consuming West
Region had the lowest level of working gas in storage during January, and activity was unaffected by the eastern cold spell.
The region's decline in working gas from January 14 to 21 was only 14 Bef—lower than the 16 to 25 Bef declines that
occurred in this region during each week of February.

Overall storage withdrawals during January 1994 were 27 percent higher than during the previous January and second only
to the 822 Bef withdrawn in December 1989 when frigid weather in the supply region caused some disruptions in production.
Today's pipeline system is quite different from that in 1989, with much more import capacity available from Canada and more
system flexibility to enable gas to move quickly during peak demand periods. For example, the large Iroquois Pipeline in the
Northeast was designed to handle peak summer loads for electricity generation and thus has sufficient capacity during the
winter to allow extensive linepacking, which is a method for using the pipeline for short-term gas storage. When emergency
supplies were needed by Consolidated Edison of New York during January 1994, Iroquois was able to deliver gas from
linepacking, and several companies were able to divert their supplies to Consolidated Edison and then replace them with
propane and liquefied natural gas from storage.

The additional storage capacity placed in service since 1989 also played a role in supporting the successful delivery of gas
to markets during January 1994. From 1990 through 1993, 136.5 Bef of working gas capacity and 5.7 Bef per day of
deliverability were added, representing increases of 3.8 and 9.2 percent, respectively, over levels in 1989.

Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry





Table B3. Proposed Underground Storage by State, 1994-1999 (Continued)

Capacity Capacity
(billion cubic feet) (MMcf per day)
Working Total Cost
Project Name/State Total Base Gas Gas Withdrawal _Injection (Thousand $)
ALABAMA
SOUTH 4.00 4.30 2.70 100 25 $30,000
ALABAMA-MCINTOSH
TOTALS: Projects=1 4.00 4.30 2.70 100 25 $30,000
ARIZONA
PATAYA PHASE 1 9.00 3.00 6.00 250 120 $41,000
PATAYA PHASE 2 9.00 3.00 6.00 250 120 $18,000
‘TRANAM PHASE 1 11.00 0.00 14.00 1000 0 $0
TRANAM PHASE 2 . 9,00 0.00 9.00 1000 0 $0
TOTALS; Projects = 4 38.00 6.00 32.00 2,500 240 $59,000
CALIFORNIA
Loot 24,00 16,00 8.00 250 130 $25,000
PUTAH SINK 23.00 8.00 15,00 214 107 $40,000
‘TEN SECTION 65.00 25.00 40.00 600 200 $55,000
WILD GOOSE 9.00 3.00 6.00 400 200 $90,000
TOTALS: Projects = 4 421.00 52.00 69.00 4,464 637 219,000
COLORADO
DOUGLAS CREEK 17.00 7.00 10.00 200 250 $30,000
YOUNG 10.00 470 5.30 200 100 $44,400
TOTALS: Projects = 2 27.00 11.70 15.30 400 350 $74,400
ILLINOIS
HILLSBORO EXPANSION 11.60 7.00 4.50 75 ar $36,600
JOHNSON CITY 1.60 0.60 4.00 10 7 $2,600
TOTALS: Projects = 2 13,10 7.60 5.50 85 34 $39,200
INDIANA
CARBON-CALCUTTA 5.60 1.60 3.80 35 18 $12,275
TOTALS: Projects = 1 5.50 4.60 3.90 35 18 $12,275
KANSAS
MID-CONTINENT PHASE 1 1.90 0.65 1.25 100 50 $20,000
MID-CONTINENT PHASE 2 1.90 0.65 1.25 400 50 $11,000
MID-CONTINENT PHASE 3 1.90 0.65 1.25 400 50 $11,000
MID-CONTINENT PHASE 4 4.90 0.65 1.25 100 50 $11,000
MULLINVILLE 7.50 2.80 5.00 500 250 $40,000
RICHFIELD WEST FIELD 6.50 3.00 3.50 50 12 $12,000
RICHFIELD WEST FIELD 1.50 0.00 1.50 30 0 $0
TOTALS: Projects =7 23.10 8.10 15.00 980 462 105,000
KENTUCKY
ELK CREEK 13.00 6.50 6.50 50 33 $14,000
SOUTH ST. CHARLES 1.40 0.70 0.70 6 4 $3,300
ST. CHARLES 29.50 14.75 14.75 120 80 $51,000
TOTALS: Projects = 3 43.90 21.95 21.95 176 117 $68,300
LOUISIANA
CHANDELEUR 26.00 0.00 26.00 300 300 a)
COTTON PLANT 46.00 30.00 16.00 450 173 $100,000

Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



pressure is exposed to the much lower atmospheric pressure,
and gas can flow into and out of the well.

Depleted oil and gas reservoirs are the most commonly used
underground storage sites because of their wide availability.
They use the pressure of the stored gas and, in some cases,
water infiltration pressure to drive withdrawal operations.
Cycling (number of times a year the total working gas volume
may be injected/withdrawn per year) is relatively low, and
daily deliverability rates are dependent on the degree of rock
porosity and permeability, although the facilities are usually
designed for one injection and withdrawal cycle per year.
Daily deliverability rates from depleted fields vary widely
because of differences in the surface facilities (such as
compressors), base gas levels, and the fluid flow
characteristics of each reservoir. Retention capability, which
is the degree to which stored gas is held within the reservoir
area, however, is highest of the three principal types of
underground storage. Depleted field storage is also the least
expensive to develop, operate, and maintain.

In order to use an abandoned gas reservoir for storage, one or
more of the wells used for extraction are typically used to
inject gas. As with extraction, the more porous the rock, the
faster the rate of injection can be. As pressure builds up in the
reservoir, the rate of injection slows down—pushing the gas
in against higher pressure requires more force. Similarly,
when the reservoir is at peak pressure, the rate of extraction
is greater than at minimum pressure.

The factors that determine whether a gas reservoir will make
a good storage reservoir are both geographic and geologic.
The greater the porosity of the rock, the faster the rates of
injection and withdrawal. In some cases, where the reservoir
rock is "tight" or of low porosity, then some form of
stimulation of the reservoir may also be performed. This
would include various methods to introduce cracks into the
reservoir rock, thus increasing the opportunities for the
hydrocarbon to flow towards the weil hole.

The size of the reservoir—the thickness of the gas-bearing
rock stratum and the extent to which the stratum is covered by
cap rock—is another factor. The location is also a factor—if
the reservoir is not close to existing trunk pipelines or market
areas and distribution lines, then greater expense will be
incurred to establish connecting pipelines.

Aquifers

An aquifer storage site (Figure A3) is a water-only reservoir
conditioned to hold natural gas. Such sites are usually used as
storage reservoirs only when depleted gas or oil reservoirs are
not available. Aquifers have been developed exclusively in

market areas. In general, aquifer storage is more expensive to
develop arid maintain than depleted gas or oi! reservoir
storage.

Today, aquifer storage accounts for only 11 percent of the
total working gas capacity and daily deliverability in the
United States. Most of the aquifer storage is located in the
States of Illinois (18), Indiana (8), and Iowa (4). In fact, all of
the underground storage sites in Iowa are aquifers. The
remaining eight aquifer sites are scattered among five
different States.

There are several reasons why an aquifer is the least desirable
site for natural gas storage. First, it takes much longer to
condition the site: on average about 4 years, which is twice as
long as for an average depleted gas or oil field. Unlike a
depleted site, the geology of an aquifer site is unknown
beforehand. As a result, seismic testing must be performed to
determine its geologic profile. Important also are such
characteristics as the confinement area of the reservoir, the
location and type of the “cap" rock ceiling barrier, existing
reservoir pressure, and the porosity and permeability of the
reservoir rock. The potential capacity of the reservoir is also
unknown and can only be determined as the site is further
developed.

Second, all new facilities must be installed, including wells,
pipelines, dehydration facilities, and compressor operations.
Aquifer storage sites may also require additional facilities
such as greater compression for injection purposes (to push
back the water), more extensive dehydration facilities (which
are not always needed at gas reservoir sites), and "collector"
wells drilled into formations above the cap rock, which
recover gas that may penetrate out of the storage zone. An
important consideration is that the design of the facilities
specifically meet the peak-period needs of the customers
expected to use the service. Because of the additional support
of an aquifer's water (pressure) drive, in most instances,
higher sustained deliverability rates than gas or oil reservoirs
can be designed and incorporated at the site.

Third, no native gas is present in an aquifer formation. Thus,
once initial testing has been completed and site development
approval has been granted, base or cushion gas must be
introduced into the reservoir to build and maintain
deliverability pressure. While base gas in gas/oil storage
reservoirs usually is about 50 percent of total capacity, base
gas in aquifer storage may constitute as much as 80 to 90
percent by the time the site is fully developed for gas storage.

Needless to say, the need to acquire such large volumes of
base gas to maintain operational integrity is a crucial
component in assessing the economic viability of the overall
project. Most, if not all, of this base gas is not recoverable
(even when the site is abandoned). Many of the sites in

48 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Figure ES1. Storage Facilities Are Heavily Concentrated Near Major Eastern Markets

Consuming West

¥

ted Fields

A aquiters
®* salt Caverns

Producing

Note: Regions are those established by the American Gas Association.
Source: Energy Information Administration, Office of Oil and Gas, Natural Gas Pipeline Geographic Information System (November 1994).

commercial consuming regions. Underground storage has
helped the gas industry reduce the variability in the amount of
natural gas produced monthly. Without storage the natural gas
industry would require more production wells to satisfy winter
demand. This savings in production wells is viewed as an
efficiency gain traceable to the availability of storage
reservoirs. The availability of storage also allows pipeline
companies to operate more efficiently by enabling them to
function at a more constant level throughout the year, thus
making better use of available pipeline capacity.

Some new aspects of storage are market-based rates for
storage services, the release of storage capacity to third
parties, and the use of storage to support transactions in the
natural gas financial markets. The short-term influences of
storage on the industry have become so important that the
American Gas Association began releasing estimates of
weekly levels of working gas on January 5, 1994. Prior to

this, only the Energy Information Administration's monthly
survey data were publicly available.

Storage Activity and Wellhead
Prices

Storage levels and activities can significantly affect spot
market prices. However, because storage is only one aspect of
the supply picture, the relationship between changes in storage
volumes and spot market prices is not always clear. Still,
when extreme weather conditions occur during the heating
season, withdrawals from storage comprise a larger proportion
of supply to the market areas, and some measures of the
potential impacts can be estimated.

During periods of severe weather or other stress conditions,
the monetary value of natural gas held in storage can change

viii Energy Information Administration
The Vaiue of Underground Storage in Today’s Natural Gas Industry



Figure 13. The Premium Value of Gas Increases as Weather Becomes Colder

1.20 5
eo Feb2

Ss
Z 1.00 4 © Feb3
< .

0.80 +
=
a 0.604
2
Ss
> 040-4
2
= Trend Line
5 0.204 .
2 .
2 . ee
a 0.00

.
-0.20 —— T T T 1
20 10 0 10 20 30

—«— Warmer than Normal —»-«————-. Colder than Normal. —————

Temperature Deviation (Fahrenheit Degrees)
Notes: The premium is the difference between the Henry Hub spot price and the futures price for the expiring contract. The Trend Line is the
result of a least-squares regression. Data are for January 3 through February 28, 1994, excluding weekends and holidays.
Sources: Regression Results: Energy Information Administration (EIA), Office of Oil and Gas: derived from: Premium—derived from Spot
Prices; Pasha Publications Inc,, Gas Daily, and Futures Prices: Commodity Futures Trading Commission, Division for Economic Analysis; and

Temperature Deviation—derived from temperature data from National Oceanic and Atmospheric Administration, National Climatic Data Center.
(See Appendix D.)

Figure 14. Cold Weather Index Shows Persistence of Severe Temperatures
300 -

250 +

200 4

150 4

100 4

Cumulative Fahrenheit Degrees Colder
than Normal

a

T T T T T T T T
Jan.3 Jan.10 Jan.18 Jan.25 Feb.1 Feb.8 Feb.15 Feb. 23
1994

Note: The cold weather index is the cumulative of the average deviation from normal temperatures for four cities: Kansas City, MO; Chicago,
IL; Pittsburgh, PA; and New York, NY. The data were accumulated beginning in mid-December when temperatures first began a systematic
decline from normal levels. Data for weekends and holidays were included in the calculation but excluded from the graph.

Source: Energy Information Administration, Office of Oil and Gas; derived from temperature data from National Oceanic and Atmospheric
Administration, National Climatic Data Center.

Energy Information Administration 19
The Value of Underground Storage in Today's Natural Gas Industry



Appendix B

Proposed Additions
to Underground
Storage

TE



Appendix B

Proposed Additions to Underground Storage

This appendix presents an overview of natural gas
underground storage projects proposed to be completed by the
end of the decade. As of October 1994, 47 new and 34
expansion storage projects had been announced (Figure B1).
These projects would add approximately 495 billion cubic
feet (Bcf) to U.S. working gas capacity, which represents an
increase of 13 percent over 1993 levels (Table B1). Moreover,
this activity will generate an additional 21 Bcf of daily
deliverability from storage, 31 percent above the 1993 level.
The total estimated capital outlay (development cost) for these
81 proposed projects is $2.2 billion.

Most of the planned working gas capacity development is the
traditional depleted gas/oil reservoir type (65 percent), yet this
component accounts for only 31 percent of the planned
increase in daily deliverability and only a 10-percent increase
over 1993 daily deliverability. In contrast, while salt cavern
storage projects represent only 33 percent of the planned
increase in working gas capacity, they account for more than
68 percent of the planned increase in daily deliverability (21
percent above the total 1993 daily deliverability of nearly 68
Bef).

Many of the projects represent expansions to existing or
planned salt storage facilities. Twenty-five salt cavern
expansion projects, with about 6 Bef of daily deliverability
from additional salt cavern reservoirs, are proposed. Depleted
gas/oil and aquifer reservoir expansion projects (9), on the
other hand, represent an increase of only 568 million cubic
feet per day in deliverability. This is only 10 percent as much
as for salt cavern expansion projects and only a 1-percent
increase over existing 1993 depleted gas/oil and aquifer
reservoir levels. Many proposals also include plans to
construct interconnecting lines with other pipeline systems or
additional surface facilities to expand deliverability or provide
additional services.

Some projects have firm commitments with customers and/or
are already under construction. Others are in the engineering
design stage or only the early stages of conceptualization.
Several projects have yet to announce a planned inservice
date. Many projects are competing for overlapping markets
and will be withdrawn when earlier or lower cost entrants
secure their target customer base. Others will be canceled or
delayed because of market or regulatory changes.

The secondary storage market under FERC Order 636 will
have a major influence on the ultimate success of these
projects. Under most compliance plans, the existing
customers of the pipeline companies (primarily distribution
companies) were awarded most of the existing storage
capacity with the remainder going to the pipeline companies
to support no-notice services and system management. As a
result, little additional storage was available initially to third
parties as a result of unbundling. However, a secondary
storage market has developed as distributors have adapted
their supply plans and strategies to the post-636 world. Yet,
at this point it is too early to determine if this secondary
market will offer old storage or pull in new storage. The
evolution of the marketplace during the next 2 to 3 years
should provide valuable insights into these issues.

A variety of companies are active in the development of
underground storage (Table B2). These include intrastate and
interstate pipeline companies, local distribution companies
(LDC's), independent storage developers, marketers,
producers, and electric utilities. In several cases, multiple
parties are jointly developing a project, such as the Avoca salt
bed facility in New York. In this case, J. Makowski &
Associates is developing the project with participation by
Natural Gas Clearinghouse, Texaco Gas Inc, Tennessee Gas
Pipeline Company, Union Gas of Canada, and Equitrans Inc.

Although interstate pipeline companies have been the
dominant providers of underground storage and currently
manage the majority of storage capacity in the United States,
projects sponsored by interstate pipeline companies account
for only 14 percent of the proposed additions to working gas
capacity. Today, independent storage operators are the
principal initiators of new storage projects. They have entered
the storage market in unprecedented numbers, with many
developing new salt cavern storage sites or other
high-deliverability sites. Such facilities, with their high daily
deliverability rates, offer the potential for lower per-unit
operational costs (because of their capability to provide high
turnover in gas inventories, or multiple cycling of inventories
over time).

Some interstate pipeline companies are the primary sponsor
of a project, as in the case of Questar’s expansion of its Clay

Energy Information Administration 87
The Value of Underground Storage in Today's Natural Gas Industry



Figure B1.

Locations of Storage Projects Planned Through 1999

* Depleted Fields
@ Salt Caverns
A Aquifers

Source: Energy Information Administration, Office of Oil and Gas, Natural Gas Pipeline Geographic Information System (November 1994}.

Basin facility. Others are either entering into joint storage
ventures with LDC's and independents or are forming
subsidiary companies to develop underground storage
projects that may or may not serve the pipeline's traditional
market. For example, Enron Storage Inc., which was formed
to develop primarily nonjurisdictional facilities, is sponsoring
the proposed Mullinville (Kansas) bedded salt facility and the
Napoleonville (Louisiana) salt cavern facility.

Integration of New Storage

Most new storage is being planned with access to multiple
pipelines, that is, around market (pooling) hubs, being a major
consideration. This feature permits service and transportation
flexibility, which will enhance a pipeline company's
capability to provide reliable no-notice and other services.

58

The strategic placement of new storage sites in the vicinity of,
or with ready access to, multiple pipeline transporters around
market hubs is enabling new operators to compete effectively
with traditional storage operators. Of the 47 distinct storage
projects, about 20 are located in areas near or adjacent to what
have become known as market pooling points or have been
proposed as such.

Expanded Service Offerings

Developers see a variety of roles for underground storage
located at or near a hub. Key services include supply
balancing and emergency backup. Conceptually, a combined
storage/hub facility would act as a minipipeline system that
transferred gas between sellers and buyers and balanced daily
fluctuations in deliveries to meet nominated volumes on the

Energy Information Administration

The Value of Underground Storage in Today's Natural Gas Industry



Weather Patterns Strongly Affect Storage Use

Natural gas consumption is influenced more by weather patterns than is almost any other commodity. The gas industry makes
its plans for the heating season based on expectations of normal winter temperatures and common deviations from normal.
However, the flexibility of the system and the location of storage sites enable the industry to adjust as needed when prolonged
periods occur with temperatures far below normal.

The natural gas industry was tested by the cold weather of January 1994. The severity of the cold spell, which produced
record-setting demand for natural gas, can be seen by examining the average of temperatures during the period for a selection
of cities (Figure 11). The cities—Kansas City, Missouri; Chicago; Pittsburgh; and New York City—were selected as
representative of large gas markets in the areas hit by the cold.

Tracking of the weather pattern during the coldest days (Figure 12) is useful for illustrating certain important aspects of the
gas industry. The gas system in the United States, especially in the producing regions and the region near the Great Lakes,
is highly interconnected, Thus, during the heating season, when the weather becomes colder in one area and warmer in
another, gas can be moved to the end users that need it the most.

This flexibility is supported by the location of natural gas storage facilities. If one overlaid a weather map for these days with
a storage map, one would find that a large percentage of the U.S. storage facilities are located in market areas where the
weather can turn cold rapidly. Many of these storage facilities are former producing oil and gas reservoirs, left over from a
once thriving producing region that ran from Illinois to Pennsylvania. The placement of these storage reservoirs was
determined not only by geology but also by gas demands, as many gas consumers now live in areas that can be served by
storage in this region.

Figure 11. Average of Temperatures for Four Cities Plummets in Mid-January

60 +
50 4

40 4
Normal Temperatures

|. |

Degrees Fahrenheit

10 +

0

T T T T T T T T
Jan.3 Jan.10 Jan.18 Jan.25 Feb.1 Feb.8 Feb.15 Feb. 23

1994

Note: Data are the mean of average daily temperatures in Kansas City, MO; Chicago, IL; Pittsburgh, PA;, and New York, NY. Data were
excluded for weekends and holidays.

Source: Energy Information Administration, Office of Oil and Gas: derived from: National Oceanic and Atmospheric Administration,
National Climatic Data Center.

16 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry





Contents

Executive Summary ........ 000 cece cece eee e eee e nent ener e nee ene n ene ene e renee nese neta nets vii

1, Importance of Storage in the Gas Industry ..........
Natural Gas as a Commodity and the Role of Storage .

Value of Underground Storage ...........2.-eeeeee
SUMMATY 00... eee eee eee ete e eee cette nee eee
2. Relationship Between Natural Gas Prices and Storage Activity 2
Spot Prices and Monthly Storage Needs ............ ul
The Premium Value of Stored Gas in the Short Term . 13
Spot Prices and a Storage Load Indicator .......... . 18
SUMMALY oo. eect et eee ee . 22
3. Changes in Storage Operations . 25
Inventory Management ........0..00e esses eee reeeeeee . 25
New Market Requirements Are Driving Storage Expansions 29
Competitive Pressures Foster Some Abandonments ......... - 30
The Emphasis on Salt Cavern and Other High-Deliverability Storage . 33
Market-Based Rates for Storage Services .. 34
Storage Capacity Release ............ . 39
Summary ......0 cece cence eee eee eee . 40
Appendices
A. Underground Natural Gas Storage Operations . 43
B, Proposed Additions to Underground Natural Gas Storage . 57
C. Revisions to Working Gas Storage Data . . ~ 7
D. Regression Analysis Results .. . 77
Energy Information Administration v

The Value of Underground Storage in Today's Natural Gas Industry





Figure 2. January 1994 Storage Withdrawals Were the Second Highest on Record

800 —
HB Withdrawals, 1992-93 aa
(1 Injections, 1992-93
[i] Withdrawals, 1993-94
600 — Injections, 1993-94
3 —
oO
ue
°
g
s
© 400-4 '
< \
2
a
200 4
0 | sh bel

Dec Jan Feb

Note: The highest storage withdrawals (822 billion cubic feet) occurred in December 1989.
Source: Energy Information Administration, EIA-191, "Underground Gas Storage Report.”

Figure 3, Almost 1.3 Trillion Cubic Feet of Gas Was Withdrawn from Storage During the Bitter Cold of
January and February 1994

2,400-—
c U.S. Total
o
oO
ue
9 2,0004
2
E]
6 4
e
2 1,600-
3 ” Consuming East
@ 1,200
a
a
a 4
oO
2 8004
< Producing
ES

4004

Consuming W:
0

T T T T T T T
Dec. 31 Jan. 14 Jan. 28 Feb. 11 Feb.25 Mar. 11 Mar. 25

Note: The Producing Region consists of New Mexico, Kansas, Oklahoma, Texas, Arkansas, Louisiana, and Mississippi. The Consuming
East Region consists of all States east of the Mississippi River and Nebraska, lowa, and Missouri. The Consuming West Region consists
of all other tower 48 States.

Source: American Gas Association.

Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Executive Summary

Underground storage is a vital part of the natural gas industry.
The ability to store gas ensures reliability during periods of
heavy demand by supplementing pipeline capacity. Storage
also enables greater system efficiency by allowing more level
production and transmission flows. End-use customers gain
from this increased efficiency with reduced overall costs of
service,

This report explores the significant and changing role of
storage in the industry by examining the value of natural gas
storage; short-term relationships between prices, storage
levels, and weather; and some longer term impacts of the
Federal Energy Regulatory Commission's (FERC) Order 636.
Some of the highlights of the report include the following:

© Expected storage requirements and spot prices are
strongly related during the heating season. High prices
in the spot market are associated with low levels of
storage relative to expected deliveries. As temperatures
drop below normal, storage withdrawals increase and gas
prices can rise dramatically. The premium value of
having gas available for immediate delivery during
periods of stress can be greater than $1.00 per million
Btu. During other times of the year, the relationship
between storage and spot prices is much less direct as
weather and pipeline capacity utilization are of less
concern,

© Regulatory changes during the past decade have
resulted in significant changes in storage operations.
Higher utilization of storage facilities is evident
throughout the year in both injection and withdrawal
activities. However, new programs for storage markets,
such as market-based rates and secondary markets for
storage capacity, have experienced limited growth.

© Proposed capacity additions through the end of the
decade could increase the ability of the storage
industry to deliver gas from storage on a peak day by
almost 31 percent from the level in 1993. About one-
third of the proposed additions to working gas capacity
are for high-deliverability salt cavern storage projects,
which allow greater flexibility for both withdrawals and
injections throughout the year than is available in more
traditional facilities. This flexibility is increasingly
valuable in addressing new market requirements.

The key role that storage plays in the natural gas market was
demonstrated during January and February 1994 when severe
weather placed enormous demands upon the industry. The
additional storage capacity placed in service since the frigid

December of 1989 played a role in allowing the successful
delivery of gas to the markets during January 1994. The
ability to deliver gas from storage has increased by nearly 10
percent over levels available in December 1989.

The Role of Natural Gas
Storage

‘Natural gas consumption is strongly influenced by weather,
with levels during the heating season (November through
March) being about 55 percent higher per month than during
the nonheating season. This pattern is driven by the heavy use
of natural gas for space heating in the residential and
commercial sectors. For example, monthly residential
consumption during the heating season averages three times
higher than during the nonheating season.

Storage, particularly that which is accessed directly by local
distribution companies, gives great flexibility to the
distribution system, allowing it to respond quickly to sudden
shifts in demand. The severe temperature conditions during
January 1994 provide a good example of this flexibility. As
average temperatures in much of the Northeast and Midwest
plummeted to 20 degrees or more below normal, many
companies withdrew record amounts of gas from storage. For
example, ANR Pipeline Company, one of the largest
providers of storage services, withdrew a record 3.3 billion
cubic feet of gas from its Michigan storage fields two days in
a row, exceeding its previous peak by 18 percent.

The industry currently has the capability to store
approximately 8 trillion cubic feet (Tcf) of natural gas in 375
storage sites around the country (Figure ES1). Of this, about
46 percent (3.7 Tcf) is considered working gas storage that
can be withdrawn as necessary to meet demand requirements.
Ona peak day, the industry has the capability to deliver more
than 120 billion cubic feet of natural gas to consumers, and
underground storage can supply as much as half of this
demand. To service the heavy heating load in the Northeast
and Midwest, more than half of the country’s working gas
capacity is located east of the Mississippi River.

The gas industry is willing to invest in storage because of its
considerable value in terms of increased efficiency, increased
reliability of service, and, consequently, market growth.
Historically, the major role of storage in production has been
to smooth natural gas production between the peak and off-
peak seasons by supplying places to store gas in the summer
when gas consumption is low in major residential and

Energy Information Administration vii
The Value of Underground Storage in Today's Natural Gas Industry



13,

14,

References

Pindyck, R. S, "Inventories and the Short-Run Dynamics of Commodity Prices." RAND Journal of Economics, Vol. 25,
Spring 1994, pp. 141-159.

United States Department of Agriculture. Economic Research Service. Wheat - Situation and Outlook Report, May 1994.

Energy Information Administration. "Natural Gas Futures Contract Market - The First Two Years." Natural Gas Monthly,
November 1992, DOE/EIA-0130(91/11). Washington, DC, November 1992, pp. 1-11.

Energy Information Administration. "Natural Gas Futures Market." Natural Gas 1992 Issues and Trends, DOE/EIA-
0560(92), Washington, DC, March 1993.

Herbert, J. H. "The Relation of Monthly Spot to Futures Prices for Natural Gas." Energy, Vol. 18, 1993, pp. 1,119-1,124.

De Vany A. and W. D. Walls. "Pipeline Access and Market Integration in the Natural Gas Industry: Evidence from
Cointegration Tests." The Energy Journal, Vol. 14, 1993, 1-19.

De Vany, A. and W. D Walls. "Open Access and the Emergence of a Competitive Natural Gas Market." Contemporary
Economic Policy, April, 1994, pp. 77-95.

Draper, N. and H. Smith. Applied Regression Analysis. New York: John Wiley & Sons, Inc., 1981.
Chatterjee S, and A. S. Hadi. Sensitivity Analysis in Linear Regression. New York: John Wiley & Sons, Inc., 1988.
Brennan, M. J. "The Supply of Storage." American Economic Review, Vol. 48, 1958, pp. 50-72.

Telser, L. G, "Futures Trading and the Storage of Cotton and Wheat." Journal of Political Economy, 66, June 1958, pp.
233-255.

Amundsen, Erik Schroder. "Seasonal Fluctuations of Demand and Optimal Inventories of a Non-renewable Resource
Such as Natural Gas." Resources and Energy, Vol. 13, 1991, pp. 285-306.

Cho, D. W. and G. S. McDougall. "The Supply of Storage in Energy Futures Markets." The Journal of Futures Markets,
Vol. 10, 1990, pp. 611-621.

Serletis, A. and Hulleman V. "Business Cycles and the Behavior of Energy Prices." The Energy Journal, Vol. 15, No. 2,
1994, 125-134.

Energy Information Administration. "Residential and Commercial Natural Gas Markets." Natural Gas Monthly,
September 1985, DOE/EIA-0130(85/09). Washington, DC, September 1985, pp. XXI-XLIX.

Riddick, C. "A Regression Model for Explaining the Premium Value of Stored Gas in the United States." Virginia
Polytechnic Institute and State University (Telestar Campus), Research Project for Statistics 5615, Statistics in Research,
December 12, 1994.

Energy Information Administration. "Underground Storage of Natural Gas." Natural Gas Monthly, July 1987, DOE/EIA-
0130(87/07). Washington, DC, July 1987, pp. 9-22.

Birkes, David and Yadolah Dodge. Alternative Methods of Regression. New York: John Wiley & Sons, Inc., 1993.

Herbert, J. H., and P, Kott. "An empirical note on regressions with and without a poorly measured variable." The
Statistician, Vol. 37, 1988, pp. 293-298.

Energy Information Administration 85
The Value of Underground Storage in Today's Natural Gas Industry



Appendix D

Regression Analysis Results

This appendix presents summary statistics and other findings for the regression analyses reported in Chapter 2. Background
information for understanding the relationships estimated is included in the main body of the text and references to the data
sources are included in source notes to the figures in the text.

Spot Prices and Monthly Storage Needs
(Pages 11 - 14)

Specification and Estimation

The first regression analysis presented in Chapter 2 deals with the relationship between the spot price of gas at the beginning of
the month (PG) and the level of gas in storage at the end of the previous month (GS) relative to expected consumption (EC) or
deliveries of gas for the month.[1,2] EC is measured by actual total consumption for a month in the previous year. PG is
represented by the price of gas at the Henry Hub in Louisiana, which is the reference price for gas exchanges in the United States
and Canada. This price largely represents exchanges of gas negotiated at the close of the previous month during a period called
bid week when contracts for guaranteed deliveries of gas for the month are signed (for a discussion of spot and futures prices
see [3-7]). An appealing characteristic of EIA storage or inventory data is that it represents inventories at the end of ‘the month.
Moreover, non-EIA price data represent prices negotiated at the end of the month for deliveries in the next month, and EIA
consumption data represent consumption throughout the month. The temporal characteristics of these data are particularly
appropriate for examining the relationship between price and inventories. For most other commodities the inventory and price
data need to be adjusted prior to any econometric analysis.

Large values for GS relative to EC (GS/EC) are expected to be associated with low values for PG because large values for GS/EC
indicate that supplies of gas in storage are plentiful relative to expected deliveries. When the regression equation is estimated,
the following results are obtained (standard errors are reported in parenthesis followed by the coefficient of determination, R,
and the value for the Durbin-Watson test, DW):

PG = 5.12 - 1.09GS/EC q@
(0.911) (0.287)

R?=0.59, DW = 1.78, n= 12 (number of data points for storage at the end of January, February, and March
for the years 1991-1994), .

Evaluation

‘The size of the standard errors relative to the size of the coefficients in equation 1 indicates that the coefficients are significantly
different from zero. The coefficient of determination (R?) indicates that 59 percent of the variation in PG is associated with the
variation in GS/EC. The value for the Durbin-Watson (DW) test, while difficult to interpret with only 12 (n=12) observations,
indicates that the errors terms in the model underlying equation 1 are independent (the assumption of a lack of first-order serial
correlation could not be rejected). Because there are 6 negative residuals and 6 positive residuals and 6 runs of the residuals, a
runs test on the residuals would indicate the same conclusion.[8] Examination of r-student values[9] indicates that there are no
outlying observations. Examination of plots of the residuals against GS/EC also indicates that the assumption of a constant
variance for the error terms is also not violated (copies are available from John H. Herbert, EIA).

Energy Information Administration 7
The Value of Underground Storage in Today's Natural Gas Industry





Table C1. Underground Gas Storage Volumes
(Volumes in Billion Cubic Feet)

Base Gas Working Gas Capacity Working Gas Percent Full
Year/Month Percent
Reported | Adjusted Difference | Reported | Adjusted | Reported | Adjusted | Reported | Adjusted

1991
January 3,984 4,298 8 4,042 3,582 2,328 1,966 58 55
February 3,996 4,289 8 3,915 3,582 2,039 1,685 52 47
March 3,985 4,299 8 3,923 3,582 1,890 1,525 48 43
April 3,997 4,299 8 3,953 3,582 2,020 1,650 51 46
May 4,030 4,299 7 3,850 3,582 2,255 1,911 59 53
June 4,039 4,239 6 3,846 3,582 2,533 2,183 66 61
July 4,043 4,299 6 3,861 3,582 2,750 2,396 71 67
August 4,048 4,299 6 3,862 3,582 2,957 2,596 7 73
September 4,049 4,301 6 3,872 3,589 3,180 2,811 82 78
October 4,051 4,301 6 3,868 3,589 3,347 2,959 87 82
November 4,052 4,302 6 3,840 3,590 3,127 2,757 81 77
December 4,056 4,304 6 3,862 3,599 2,809 2,440 73 68

1992
January 4,038 4,314 7 3,888 3,611 2,203 4,913 57 53
February 4,038 4,314 7 3,887 3,611 1,825 1,525 47 42
March 4,032 4,314 7 3,893 3,611 1,533 1,225 39 34
April 4,022 4,314 7 3,904 3,611 1,562 4,243 40 34
May 4,025 4,314 7 3,901 3,611 1,837 4,520 47 42
June 4,027 4,314 7 3,898 3,611 2,141 1,843 55 51
duly 4,061 4,333 7 3,890 3,617 2,448 2,149 63 59
August 4,058 4,333 7 3,892 3,617 2,749 2,458 ral 68
September 4,057 4,333 7 3,893 3,617 3,031 2,756 78 76
October 4,061 4,335 7 3,892 3,617 3,211 2,939 83 81
November 4,054 4,335 7 3,899 3,617 3,042 2,759 78 76
December 4,022 4,335 8 3,931 3,617 2,585 2,268 66 63

1993
January 4,271 4,337 2 3,692 3,620 1,818 1,713 49 47
February 4,248 4,338 2 3,717 3,621 1,293 1,163 35 32
March 4,228 4,336 3 3,733 3,618 1,017 857 27 24
April 4,239 4,336 2 3,722 3,618 1,108 968 30 27
May 4,254 4,336 2 3,707 3,618 4,512 1,395 41 39
June 4,264 4,336 2 3,697 3,618 1,883 1,763 St 49
July 4,263 4,336 2 3,698 3,618 2,229 2,104 60 58
August 4,270 4,336 2 3,691 3,618 2,537 2,415 69 67
September 4,261 4,329 2 3,684 3,624 2,862 2,733 78 75
October 4,321 4,329 0 3,627 3,627 2,953 2,884 81 80
November 4,342 4,336 0 3,661 3,669 2,771 2,715 76 74
December 4,340 4,338 0 3,669 3,673 2,329 2,275 63 62

1994
January 4,344 4,351 0 3,692 3,685 1,572 1,556 43 42
February 4,338 4,351 0 3,698 3,685 1,085 1,063 29 29
March 4,344 4,351 0O 3,692 3,685 952 931 26 25
April 4,347 4,351 0 3,689 3,685 1,165 1,143 32 34
May 4,353 4,351 0 3,683 3,685 1,548 1,535 42 42
June 4,350 4,351 0 3,686 3,685 1,890 1,878 51 51
July 4,353 4,351 te) 3,687 3,688 2,267 2,258 61 61
August 4,353 4,351 0 3,687 3,688 2,600 2,592 71 70
September 4,351 4,351 0 3,689 3,688 2,904 2,906 73 79
October 4,354 4,354 0 3,689 3,688 3,067 3,067 83 83
November 4,351 4,354 o 3,689 3,688 2,970 2,970 81 81

Note: These data exclude four storage fields included in Figure 1 and Table A1 that are not reported on EIA-191.

Source: Energy Information Administration (EIA). Reported: EIA-191, "Underground Gas Storage Report." Adjusted: Office of Oil

and Gas.

Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry

73



2. Relationship Between Natural Gas Prices
and Storage Activity

The ability of the natural gas industry to store large amounts
of gas has allowed the production and transmission portions
of the industry to operate at a higher level of efficiency than
would, otherwise be possible. The long-term impact has been
to reduce the overall cost of producing and shipping gas, thus
reducing the price of gas to end users.

Increasing attention is being paid to using underground
storage to exploit short-term changes in natural gas prices to
satisfy winter demands at a reduced cost. This management of
storage levels in turn has an impact on short-term natural gas
prices. Although storage is frequently mentioned in the trade
press as a major influence on both spot and futures prices,
previous studies have not examined this relationship. The
analysis is complicated for several reasons. For example, data
are either not generally available or are measured indirectly.
Also, the proportion of end-use demand satisfied from storage
versus production sites varies greatly throughout the year. In
addition, the amounts of gas withdrawn from storage and
from production sites are interdependent, particularly during
the nonheating season. This interdependence has been
expanding and changing in recent years as overall storage
activity has increased throughout the year. Thus great care is
needed in selecting the means for analyzing the relationship
between spot prices and storage activity.

This chapter discusses the short-term relationship between
storage levels and price from several different perspectives.
Regression analysis techniques are used to gain insight into
the strength of the relationships between the different
variables examined.!? An examination of data on price and the
amount of gas in storage at the end of a month relative to
expected consumption in the subsequent month reveals a
quantitative relationship between prices and storage levels.
The chapter also examines daily price behavior to understand
the value associated with having gas in storage during periods
of high demand. This value increases dramatically as supply
conditions tighten during periods of persistently cold weather.

Just as the conditions of December 1989 once served as a
benchmark for industry performance, the extremely cold
weather and high levels of demand in January and February
1994 will serve as the new benchmark. Temperature and price

‘2fn all cases, the least-squares regression procedure is used first. Then
in several instances, the robust procedure, least absolute deviation, is also
used to give fess weight to extreme data values. Appendix D provides
information, such as regression equation coefficients, for each regression
presented in this chapter.

data from this period are used frequently in this chapter to
examine the relationships between price and storage.

Spot Prices and Monthly
Storage Needs

The factors influencing the relationship between price and
storage vary throughout the year. For example, if storage
levels are particularly low at the end of March—the end of the
heating season—many buyers may decide to purchase large
amounts of gas for storage during April, putting upward
pressure on spot prices. On the other hand, if at the same time,
many new producing wells are brought on line or imports
from Canada are larger than expected, then the price of gas
may decline instead. Examining monthly data on spot prices
and total storage levels over several years shows that the
overall relationship between the two series is not readily
apparent (Figure 8).

Before 1992, prices tended to be low in the spring and
summer and high in the early winter, and storage levels
tended to follow a pattern similar to prices. In 1992, prices
increased throughout much of the year, yet storage level
patterns did not change much from the past. In 1991, prices
fell from $1.32 per million Btu (MMBtu) in April, the
beginning of the nonheating season, to $1.19 in July.
However, in 1992, prices rose from $1.57 per MMBtu in
April to $1.83 in July. Even though prices rose between April
and July in one year and fell in the next, storage levels rose in
both years during those months. In 1993 and 1994, the lack of
seasonality in prices contrasts sharply with the continuing
seasonality in storage levels.

The lack of a clear, direct relationship between movements in
storage levels and prices is because the market is more
complex than this simple comparison would suggest. Other
factors, such as supply availability, expected consumption
patterns, movements on the natural gas futures market, and
economic conditions, are affecting the prices as well.

Even if other factors that influence price did not change
much, the relationship between storage and price would be
expected to vary throughout the year. For example, from
April through October, storage is being filled in order to reach
planned levels by the beginning of the heating season

Energy Information Administration 11
The Value of Underground Storage in Today's Natural Gas Industry



DOE/EIA-0591
Distribution Category UC-950

The Value of Underground Storage
in Today's Natural Gas Industry

March 1995

Energy Information Administration
Office of Oil and Gas

U.S. Department of Energy 4 .
Washington, DC 20585 Ni AS

STRIBUTION OF THIS DOCUMENT IS UNLIMITED
os Ne

This report was prepared by the Energy information Administration, the independent statistical and analytical agency within
the Department of Energy. The information contained herein should not be construed as advocating or reflecting any policy
a" of the Department of Energy or any other organization.

PO





normally cycled only once each year and typically requires
200 days to refill."

While salt cavern storage accounts for only 2 percent of total
working gas capacity, it can provide 11 percent of available
storage deliverability on a peak day. In 1993, there were 18
active salt cavern sites, 11 of which had been developed since
1986. This type of storage provides a great deal of flexibility
for quick withdrawals and refills. Because of its ability to
cycle the gas quickly, salt cavern storage is potentially very
useful for supporting the increased load-balancing
requirements of the industry, the new electric generation
requirements for combined-cycle plants,” and as supply for
no-notice service.

Withdrawals from salt cavern storage account for an
increasing percentage of monthly storage withdrawals,
particularly during the nonheating season (Figure 21) when
most depleted reservoir storage is in the injection phase of its
annual cycle. Aithough withdrawals from salt cavern storage
represented less than 4 percent of total withdrawals during
each of the heating seasons from 1989 to 1993, they
accounted for I9 percent in the 1994 nonheating season.
Many of today’s salt cavern storage customers are electric
utilities in Texas, who are increasingly using high-
deliverability storage for very short-term peaking purposes.
Depending on summer temperatures and resulting electric
generation needs, utilities may cycle their storage inventories
many times in the summer months.

Although its role is clearly increasing (see box, p. 36), salt
cavern storage facilities have limited working gas volumes
and are still being used primarily for peaking operations.
Further, it appears that one of the major advantages of salt
cavern storage—its ability for multiple cycling during the
year—is yet to be fully exploited. While the ratio of annual
total withdrawals to working gas capacity (the number of
times that inventory was turned over in a year) for salt cavern
storage facilities has slowly edged up, from 1.11 in 1991 to
1.66 in 1993 and an estimated 1.61 in 1994, it remains very
low relative to the facilities’ capabilities. One possible
explanation for the limited utilization of salt storage lies in the
rate structure under which the storage service has been
offered. Most pre-Order 636 salt cavern storage remains
subject to rate-based cost recovery pricing. Thus, storage
operators generally have been able to obtain their regulated
rate of return on storage operations without multiple cycling

“For further information, see Thomas F, Barron, "Underground Storage
of Natural Gas," GasMart 1993 (Kansas City, MO, March 8, 1993).

2A combined-cycle electric generating plant is one that employs gas-
fired and steam-driven turbines together to increase the efficiency of the
electricity generating process, Such plants require gas delivery under high
pressure and have widely varying load requirements, which make the high-
deliverability capability of salt cavern storage desirable,

of the facility. Peaking service is a high-cost service, and in
this role, salt storage competes with other high-cost
supplemental sources. In the future, salt storage, as well as
other high-deliverability storage facilities, may increasingly
operate under market-based rates and require multiple
inventory turnovers to remain competitive. A number of
proposals involving new salt cavern storage facilities have
been made to FERC for permission to charge market-based
rates (see following section, "Market-Based Rates for Storage
Services").

Finally, while it is common to equate high-detiverability rates
with salt cavern storage facilities, a number of storage
facilities—primarily depleted fields but also one aquifer site
and converted mine—that are not salt-formation reservoirs
have the ability to withdraw working gas as rapidly as the
average salt cavern facility (based on reported working gas
capacities and maximum deliverability rates).> The average
withdrawal cycle for all salt cavern facilities is slightly less
than 12 days, whereas the average for all storage facilities is
about 55 days. Nonetheless, 15 nonsalt cavern storage
facilities (out of a total of 354) have drawdown periods of 12
days or less. In fact, the average drawdown period for this
group of storage facilities is about 7 days.

Market-Based Rates for
Storage Services

An additional characteristic of the new storage market is the
increased interest in market-based rates for services.
Proponents stress that market-based rates for storage enhance
the flexibility or efficiency of the gas industry. One argument
is that the absence of regulation and its associated costs saves
the company money—savings, which can mean a leaner,
more efficient operation; and savings, which can be invested
to expand and improve the business. Another argument
invokes the classic market economics principle: when goods
and services are provided and prices are set in open,
competitive markets, competitors are driven to be more
efficient.

Market-based rates are a relatively new development in the
natural gas industry. The amount of storage capacity subject
to market-based rates is quite small (Table 5). So far, FERC
has approved only applications relating to individual storage
facilities, two of which were operational (Bistineau and

For purposes of this discussion, deliverability is defined in terms of the
"drawdown period"—the number of days to withdraw the total working gas
capacity volume of gas for a given facility at its maximum withdrawal rate
(ce, total working gas capacity divided by maximum withdrawal rate).

34 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



futures market help the industry reduce the price risk of
holding gas in storage. One way to do this is to increase the
efficiency of storage operations so that less gas is exposed to
price risk.

The industry has done this successfully in recent years. For
heating years 1989-90 through 1993-94, average monthly
injections and withdrawals per storage field increased
(Table ES1). The change was most significant for injections
during the heating season and for withdrawals during the
nonheating season. Average injections during the heating
season increased by 37 percent from the average during the
mid-1980's, while working gas levels increased by 9 percent.
Similarly, average withdrawals during the nonheating season
increased by 47 percent while working gas levels increased by
10 percent.

Increased injections and withdrawals have occurred while the
patterns of using working gas capacity have changed. Data for
1991 through 1993 show that the industry has been able to
operate with declining proportions of working gas capacity
filled during the summer months (Figure ES3). During 1994,
however, the share of capacity filled monthly exceeded that
of 1993 throughout the nonheating season, and by September
it even exceeded the 1991 share. The 1994 nonheating season
was the first under Order 636, and thus the first during which
a significant amount of interstate storage came under the
management of parties other than the pipeline companies. For
the most part, these parties are local distribution companies,
and it is not surprising that during this first year they may
have filled, in aggregate, a higher portion of available
capacity than did the pipeline companies. A decline in gas

prices in late summer also may have encouraged the more
rapid filling of storage.

Another area of change has been in the forces driving storage
development. Such factors as the need to resolve pipeline
imbalances quickly and the desire to take advantage of short-
term changes in gas prices have encouraged the construction
of high-deliverability storage facilities such as salt caverns.
More than one-third of the 21 existing salt facilities have been
brought on line since 1991.

The greater deliverability of salt cavern storage, compared
with either depleted field or aquifer facilities, can be seen in
the plans for new storage construction proposed for 1994
through 1999 (Figure ES4). During this period, salt cavern
facilities will account for only 28 percent of the total additions
to capacity, yet they will provide 68 percent of the additional
withdrawal capability.

The newest changes to affect the storage industry are market-
based rates for storage services and the development of a
secondary market for storage capacity. Both have seen limited
development as the industry and Federal regulators attempt to
implement the first programs in each area. To receive
permission to charge market-based rates, the applicant must
demonstrate its lack of market power. This can be difficult
except for those relatively smaller facilities in areas with
substantial storage options already available. As of January
20, 1995, only 96 billion cubic feet of working gas capacity
was subject to market-based rates; and of the applications
FERC has approved, only two are for facilities that are
operational.

Table ES1. Average Monthly Natural Gas Injections, Withdrawals, and Working Gas Levels,
Heating Years, 1982-83 Through 1986-87 and 1989-90 Through 1993-94

(Million Cubic Feet)

Average Injections per Field Average Withdrawals per Field Average Working Gas per Field
Period 1982-83 | 1989-90 1982-83 | 1989-90 1982-83 | 1989-90

Through | Through | Volume | Percent | Through | Through | Volume | Percent | Through | Through | Volume {Percent

1986-87 | 1993-94 | Change | Change | 1986-87 | 1993-94 | Change | Change | 1986-87 | 1993-94 | Change | Change
Nonheating
Season 757 906 149 20 126 59 47 5,891 6,451 560 10
Heating
Season 187 257 70 37 1,099 1,217 118 in 5,247 5,734 487 9
Heating Year 520 642 122 23 531 113 21 5,623 6,160 537 10

Note: Before 1991, data were available only on a company-wide basis. For field-level data before January 1991, company-level data
were apportioned based on the January 1991 ratio of the field's working gas capacity to the company total working gas capacity. Only fields
active throughout the 1982-1993 period were included. A heating year is from April of one year through March of the next year; for example
April 1982 through March 1983 is the 1982-83 heating year. A nonheating season ts from April through October of one year. A heating season
is from November of one year through March of the next year; for example November 1982 through March 1983 is the 1982-83 heating

season.

Source: Energy Information Administration. 1982-83 through 1990-91: EIA-191/FERC-8, "Underground Gas Storage Report." 1991-92

through 1993-94: EIA-191, "Underground Gas Storage Report.

x Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



significantly. For example, the spot price for gas in a given
month is often relatively close to the average price of futures
contracts for the next month. However, if temperatures
suddenly plummet, the price of gas can far exceed that under
a futures contract. The difference between the spot price and
the futures price is defined as the "premium," an indicator of
the value associated with having ready supplies of gas on
hand in storage sites.

Prices during the unprecedented cold spell that hit the eastern
United States in January 1994 provide a good illustration of
the magnitude the premium can reach (Figure ES2). On
January 18, the Monday following the weekend the cold front
hit, spot prices at the Henry Hub (the delivery point for the
futures market) soared, raising the premium to nearly $0.80
per million Btu (MMBtu). The weather abated somewhat,
then was predicted to turn cold again, causing the premium to
peak at $1.12 per MMBtu on February 2.

Just as price changes affect the value of gas in storage, storage
activity can affect prices. Storage levels exhibit the strongest
influence on wellhead prices during the latter part of the
heating season, when the entire gas industry can be expected
to experience the greatest stress. Regression analysis using
data from 1991 through 1994 shows that 59 percent of the
variability in monthly spot prices at the Henry Hub was

+

associated with a measure of the storage system's readiness to
make deliveries. Higher levels of readiness, as indicated by a
higher level of gas in storage relative to expected deliveries
the next month, are associated with lower spot market prices.
(Expected deliveries are monthly consumption levels during
the previous year.)

Interest in the impacts of storage activity has increased
because of the ways in which storage activity has changed in
recent years. Many of these changes are market driven while
others are the direct result of the implementation of FERC
Order 636 in 1993.

Changes in Storage
Operations

Many aspects of storage operations were changing even
before Order 636 became effective November 1, 1993. Some
of these changes occurred in anticipation of the order as the
proposed rulemaking was widely debated throughout the
industry.

One area of change has been in inventory management. The
separate pricing of storage services and the existence of a gas

Figure ES2, The Premium Value of Gas in Storage Rose Dramatically in Early 1994

1205 Feb 2

1.00 +
Jan 19

0.80 ~ Jan 18

0.60 4

0.40 +

0.20 4

Premium (Dollars per Million Btu)

ae

\\

0,00

0.20 Spee eee

Ahn”

TTT

TPT ery
1/3 1/10 1/18 1/25 2/1 2/8 2/15 2/23 3/2 3/9 3/16 3/23 3/30 4/7 4/14 4/21

1994

Note: The premium is the difference between the Henry Hub spot price and the futures price for the expiring futures contract. Data are

unavailable for weekends and holidays.

Sources: Energy Information Administration, Office of Oil and Gas: derived from: Henry Hub Spot Price: Pasha Publications Inc., Gas
Daily and Futures Price: Commodity Futures Trading Commission, Division of Economic Analysis.

Energy Information Administration

The Value of Underground Storage in Today's Natural Gas Industry



Figure A2. Typical Configuration of Depleted Gas/Oil Field Storage

30m

Cross Section of a

Storage Well:
1. Wellhead, 6. Cemented Casing,
2. Safety Valve Control. 7. Packer.
8. Connection Plpe. 8.Caprock,
4, Flow Tubing String. 9. Strainers(-500 to -1,200m),
5. Automatic Safety Valve. —_10.Reservolr.

Source: Gaz de France, "Underground Storages Facilities" (June 1992): Recreated by Energy Information Administration, Office of Planning,

Management, and Information Services.

part) and high-deliverability sites (mostly salt cavern
reservoirs), Seasonal supply sites are designed to be filled
during the 214-day nonheating season (April through
October) and drawn down during the 151-day heating season
(November through March). High-deliverability sites are
situated to provide a rapid drawdown (or rebuilding) of
inventory to respond to such needs as volatile peaking
demands, emergency backup, and/or system load balancing.
Compared to seasonal storage, high-deliverability sites can be
drawn down in 20 days or less and refilled in 40 days or less.

High deliverability can be achieved in a depleted oil or gas
reservoir if the reservoir rock has high porosity and
permeability (allowing a rapid flow of gas), and the reservoir
has sufficient base gas pressure and a sufficient number of
wells to maximize withdrawal. Additionally, it would be
desirable to be able to refill a reservoir in a reasonably short
time. Salt cavern storage is ideal for high deliverability, as the
entire cavern is one large "pore." On average, salt storage
facilities can withdraw their gas in 12 days, versus 71 days for

aquifers and 64 days for all depleted oil or gas reservoirs.
Newly introduced horizontal drilling techniques permit
storage in older depleted gas/oil field storage fields to be
retrofitted to increase deliverability.

Depleted Gas or Oil Fields

Underground storage in depleted gas/oil fields (Figure A2) is
used when gas can be injected into reservoirs with suitable
pore space, permeability, and retention characteristics. All oil
and gas reservoirs share similar characteristics in that they are
composed of rock with enough porosity so that hydrocarbons
can accumulate in the pores in the rock, and they have a less
permeable layer of rock above the hydrocarbon-bearing
stratum. The hydrocarbon accumulation in the porous rock is
pressurized by the weight of hundreds or thousands of feet of
rock on top of the reservoir. When a well hole penetrates the
impermeable cap layer of rock, the hydrocarbon under

Energy Information Administration 47
The Value of Underground Storage in Today's Natura! Gas Industry

eK een



The prevalence of these nontraditional characteristics is, in
part, an attempt by sellers of storage services to take
advantage of the new opportunities offered by an increasingly
unregulated natural gas market. It is also the result of increas-
ing demands for new services by storage customers. In
addition to traditional seasonal storage services, there is
increased interest in:

© Supply balancing—the daily and/or monthly
reconciliation of nominations and deliveries between
buyers and sellers of gas

e© Emergency backup—the use of storage as a backup
source of supply in the event of a production failure or
the nondelivery of gas

© No-notice—the assured delivery of the difference
between a customer's daily nomination and what the
customer actually required on that day

© Price hedging—the use of storage to hedge seasonal or
shorter time period differentials in gas prices.

These services require significantly more operational
flexibility than provided by traditional seasonal supply
service. This includes such characteristics as the ability to
inject and withdraw gas on a continuing basis throughout the
year to balance daily or monthly demands and the ability to
withdraw large quantities of gas quickly and reliably to meet
surges in demand or replace lost production.

The new service requirements and growth in demand are
behind the surge of interest in new underground gas storage
construction (Table 2). If all proposed projects were
completed as planned, working gas capacity would increase
more than 13 percent by 1999 from the level in 1993.
Deliverability would increase by 31 percent, with much more
capacity owned by independent companies (Figure 20). With
the exception of projects that are actually under construction,
however, it is difficult to determine which proposals will have
sufficient customer commitment, adequate financing, and
necessary regulatory approvals to be built and become
operational.

Of the 24 projects that were originally planned to come on
line in 1993, 15 were actually completed and the rest were
deferred to 1994 (Table 3). Completed projects expanded
existing working gas capacity by 97 Bcf and daily
deliverability by 3.7 Bef. These projects represented 67
percent of planned additions to working gas capacity for 1993
and 77 percent of planned additions to daily deliverability.
(As of November 1994, at least three of the deferred projects
had been completed; the others are in various stages of
development/implementation.)

The majority of completed projects are owned by interstate
pipeline companies, accounting for 67 percent of the added
working gas capacity, but only 37 percent of the added peak-
day deliverability. Interstate pipeline companies were also the
most successful in implementing announced additions to
working gas capacity and deliverability, adding 90 percent
and 88 percent, respectively, of what was originally planned.
Only one of the five scheduled projects by independent
operators was brought on line in 1993, yet it accounted for
roughly 20 percent of the total of both new working gas
capacity and new daily deliverability in 1993. While 79
percent of total new working gas capacity brought on line in
1993 was in depleted oil/gas fields, this reservoir type
accounted for only 37 percent of total additional
deliverability; the rest, or 63 percent, was implemented in salt
formation facilities.

Most of the added deliverability is from facilities in the
Southwest (2,280 million cubic feet (MMcf) per day) and the
Midwest (720 MMcf per day), with working gas capacity
increasing by 30.7 Bcf and 42.4 Bef, respectively. The only
other region to figure significantly in capacity additions was
the Northeast, which installed 18.0 Bef of new working gas
capacity, representing 19 percent of total 1993 additions.

Competitive Pressures Foster
Some Abandonments

The 1990's is expected to be a major development period for
underground storage. Nevertheless, since 1990, a number of
existing storage sites have been placed into inactive or
standby mode while several more have abandonment
applications pending before FERC or State public utility
commissions (Table 4).

With respect to a storage field's status, the term "abandoned"
has an official, specific meaning. To abandon a field, the
operator must obtain permission from the appropriate
regulatory agency(ies) and must make certain modifications
to the physical characteristics of the field. For example, at a
minimum the operator would be required to plug each well,
dismantle and dispose of all above-ground equipment
associated with each well, and dispose of other above-ground
assets that might be safety hazards. The operator very likely
would be required to accomplish some measure of
environmental restoration or remediation, and might also be
required to remove some of the below-ground equipment
(e.g., well casings), particularly if it might in some way
endanger environmental integrity at the site.

30 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Appendix C

Revisions to Working Gas Storage Data

An underground storage site is described by its total capacity
(the total volume of gas that can be stored in the facility), its
base gas or volume of gas that remains in the facility at all
times, and its working gas capacity, which is the difference
between the first two measures (total capacity minus base
gas). Base gas is the amount of gas that supports the working
gas by providing pressure to enable the working gas to be
withdrawn at an acceptable rate. Working gas is the amount
of gas in the site that is available for withdrawal to serve
customer or system needs. Only when the storage site is
completely full does the working gas reach the working gas

capacity.

Each month gas is injected into and withdrawn from an
underground facility, either increasing or decreasing the
working gas. In theory, the level of working gas cannot
exceed the working gas capacity nor may it drop below zero.
In practice however, it is possible to exceed the working gas
capacity by overpressurization, and it is possible to go below
zero by withdrawing base gas. The determination of base gas
has some degree of flexibility, depending on what level is
determined necessary to maintain a desired withdrawal rate.

Each month, on the Energy Information Administration's
Form EIA-191, "Underground Gas Storage Report," storage
operators report their current estimates of total capacity, base
gas, and working gas, as well as their estimates of gas
withdrawn and injected that month. Base gas levels can
fluctuate slightly because of factors such as migration losses,
but these are usually very small changes. Base gas will also
change if a site is expanded, and will increase as a new site or
an aquifer is pressurized. Otherwise, base gas is essentially a
constant. Similarly, the total capacity of a reservoir is not
expected to change. Base gas thus represents a financial cost
that is not recoverable because the gas is ordinarily not
withdrawn and sold until the site is abandoned.

However, between January 1992 and December 1993, over
one-quarter (118) of all facilities revised their base gas levels
overall by more than 3 percent, thus also changing the
working gas capacities. An additional 33 sites reported
withdrawals from base gas. The largest changes to base gas
came just prior to the 1993-94 heating season. The total base
gas revisions were substantial, representing a net change of
more than 250 billion cubic feet, or 6.3 percent, from levels
a year earlier. Comparatively, between the 1990-91 and 1991-
92 heating seasons, base gas levels were revised upward by

only half that amount. In prior years, revisions were less than
1 percent annually.

In effect, existing working gas capacity was downsized during
1992 and 1993, whereby a portion of working gas was shifted
to the base gas category for accounting purposes. The 3-
percent increase (104 billion cubic feet) in base gas levels
during 1992 reflect changes in the natural gas marketplace as
a result of open-access transportation programs. Columbia
Gas Transmission, for instance, revised its base gas estimates
at a number of its storage sites after a global settlement
reached with its customers indicated that the customers
wanted, and market demand indicated a need for, more
peaking service, thus, a need for higher daily deliverability
from storage. Columbia, therefore, increased its base gas at
most of its storage sites to increase reservoir pressure and,
consequently, deliverability. Penn-York Energy Corporation,
in a separate settlement case before FERC, was permitted to
increase its base gas at one of its major storage sites to
compensate for gas lost over a period of time because of
reservoir migration. The reclassification provided for cost
recovery.

In 1993, most of the base gas reclassification resulted from
the restructuring of storage operations by interstate pipeline
companies to comply with the Federal Energy Regulatory
Commission's (FERC) Order 636. Before the reclassifications,
these operators had more capacity classified as working gas
than could realistically be withdrawn during a heating season
or refilled during a nonheating season. Therefore, under
restructuring, they revised their estimates to present a more
representative picture of storage capabilities to their
customers. In most instances, these reclassifications are
subject to final approval in the pipeline company's ongoing
rate case.

Impacts on Analyses

Because base gas levels were revised only at some sites and
at different time periods, comparisons of certain storage data
cannot be made. For example, comparisons of working gas

“®The major companies that reported revised base gas levels in response
to the FERC ruling were: Natural Gas Pipeline Company of America, KN
Interstate Gas Co, Southern Natural Gas Co, Equitrans, Inc., and El Paso
Natural Gas Co.

Energy Information Administration rel
The Value of Underground Storage in Today's Natural Gas Industry



The Premium and Temperature
Deviations

Given the importance placed on having storage supplies when
conditions are extreme, one would expect the premium to
move in the same direction as storage withdrawals; that is,
a higher level of withdrawals would imply a larger premium.
Information on the premium and daily storage withdrawals is
needed to analyze this relationship. While the daily premium
can be calculated, daily measures of storage withdrawals are
not available. However, because gas from storage is needed
most during periods of cold weather, daily deviations from
normal temperature can serve to represent daily storage
withdrawals. Thus the relationship between the premium and
temperature deviations is analyzed instead. (See Appendix D
for a detailed discussion.)

A direct relationship exists when the two data series are
analyzed for January 3 through February 28, 1994. The
deviation from normal temperatures explains 37 percent of
the variability in the premium during this period (Figure 13).
Each unit increase in the deviation from normal temperature
is associated on average with an increase in the premium of
$0.018 per MMBtu.

The explanatory strength of the relationship is weakened
because the observations for February 2 and 3 are outliers
with respect to the other data points. When less weight is
assigned to the outliers, 51 percent of the variability in the
premium is explained by the deviations from normal
temperature.”

The magnitude of the premium on these days, for example
$1.12 per MMBtu on February 2, represents, in part, the
perceptions of the industry and uncertainty about the overall
capability of the gas system to deliver gas as needed. While
such perceptions cannot be measured directly, they can have
a major impact on price (see Appendix D).

For a theoretical discussion of this issue, see Michael J. Brennan,
Supply of Storage," American Economic Review, 48 (1958), pp. 50-72.

2'These two observations for early February were identified as outliers
by using the ratio of the residual (the difference between the line and the
observed value), relative to the standard error of the residual, The ratio was
greater than 3 in both instances. See Appendix D for further discussion.

2When additional variables are introduced, the explanatory power of the
regression increases. For example, if less weight is assigned to the outliers
(least absolute deviation) and a proxy variable is added to capture the cost
of storage and the cost of borrowing money, 69 percent of the variability in
the premium can be explained. Alternatively, if the same proxy variable is
used and a third variable is added to estimate the increase in the premium
that is due to uncertainty in the gas industry in early February, then 76
percent of the variability in the premium can be explained. See Appendix D
for more details.

Spot Prices and a Storage
Load Indicator

Another way of looking at the relationship between storage
and price is to examine the effect of prolonged demand (load)
for gas from storage facilities. During the later part of the
heating season, the operational conditions at storage sites can
be quite different than at the beginning of the heating season.
For example, with lower storage levels and reservoir pressure,
the sustainable deliverability from a reservoir may be
significantly less than at the beginning of the season. One way
of examining this effect on prices is to look at cumulative
daily deviations from normal temperature.

Cumulative temperature deviations can serve as an indicator
of cumulative daily storage withdrawals, and thus reflect the
overall load placed on the storage industry during persistently
cold weather. Cumulative deviations from normal temperature
are similar to the heating degree day (HDD) index, which is
used widely throughout the gas industry to plan and schedule
deliveries of gas. But they are also different because the HDD
index is a sum of average daily deviations from some base
temperature, usually 65° F, and deviations above 65° F are
excluded from the calculation. Whereas an HDD index is used
to obtain an indication of the influence of temperature on
space-heating requirements, the sum of average deviations
from normal temperature, referred to here as a "cold weather
index," is used to obtain an indication of the influence over
time of temperature on storage requirements or load.

The weather of January and February 1994 again provides
some insights into this relationship. The cold weather index
(storage load indicator) reveals an interesting pattern
(Figure 14). It rises rapidly in the third week of January,
subsides slightly, then rises consistently once more at the
beginning of February. The initial spike in the spot price at
the Henry Hub (Figure 10, top graph) corresponds well to the
cold weather index when the coldest temperatures were
experienced in mid-January. After falling, the spot price
remained relatively constant between January 25 and 27,
when the index hardly changed. Then in spite of an increase
in temperature on Friday, January 28, the spot price rose as
weather was predicted to turn cold again over the weekend.
The price then rose sharply on February | and 2, at a faster
rate than would be expected from the mid-January patterns of
the spot price and the cold weather index. (The impact of the
weather on other wellhead markets is described in the box on
page 20.)

18 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Figure 21.
Nonheating Seasons

12 —
If Nonheating Season
1o J Heating Season

Percent of Total Withdrawals

ae

Withdrawals from Salt Cavern Storage Show Steady Increases, With Substantial Gains in

1990-91

1989-90

1991-92

1992-93 1993-94

Heating Years

Sources: 1989-1990: Energy Information Administration, ElA-191/FERC-8, "Underground Gas Storage Report." 1991- 1994: Eneray
Information Administration, EIA-191, "Underground Gas Storage Report."

Greasy Creek) and five of which were in various stages of
planning or construction at the time of application.

“Market Power:" The Determining
Factor for Market-Based Rates

To be approved to charge market-based rates, FERC requires
the applicant to demonstrate that it lacks market power in the
market that it intends to serve. FERC defines market power as
",,, the ability of a seller profitably to maintain prices above
competitive levels for a significant period of time."** Thus,
the critical element in a storage provider's application for
market-based rates is its analysis of its market and its relative
standing in that market.

Thus far, in its review of market-based rate applications,
FERC has defined a facility's market as narrowly as possible,
both from a geographic standpoint as well as from the
standpoint of which products/services are alternatives to the
applicant's, FERC’s reasoning is that if it can be shown that
the applicant cannot wield market power in a narrowly

“Federal Energy Regulatory Commission, Bay Gas Storage Company,
Ltd, 66 FERC § 61,354, at p. 62,189 (1994); Richfield Gas Storage System,
59 FERC § 61,316, at p. 62,167 (1992).

defined market, then it certainly will not have market power
in broader markets.

In its review of market analyses, FERC relies (although not
exclusively) on two numeric measures: a facility's or
company's market share, and a related measure, the
Herfindahl-Hirschman Index (HHI) of market concentration>
Market share is simply the ratio of the applicant's storage
service capacity to total storage capacity in the market. A
small HHI means that the market is not concentrated and
customers have ample alternatives. FERC defines a "good
alternative" as one that ". . . is available soon enough, has a
price that is low enough, and has a quality high enough to
permit customers to substitute the alternative. . ." for the
service offered by the applicant2*

*The HHI for a market is the sum of the squares of each storage
provider's market share. For example, if ‘a particular market has two sellers,
with market shares of .75 and .25, respectively, the HEIL is computed as
follows: (.75)' + (.25)'= .5625 + .0625 = 6250. The lower the HHI, the less
market conceritration and the greater likelihood of a competitive market. See
Federal Energy Regulatory Commission, CP94-161-000, Avoca Natural Gas
Storage, Preliminary Determination on Non-Environmentat Issues (July 8,
1994), pp. 13-14.

“Federal Energy Regulatory Commission, CP94-161-000, Avoca
Natural Gas Storage, Preliminary Determination on Non-Environmental
Issues (July 8, 1994), p. 8.

Energy Information Administration 35
The Value of Underground Storage in Today's Natural Gas Industry



Figure 12. Deviations from Normal Temperatures, January 17 - 20, 1994

January 17

January 18

SN
Ree
SSN

Fahrenheit Degrees

[J 0-9 Above Normal

NY 1-9 Below Normal
(C__] 10-19 Below Normal

[J 20-29 Below Normal
i 30-39 Below Normal
[HE 40-49 Below Normal

Cities

@ Kansas City, MO
4K Chicago, IL

Source: Energy Information Administration, Office of Oil and Gas: derived from data for 240 locations from National Oceanic and

Atmospheric Administration, National Climatic Data Center.

A Pittsburgh, PA
IB New York, NY

Energy Information Administration
The Value of Underground Storage in Today's Natural Gas industry

7





Tables

Monthly Natural Gas Injections, Withdrawals, and Working Gas Levels,
Heating Years, 1982-83 Through 1986-87 and 1989-90 Through 1993-94 ...

2. Proposed New and Expansion Underground Storage Projects in the United States, 1994-1999 .
3. Planned Versus Actual Storage Additions, 1993 ..............00.00008 32
4. Changes to Working Gas Capacity and Daily Deliverability, 1990-1993 . 32
5. Storage Service Providers Seeking to Charge Market-Based Rates 37
Figures
1. Storage Facilities Are Heavily Concentrated Near Major Eastern Markets . 2
2. January 1994 Storage Withdrawals Were the Second Highest on Record .. 5
3. Almost 1.3 Trillion Cubic Feet of Gas Was Withdrawn During the Bitter Cold of January and February 1994 . 5
4. An Active Storage Industry Enables Production to Vary Much Less Than Consumption on a Monthly Basis ..... 8
5. Recently, Seasonality in Production Appears to Have Declined as Withdrawals and Imports Have Increased ..... 9
6. By 1993, Average Variability in Production Was About Half of Its 1986 Value a)
7. During the Heating Seasons in the 1990's, Storage Withdrawals and Imports Have Generally Increased
as a Percent of Consumption While Production Has Declined 10
8. Storage Levels and Spot Prices Are Not Clearly Related ....... 12
9. Spot Prices Decline When More Storage Is Available for Deliveries 14
10. Prices Reacted to the Frigid Weather in January and February 1994 .. 15
11. Average of Temperatures for Four Cities Plummets in Mid-January .. 16
12. Deviations from Normal Temperatures, January 17-20, 1994 ..... 17
13. The Premium Value of Gas Increases as Weather Becomes Colder .. . 19
14. Cold Weather Index Shows Persistence of Severe Temperatures .................. 19
15. Henry Hub and Iroquois Have Largest Increase in Spot Prices, January 13-24, 1994 21
16. Daily Spot Prices Rise as Cold Weather Index Increases :
17. As Order 636 Takes Effect, Storage Volumes Owned by Interstate Pipeline Companies Continue to Decline .... 26
18. Utilization of Storage Facilities Has Increased During the Heating Seasons .......... 0.000 ccc ccseeveeeees 28
19. Storage Capacity Utilization in 1994 Reversed the Declining Trend, Moving Higher Than 1991 Levels
Near the End of the Nonheating Season . 29
20. Independent Operators Are Projected to Play a Larger Role in Storage by the End of the Decade . . 31
21. Withdrawals from Salt Cavern Storage Show Steady Increases, With Substantial Gains in Nonheating Seasons .. 35

vi

Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Figure 4.
Monthly Basis

400—

3004

illion Cubic Feet)

2004

100 4

An Active Storage Industry Enables Production to Vary Much Less Than Consumption on a

1983-1988
HB Dry Gas Production

Consumption

1989-1993
(J) Storage Withdrawals

Note: This graph measures the standard deviation of monthly production, consumption, and withdrawals over al! months in each time period,
1983-1988 and 1989-1993. The standard deviation measures the average dispersion of an actual production level in a given month from the mean

production level over each time period.

Source: Energy Information Administration, Office of Oil and Gas; based on Natural Gas Monthly, historical data series.

Canada and of a more active storage industry (Figure 5). Peak
storage withdrawals during the heating season in the late
1980's and early 1990's have tended to be larger than in
earlier years. Imports of gas have also increased throughout
the heating season relative to earlier years. What is not appa-
rent from these data, however, is the capability to use storage,
especially high-deliverability storage, to satisfy daily and
weekly peak demands for gas, which reduces the need to use
gas from production sites (see box, p. 4).

The decrease in the variability of production between the mid-
1980's and early 1990's is significant. By 1993, average
monthly variability in production had declined by 48 percent
from 1986 levels. The percentage decline in the difference
between the peak-month and the low-month production (the
range) was also large (Figure 6). The range fell from 322 Bef
to 174 Bcf—a decline of 46 percent. As a percentage of
consumption, domestic dry gas production during the heating
season has tended to decline while imports and withdrawals
from storage have tended to increase (Figure 7).

Summary

Storage plays a key role in the natural gas market. The
amount of gas in storage is integrated with the performance of
every aspect of the gas industry from production at the
wellhead to distribution to a household even on the coldest
day of the year. The presence of storage facilities in market
areas allows monthly production to vary much less than
consumption. Moreover, as discussed in more detail in
Chapter 3, the contribution of storage to efficiency gains
appears to have continued into much of the period of industry
restructuring that has taken place since the mid-1980's. This
gain in efficiency is indicated by the more intensive use of
storage reservoirs and the drawing down of storage stocks.
During much of the 1990's, the amount of working gas in
storage declined although injection and withdrawal activity
increased.

The extensive storage facilities throughout the United States
enable the gas industry to charge lower prices for natural gas
services than it could without storage because of the gains in
efficiency associated with storage use. This is a long-term
effect resulting from the huge capital investments made over
many years to develop the storage industry.

8 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



capacity or percentage of working gas filled in September
1992 versus September 1994 would not be valid because base
gas is a part of the calculations.

Another difficulty in data comparisons is that the reported
working gas levels are often changed from one month to the
next. Many respondents (storage operators) to Form EIA-191
re-estimate storage levels from time to time, so that working
gas for the reported month is not the sum of last month's total
plus injections and minus withdrawals. From 1991 through
1994, working gas levels had been re-estimated for more than
96 percent of the storage sites.

The approach taken to resolve some of these data and
analyses difficulties was to recalculate working gas capacity
and working gas levels using the following two assumptions:

1, The most recent estimates of base gas are also
historically valid as the most accurate.

2. Estimates of monthly injections and withdrawals are
accurate.

The monthly data for each storage site were sorted beginning
with the most recent data. From that starting point, injections
and withdrawals were systematically added and subtracted to
produce new monthly working gas levels. The most recent
capacity and base gas values were also carried back through
the previous months. These new calculations produced little
difference in the 1994 data but increasing difference in earlier
years. Table C1 summarizes the calculations by month for all
storage sites, showing the difference in base gas increasing to
8 percent by early 1991, and the difference in percent filled
(ratio of working gas to working gas capacity) increasing to
6 percent.

72 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Table A1.

Summary of Existing Underground Natural Gas Storage, by State and Type of Reservoir, 1993

Depleted Gas/Oil Aquifer Storage Salt Cavern Storage Total
State Working} Daily Working} Daily Working| Daily Working} Daily
Number} Gas | Deliver- |Number| Gas | Deliver- |Number} Gas | Deliver- |Number| Gas | Deliver-
of |Capacity| ability of |Capacity) ability of “|Capacity] ability of |Capacity| ability
Sites (Bcf) ((MMcfiday)) Sites (Bcf) |(MMcfiday)| Sites (Bcf) |(MMcfiday)} Sites (Bef) |(MMcfiday)

Arkansas 1 3 32 0 0 0 ) 0 oo) 1 3 32
California 9 222 5,618 O 0 oO 0 oO 0 9 222 5,618
Colorado 9 57 926 0 0 0 0 0 0 9 57 926
lowa o 0 0 4 98 965 0 0 Oo 4 98 965
Ilinois 10 4t 679 17 277 4,849 0 0 0 27 7 5,529
Indiana 16 18 268 8 7 280 0 0 0 24 35 549
Kansas 18 118 2,215 Oo) 0 i) 1 2 100 19 120 2,315
Kentucky 19 99 2,847 2 6 106 0 0 0 21 105 2,953
Louisiana 8 273 4,049 °O oO 0 3 12 944 1 285 4,993
Maryland 1 16 306 i?) i) t) 0 0 0 1 16 306
Michigan 44 615 11,101 i) oO 0 2 3 80 46 617 11,181
Minnesota 0 te) 0 1 2 60 oO te) i) 1 2 60
Missouri 0 ) 0 4 8 350 0 QO 0 1 8 350
Mississippi 3 35 1,025 0 tt) 0 3 17 1,020 6 52 2,045
Montana 4 203 308 0 0 0 0 0 O) 4 203 308
Nebraska 2 15 221 te) 0 O 0 0 o 2 15 221
New Mexico 2 58 325 1 6 14 0 0 Qo 3 64 339
New York 21 76 1,009 0 0 0 0 0 QO 21 75 1,009
Ohio 22 238 4,653 0 i) 0 te) te) te) 22 238 4,653
Oklahoma 12 133 5,468 oO i) i) 0 0 0 12 133 5,468
Oregon 1 7 80 0 0 ) 0 te) 0 1 7 80
Pennsylvania 55 329 4,736 i) 0 0 tt) 0 0 55 329 4,736
Texas 18 324 4,239 0 i) 0 12 48 4,897 30 369 9,136
Utah 1 45 400 2 9 98 0 0 te) 3 54 498
Washington 0 o i) 1 15 525 oO o 0 41 15 525
West Virginia 35 209 2,722 i) to) O 0 O 0 35 209 2,722
Wyoming 5 42 147 1 4 58 0 o i) 6 46 205

Total 316 = 3,170 53,380 38 443 7,306 21 82 7,041 375 «3,696 = 67,729

Bef = Billion cubic feet. MMcffday = Million cubic feet per day.

report,

Does not include 21 storage facilities reported on Form EIA-191 because they are considered inactive or standby for purposes of this

Source: Energy Information Administration, EIA-191, “Underground Gas Storage Report.”

Owners and Operators of
Storage

The principal owner/operators of these underground storage
facilities are (1) interstate pipeline companies, (2) local
distribution companies (LDC's), (3) intrastate pipeline
companies, and (4) independent storage service providers.
Several natural gas producers and large industrial users also
own a limited amount of storage.

Interstate pipeline companies operate about 62 percent of all
working gas capacity in the United States (Table A2).
Historically, these FERC-jurisdictional companies have
owned and distributed most of the natural gas from U.S.
underground storage sites. Underground storage has

Energy Information Administration

traditionally been important to interstate pipeline companies
because they depend heavily on storage inventories to
facilitate load balancing and system supply management on
their long-haul transmission lines.

LDC's and intrastate pipeline companies account for about
34 percent of working gas capacity. LDC's generally use gas
from storage sites to serve customer needs directly, whereas
intrastate pipeline companies use underground storage for
operational balancing and system supply as well as the energy
needs of end-use customers. While most LDC and intrastate
pipeline storage operations are subject only to State regulatory
agencies, 14 percent (8 of 58) are subject to FERC
jurisdiction because they also provide significant service to
the interstate market.

Independent operators own or operate about 4 percent of
current working gas capacity. Many of the salt formation and

45

The Value of Underground Storage in Today's Natural Gas Industry



Appendix C

Revisions to
Working Gas
Storage Data



The main reason for introducing S,./D, into equation 6 is to reduce any bias in the other estimated coefficients from not including
a variable that, in principle, belongs in the equation. This bias increases with the correlation between the S,.,/D, and the other
variables. Since the correlation between S,,/D, and the other variables is small, as indicated by lack of any change in the
magnitude of the other coefficients when S,.,/D, is included in the regression equation, it was decided that nothing is gained by
including this variable in the regression equation.[19} It is probably best to conclude that S,,/D,, as measured, is not a good proxy
variable for daily storage levels (correctly measured) relative to expected demands, and little harm is introduced by not including
it in the estimated equation. Little harm is done because changes in temperature between days tend to be independent and
uncorreiated. DT is influenced by changes in temperature on day t. The level of S,., is influenced by changes in temperature on
day t-1. Thus, these two variables are probably uncorrelated.

In conclusion, the amount of variability in PR explained by equation 6 is probably less than it could be because a correctly
measured stock variable is missing from the relationship. Yet, the estimated coefficients are not badly biased from not including
this variable because there is probably not much correlation with the other variables included in the relationship.

Spot Prices and a Storage Load Indicator
(Pages 18 - 22)

Specification and Estimation

In the final estimation, it was decided to determine for the period January and February 1994 whether there was any relationship
between the daily spot price at the Henry Hub (DSP) and cumulative deviations from normal temperatures, referred to as the "cold
weather index" (CWI) in the text (the higher the value for the index the colder the weather for the time period over which the
index was computed). CW] is also an indicator of cumulative withdrawals of gas above expected levels of withdrawals during
the 2 months. CWI is probably best for comparing the severity of the winter for several years and comparing the price that
evolved during these periods. For example, if the cold winter index is generally lower in year t+1 than in year t, one would expect
price to be lower as well, other things being equal. As discussed in the text, comparing CWI values is similar to comparing
heating degree day numbers for winter months. Generally, it is expected that there would be a positive relationship between DSP
and CWI. When DSP is regressed on CWI using an OLS estimator (equation 9) and a LAD estimator (equation 10), the following
estimated results are obtained (standard errors are given in parenthesis):

DSP = 2.08 + 0.0027CWI (9)
(0.142) (0.00751)

R? = 0.26.

DSP = 2.08 + 0.0022CWI (10)
(0.071) (0.00042)

R?=0.41.

Evaluation

As distinct from the other estimations reported in this appendix, these estimated equations are unreliable for several reasons.
There is a significant first-order serial correlation between the residual values from both estimations. Thus, it is not possible to
assume that the error terms are independent. Moreover, the magnitude of the residual tends to increase as CWI increases
suggesting that the assumption of a constant variance of the error terms is also questionable. Nonetheless, the coefficients are
stable, even though the standard errors of the coefficients are biased, and they provide a useful summary of the relationship
between CWI and DSP for the time period.

84 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Appendix D

Regression
Analysis Results



Figure D1.

4.00 =
3.00 +
2.00 4
1.00 + ° .

0.00 -

Residuals Plotted Against Predicted Value for PR

-1.00 4 .

-2.00 4 . .

Residuals (Dollars per MMBtu)

-3.00 +

-4.00 4

-5.00

-0.2 0 0.2

Source: Regression equation 6.

T T T
0.4 0.6 0.8

Predicted Value for PR

Figure D2. Residuals Plotted Against Variable DT

4.00 =

3.00 =
4 .

2.00 4 .

1.00 4 .

0.00

-1.00 +

-2.00 4

Residuals (Dollars per MMBtu)

-3.00 4

-4.00 4 .

-5.00 ;

Source: Regression equation 6.

82 Energy Information Administration

tt) 10
Variable DT

20 30

The Value of Underground Storage in Today's Natural Gas Industry



suppliers, for the most part the flow of LNG imports virtually
ceased by 1981.

LNG imports have never attained a significant place in the
overall supply market. In 1993, LNG imports were only 81
billion cubic feet, accounting for less than 1 percent of
domestic consumption and only 9 percent of underground
storage withdrawals. Today, only two companies continue to
import LNG supplies: Trunkline Gas Company into its Lake
Charles, Louisiana, site and Distrigas of Massachusetts into its
Boston (Everett) facility. LNG imports, as a peaking source
relative to underground storage, maintain only a minor niche
in the current storage system.

Storage for Peaking and Peak-shaving

Underground natural gas storage inventories provide suppliers
with the means to meet peak customer requirements up to a
point. Beyond that point the distribution system still must be
capable of meeting customer short-term peaks and swings that
occur on a daily and even hourly basis. During periods of
extreme usage, peaking facilities, as well as other sources of
temporary storage, are relied upon to supplement system and
underground storage supplies.

Peaking needs are met in several ways. Some underground
storage sites are designed to provide peaking service, but most
often LNG and liquefied petroleum gas such as propane are
vaporized and injected into the gas distribution system supply
to meet instant requirements (Figure AS). Short-term
linepacking is also used to meet anticipated surge
requirements. Above-ground natural gas holders are
sometimes available.

The use of peaking facilities, as well as underground storage,
is essentially a risk-management calculation, known as peak-
shaving. The cost of installing these facilities is such that the
incremental cost per unit is expensive, perhaps as high as $10
per thousand cubic feet. However, the cost of a service

interruption, as well as the cost to an industrial customer in

lost production, may be much higher. In the case of
underground storage, a suitable site may not be locally
available. The only other alternative might be to build or
reserve the needed additional capacity on the pipeline
network. Each alternative entails a cost.

A local gas distribution company (LDC) installs supplemental
supply sources (underground storage, LNG, and propane) and
uses linepacking to "shave" as much of the difference
between the total maximum user requirements (on a peak day
or shorter period) and the baseload customer requirements
(the normal or average) daily usage. Each unit "shaved"
represents less demand charges (for reserving pipeline
capacity on the trunklines between supply and market areas)
that the LDC must pay. The objective is to maintain sufficient
Jocal underground storage capacity to minimize capacity
reservation. costs on the supplying pipeline by using
conventional storage and also having in place additional
supply sources such as LNG and propane air to meet large
shifts in daily demand. In these instances, the tradeoff is
between high-deliverability storage such as salt dome
facilities and propane-air plants.

Although peaking facilities are often used only a few days a
year, their availability is critical. For instance, if it were not
for these facilities:

© = More long-haul pipeline capacity, and in many cases
local pipeline deliverability, would have to be built to
serve end-use customers.

© Much more underground storage would have to be
developed (if suitable sites were available) to meet
peak and surge requirements in addition to seasonal

supply.

© More large industrial and electric utility users of
natural gas would have to have the capability to
fuel-switch during peak periods.

52 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



3. Changes in Storage Operations

Market and regulatory changes during the past several years,
culminating with Order 636, have led to an increased role in
the gas industry for natural gas storage. The more competitive
environment has required market participants to explore new
approaches to the use of storage facilities, develop new
services, and propose substantial additions to existing storage
capacity, Some of the trends and new developments within
the storage industry include:

© More emphasis on inventory management. Under
the separate pricing of storage services and the
existence of a futures market, the cost and dollar value
of storage services and the need to minimize the price
risk of holding gas in storage are receiving individual
attention for the first time. Inventory management is
receiving greater attention, with increased injection
and withdrawal activities throughout the year.

© Surge in new storage construction, particularly
high-deliverability salt cavern facilities. Since 1989,
the ability to deliver gas from storage has increased by
nearly 10 percent. More than one-third of the 21
existing salt cavern storage operations have been
brought on line since 1991, adding 29 billion cubic
feet (Bcf) of working gas capacity and 3.1 Bef per day
of deliverability—increases of 55 and 81 percent,
respectively, for this reservoir type. This development
is, in part, a response to the overall growth in
individual customer transactions, the increased chances
of system imbalances because of the variety of
transportation arrangements, and the need for a quick-
response mechanism to manage operations.

e Interest in market-based rates. Several companies
have asked the Federal Energy Regulatory
Commission (FERC) to consider market-based rates
for storage services from new as well as existing
storage facilities. To date only a few requests have
been allowed. The applicant must demonstrate a lack
of market power, and this can be difficult except for
those relatively smaller facilities in areas where
substantial storage options are already available. The
spread of market-based rates within the industry may
depend in large measure on the markets for released
transportation and storage capacity—two key elements
of Order 636.

© Development of a secondary market for storage
capacity. As with firm transportation capacity, Order
636 requires interstate storage operators to allow their
customers to release or sublet unused firm storage

capacity to third-party shippers. In the secondary
market, owners of unwanted storage capacity have an
economic incentive to sell or release the capacity to
help defray at least a portion of the cost of reserving
capacity. Unneeded capacity that is not resold has no
economic value. Very few storage releases have
occurred since the implementation of Order 636 in
November 1993, perhaps because shippers are
reluctant to sell their storage capacity rights until they
gain more experience directly managing their systems.
It may also be that storage capacity is being rebundled
with natural gas and transportation service and sold in
the "gray market."

This chapter discusses these new developments, paying
particular attention to increased storage utilization and plans
for new storage capacity. It should be noted that accounting
changes by several major storage operators in 1992 and 1993
have resulted in reclassification of base gas levels (see
Appendix C). To simplify comparisons of storage operations
between years, historical working gas data presented in this
chapter have been revised to reflect the current base gas
classification.

Inventory Management

Large amounts of interstate storage capacity were opened to
transportation customers when Order 636 provisions were
fully implemented on November 1, 1993. However, even
before implementation of Order 636, the percentage of
working gas in storage owned by interstate pipeline
companies had been declining steadily. The percentage of
total working gas in interstate storage owned by storage
operators at the start of the heating season fell from 73
percent in 1986 to 46 percent in 1993 (Figure 17).”* Under
their Order 636 restructuring filings, interstate storage
operators were allowed to retain some of their working gas

The gray market includes all transactions involving unneeded firm
interstate transportation or storage capacity that avoid the capacity release
posting requirements specified in FERC Order 636. See Philip M. Marston,
"The Rumble of Bundles: A Review of Experience Under the Capacity
Release Experiment" (Hadson Gas Systems, Inc., August 1994). Many of
these transactions involve pre-Order 636 buy-sell agreements that are
exempt from the capacity release program, See the “Storage Capacity
Release” section in this chapter for more discussion.

21993 is the last year for which the EIA-191, "Underground Gas Storage
Report" survey collected this information.

Energy Information Administration 25
The Value of Underground Storage in Today's Natura! Gas Industry



Table B3. Proposed Underground Storage by State, 1994-1999 (Continued)

Capacity Capacity
{billion cubic feet) (MMcf per day)
Working Total Cost
Project Name/State Total Base Gas Gas Withdrawal —_ Injection (Thousand $)
JEFFERSON ISLAND 470 1.70 3.00 300 150 so
JENNINGS SALT DOME 6.00 1.90 4.10 4200 150 $56,000
LA-1 PHASE 3, 4 6.20 2.20 4.00 400 200 $18,000
LA+t PHASE 5,6 6.20 2.20 4,00 400 200 $12,000
LA-V/EGAN PHASE 1,2 6.70 2.20 450 400 150 $37,000
NAPOLEONVILLE PHASE 1 8.30 3.70 460 400 200 $45,000
NAPOLEONVILLE PHASE 2 10.00 3.00 7.00 600 300 $33,750
OUACHITA RIVER 40.50 13.50 27.00 550 250 $80,000
SULPHUR MINES 13.55 5.55 8.00 400 150 $65,000
TOTALS: Projects = 11 174.15 65.95 108,20 5,400 2,223 446,750
MICHIGAN
GRANDS LACS 3.00 0.00 3.00 150 0 $100,000
KALKASKA 30 22.00 5.00 17.00 200 150 $50,000
LEE 8 3,80 3.80 0.00 0 0 $0
LIVINGSTON EXPANSION 0.80 0.00 0.80 o 0 $1,000
WASHINGTON TOWNSHIP 42.00 42.00 0.00 800 0 $120,000
TOTALS: Projects = 5 71.60 50,80 20.80 4,150 150 271,000
MINNESOTA
WATERVILLE-WASECA 2.00 0.80 4.20 o ° $2,000
TOTALS: Projects = 1 2.00 0.80 1.20 0 0 $2,000
MISSISSIPPI
EMINENCE EXP PHASE 2 4.64 1.72 2.92 200 0 $10,152
EMINENCE EXP PHASE 2 4.84 472 292 0 0 $10,152
HATTIESBURG PHASE 2 3.16 0.96 2.20 220 40 $20,000
MS-1 PHASE 1,2 4.20 1.20 3.00 300 280 $80,000
MS-1 PHASE 3, 4 4.20 1.20 3.00 300 0 $25,000
MS-1 PHASE 5 4.20 1.20 3.00 300 280 $15,000
PETAL 5.00 1.80 3.20 320 160 $30,000
TOTALS; Projects =7 30.04 9.80 20.24 1,640 760 170,304
MONTANA
BAKER EXPANSION 0.00 0.00 0.00 40 20 $7,312
TOTALS: Projects = 1 0.00 0.00 0.00 40 20 $7,312
NEW YORK
AVOCA PHASE 1 2.96 0.96 2.00 320 160 $49,000
AVOCA PHASE 2 2.30 0.30 2.00 100 50 $5,600
AVOCA PHASE 3 1.24 0.24 4.00 80 40 $4,600
CAYUTA PHASE 1 4,00 0.80 3.20 320 160 $42,000
CAYUTA PHASE 2 2.60 0.50 2.00 100 50 $6,600
CAYUTA PHASE 3 1.30 0.30 1.00 80 40 $6,600
LAUREL FIELDS-ALLEGANY 18.30 9.30 6.00 60 40 $48,600
SENECA LAKE 0.80 0.00 0.80 80 20 $59,000
THOMAS CORNERS 7.70 2.70 5.00 50 33 $28,000
WATKINS GLEN 2.00 0.00 2.00 200 a so
TOTALS: Projects = 10 40.10 15.10 25.00 1,390 593 250,000

Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry

65

aan

Ter TT



Figure 17. As Order 636 Takes Effect, Storage Volumes Owned by Interstate Pipeline Companies

Continue to Decline

100 —
well LDC Storage
BS Pt tee eee
a ee
3 80 4
<
2
on
29
é 3 60 Interstate Storage
Es
©
Ee
S
8 40 4
‘62
par)
<
2
2
2 20-4
te}

T T T T
1986 1987 1988 1989

T T T T
1990 1991 4992 1993

Beginning of Heating Season (November 1)

LDC = Local distribution company.
Note: Order 636 became effective on November 1, 1993.

Source: 1986-1990: Energy Information Administration, EIA-191/FERC-8, "Underground Gas Storage Report." 1991-November 1, 1993:
Energy Information Administration, EIA-191, "Underground Gas Storage Report."

capacity to meet their system requirements for load balancing,
system management, and providing "no-notice" service.””

As customers have increasingly taken responsibility for
contracting for storage services, thereby managing the costs
associated with storage use, inventory management practices
have changed. During the period from 1989 through 1993,
storage utilization per field increased significantly in
comparison with the 5-year period from 1982 through 1986
(Table 1). The earlier period reflects the natural gas industry
under its "old," highly regulated structure, whereas the later
period represents the industry well in transition toward
deregulation of most aspects of its operations. By 1989 the
effects of Order 436 (open-access transportation programs)
were well incorporated into industry operations, and by 1991
the industry was anticipating Order 636.

In comparison with the earlier period, average injection and
withdrawal activities per field uniformly increased during the
period from 1989 through 1993. This trend held true for
nonheating seasons, heating seasons, and heating years alike.

*No-notice transportation service allows shippers to receive delivery on
demand, up to their firm entitlements, without incurring penalties.

The increase in monthly average activity levels was
substantial. Injection activity during the nonheating season
increased by 20 percent while withdrawals increased by 47
percent. Monthly withdrawals during the heating season were
up by 11 percent. This upward shift in withdrawal activity is
visually evident in the middle graph of Figure 18, which
shows heating season withdrawals after adjusting for weather.

In addition to this trend toward greater injection and
withdrawal activity, working gas inventory levels at the
beginning of the heating season (November 1) drifted
progressively lower from 1990 to 1993—from 3.5 trillion
cubic feet (Tcf) in 1990 to 3.0 Tef in 1993.* Working gas
inventories at the end of the heating season also dropped
significantly in 1992, 1993, and 1994, both in volume and as
a percentage of working gas capacity. Between 1985 and
1991, end-of-season inventories ranged from 32 to 43 percent
of capacity. In 1992, inventories were 32 percent of capacity
and after the severe weather in 1993 and 1994 dropped to 24
percent and 26 percent, respectively.

Energy Information Administration, Natural Gas Monthly, DOE/ELA-
0130(92/02) (Washington, DC, February 1992), Table 17; and Natural Gas
Monthly, DOEJEIA-0130(94/12) (Washington, DC, December 1994),
Table 13.

26 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Appendix A

Underground Natural
Gas Storage
Operations



Figure 9.
2.40 5
2.20 4
2.00 4
3
Qa
e 1.804
8s
3
Q 1.60 -
o
2
a 1.404
3.
a
® 4.204
2
$
x=
> 1.004
€
By
F 0.00 1

Spot Prices Decline When More Storage Is Available for Deliveries

Trend Line

T T T T
2.60 2.80 3.00

T T T
3.20 3.40 3.60 3.80

Total Gas in Storage/Expected Deliveries

Notes: The ratio of total storage to expected deliveries is end-of-month storage divided by the previous year’s total consumption for the
next month. Thus, total storage data are end-of-month for January through March, 1991 through 1994, while expected deliveries are
consumption for February through April, 1990 through 1993, Spot prices are the average negotiated prior to delivery for the next month and
are thus beginning-of-month for February through April, 1991 through 1994. The Trend Line is the result of a least-squares regression.

Sources: Regression Results: Energy Information Administration (EIA), Office of Oil and Gas: derived from: Storage and Expected
Deliveries—EIA, Natural Gas Monthly, various issues; and Spot Prices—inside F.E.R.C.'s Gas Market Report, various issues.

The magnitude of the premium is an indication of the increase
in the value of gas at the Henry Hub. However, because a
large amount of gas moves through the Henry Hub on a daily
basis and because changes in price at other locations tend to
be correlated with changes in price at the Henry Hub, the
estimated premium is a useful indication of the premium
received for stored gas overall and at other locations
experiencing similar demands for gas.

After January 22 when warmer weather prevailed, the
difference in the two series turned toward zero and negative
values. However, when another blast of frigid temperatures
was forecasted, spot prices rose significantly, and the
premium peaked at $1.12 per MMBtu on February 2.
Thereafter, the premium was not much different from zero
during most days through April 23, and as expected was
negative when the temperature returned to near normal levels.

During periods of stress caused by sudden declines in
temperature, the premium can be expected to rise. In fact,
profits approximating the premium could be obtained by
owners of stored gas who do not need the gas for their own
current needs. Such a circumstance may be unusual, but if
owners find buyers with sufficient pipeline capacity they
could sell the gas from storage at the prevailing spot price
nearest their storage location. That price could be above or
below the average price for the day reported at the Henry
Hub. Owners could then replace the gas sold with gas
purchased under a futures contract at the lower futures price."
If a sufficient volume of gas were traded in this manner, it
would have the effect of lowering spot prices and raising
futures prices, moving the two series into closer balance,

profits may also be made when the futures price is higher than the spot
price, although the process is a bit more complicated. As an example, a party
could borrow money to buy gas at the lower spot price, pay for storing it,
and sell the gas under a futures contract at the higher futures price. A party
would do this only if the futures price exceeded not only the cost of the gas,
but also the interest cost on the money borrowed, and the cost of storing the
gas until the future delivery date.

14 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Figure A1.

Ne,

aD

on

Illustration of the Various Types of Underground Storage

‘ Underground Storage In:

A Salt Caverns

B_ Mines

C Aquifers

D Depleted Reservoir
E  Hard-rock Caverns

Source: PB-KBB Inc., “Underground Storage and Subsurface Systems”: Recreated by Energy Information Administration, Office of Planning,

Management, and Information Services.

Most of the Nation's storage sites were developed between
1955 and the early 1980's. During this period, U.S. storage
capacity increased over fourfold, from about 2.1 trillion cubic
feet (Tcf) in 1955 to 8 Tef in 1985. The need for
underground storage grew as consumption of natural gas
increased significantly. The mix and requirements of
consumers also changed as demand shifted toward the more
weather-sensitive residential and commercial markets.
Furthermore, in the mid- and late-1970's, the interstate market
encountered supply and demand imbalance situations during
several exceptionally cold winters, and as a result service
curtailments were imposed.

The sporadic inability of the industry during the winter
months to meet large and sudden increases in demand for
natural gas in some areas helped stimulate the planning and
construction of new storage. Increased storage development
was seen by regulators and industry alike as necessary to
avoid a repeat of such occurrences and also to satisfy
expected increases in gas demand during the 1980's.

“American Gas Association, Gas Facts: 1979 Data (Arlington, VA,
1979); and Energy Information Administration, Natural Gas Monthly,
February 1991, DOE/EIA-0130(91/02) (Washington, DC, February 1991).

Since the mid-1980's, total storage capacity has remained at
approximately 8 Tcf, even with the recent surge in new
storage development. (Some new sites have been added but
some have also been abandoned.) However, the daily
deliverability from storage has increased. The volatile gas
market during the late 1980's set in motion certain events that
heightened interest in new storage facility development.
Interest in new storage resurged as regulatory changes under
Federal Energy Regulatory Commission (FERC) Orders 436
and 636 forced more competition into the marketplace.
Storage became increasingly important as all pipeline services
were unbundled and customers had to make their own storage
arrangements. These changes led to increased interest in
development of storage sites that would provide greater
deliverability and more access to working gas capacity.
Between 1992 and 1994, deliverability from storage increased
by 5 percent, from approximately 65 Bef per day*’ to 68 Bef
per day (Table Al).

“Energy Information Administration, Natural Gas 1992: Issues and
Trends, DOEIEIA-0560(92) (Washington, DC, March 1993), Table 12,
p. 87.

44 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Figure A5. Propane Underground Storage Cavern

TM.

Source: PB-KBB Inc. (Houston,

53

Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



DISCLAIMER

Portions of this document may be illegible
in electronic image products. Images are
produced from the best available original

document.



On the other hand, the terms "inactive" and "standby," at least
as used here, do not refer to any officially-sanctioned status.
The intended meanings of these terms were implied through
their use by storage operators in conversations about their
operations, Thus, for purposes of this discussion, an inactive
field is tantamount to being abandoned. The operator has
removed or is removing all working gas and, usually, is
recovering or will attempt to recover all base gas for which
recovery is economical. The operator is doing virtually no
maintenance on the field. In some cases, operators with
inactive fields have already filed, or intend to file, the
necessary paperwork for official abandonment, but this is not
always the case. Some operators have indicated that they will
merely leave the fields in an inactive state for an unspecified
period of time.

Standby fields are those that are not actively in use, but are
being maintained and can be brought back into service in a
relatively short period of time. Usually, the operator has
withdrawn or is withdrawing all working gas, but base gas is
being left in place.

Of the 29 storage sites taken out of service from 1990 through
1993, at least 13, and perhaps as many as 21, have been or are
being depleted and will be abandoned or left inactive. Most of
the 21 are considered by their owners to be uneconomical to
operate in today's marketplace without incurring a major
workover expense; a few are inactive because continued
operation would raise safety concerns. The remaining 8 of the
29 sites are classified as standby by their operators; that is,
they contain no working gas, and, other than withdrawing
remaining recoverable gas or operations to maintain standby
status, minimal activity has been reported. All but 2 of the 29
deactivated sites are depleted gas/oil reservoirs, with the
others aquifer sites. For the most part, they are small fields.
Nine are located in the Northeast, seven in the Midwest, six
in the Southwest, and four in the Central Region. Two are
located in Kentucky (Southeast) and one in California
(Western).

A close examination of the types of storage fields that have
been taken out of service tends to show how, with the growth
of open access storage and increased need by operators to
market storage services, marginal and poorly located storage
may be falling victim to economics and a changing market
environment. Some of the reasons given for inactivating or
abandoning particular storage sites are:

© Need major workovers; leaking casings, seepage, etc.
(four sites)

© Too small a field to support itself (four sites)

© Substantial migration losses (three sites)”

e Safety (three sites)

© Located at nonstrategic place on system (two sites)
© Loss of a key and only client (one site).

In total, since the early 1970's, as many as 82 storage facilities
in the United States have been officially abandoned, classified
as standby, or are simply no longer being used.” However,
their daily deliverability is only 1.8 percent of total storage
deliverability in 1994. In contrast, the new sites brought into
service from 1990 through 1993 increased daily deliverability
by 9.2 percent (5,694 million cubic feet).

It appears then that new underground storage development
has not created a surplus of storage capacity, at least for now,
as some have argued. New storage capacity has not displaced
existing capacity; rather, it has been the marketplace that has
culled the marginal operations from the Nation's storage
inventory. Also, it is worth noting that standby sites, as well
as a number of the inactive sites, have not been totally
abandoned and could be reactivated in the future.

The Emphasis on Salt Cavern
and Other High-Deliverability
Storage

Another new characteristic of the storage market is the
increasing reliance on salt cavern storage. Most salt cavern
facilities are designed with the intent of cycling the entire
working gas capacity 5 to 10 times each year. Typical
injection periods are in the range of 20 days. In contrast, more
traditional storage, such as storage in depleted reservoirs, is

2 Migration is the subsurface movement of oil, gas, or water through
porous and peimeable rock. Migration losses occur when gas molecules find
pathways beyond the confines of the storage reservoir's cap rock (the
generally impermeable layer that halts upward migration of gas). Such losses
are usually because of the geologic configuration of the reservoir but may
be intensified by man-made development activities or reservoir operating
procedures,

*This count of abandoned fields has been developed from information
provided by respondents to EIA-191, “Underground Gas Storage Report,
analysis of EIA-191 data, and from various published sources. The
abandoned fields list may involve some double-counting because of
ambiguities and inaccuracies in storage field identification, just as it may
also exclude some abandoned fields for which no information is available.

Energy Information Administration 33
The Value of Underground Storage in Today's Natural Gas Industry



Table 2, Proposed New and Expansion Underground Storage Projects in the United States, 1994-1999

Number of
Projects |Additions to | Additions to |Total Additions | Additions to} Additions to

Base Gas | Working Gas to Storage | Withdrawal Injection
Type of Project 7 Capacity | Capacity Capacity | Capacity | Capacity
New |FXPATM| Tota | (Bet (Bch) (Bcf) (MiMctid) (MMct/d)
Depleted Fields .. 24 7 3 253 322 575 6,521 3,124
Aquifers, ......... 1 2 3 9 9 19 110 45

Salt Caverns®
Salt Domes .... 0 13 15 28 49 103 152 8,905 3,245
Salt Beds .... se 9 10 49 16 61 77 5,210 1,390
Total Salt Formations... 22 25 47 65 164 230 14,115 4,635
Total Projects” 47 34 81 328 495 824 20,746 7,804

Salt caver storage is prepared by injecting water (leaching) into a salt formation (either a salt bed or salt dome) and shaping a cavern. Salt
beds are more expensive to develop than salt domes because in general they are thinner formations (about 1,000-feet thick vs. up to 30,000 feet),
which makes them more susceptible to deterioration.

Pannounced as of February 28, 1994.

Bef = Billion cubic feet. MMcffd = Million cubic feet per day.

Note: Two liquefied natural gas storage projects (one new, one expansion) have also been proposed, which would add 4 Bcf working gas
capacity, 1,000 MMcf/d withdrawal capacity, and 15 MMcf/d injection capacity. Totals may not equal sum of components because of independent
rounding.

Source: Energy Information Administration, Office of Oil and Gas, "Proposed Natural Gas Storage Projects," data base as of October 31,
1994, based on Federal Energy Regulatory Commission filings and information from various industry news sources.

Figure 20. Independent Operators Are Projected to Play a Larger Role in Storage by the End of the Decade

7} Working Gas Capacity
Interstate Pipelines TERT ERT
LDC's
Independents/Others 1994
Il i999
7 Deliverability
Interstate Pipelines
LDC's
Independents/Others
T 1
60 80

Percent

LDC's = Local distribution companies,

Sources: Energy Information Administration (EIA). 1994: EIA-191, "Underground Gas Storage Report." 1999: Office of Oil and Gas,
“Proposed Natural Gas Storage Projects," data base as of October 31, 1994, based on Federal Energy Regulatory Commission filings and
information from various industry news sources.

Energy Information Administration 34
The Value of Underground Storage in Today's Natural Gas Industry





1. Importance of Storage in the Gas Industry

Underground storage is a vital part of the natural gas industry.
The ability to store gas ensures supply reliability during
periods of heavy demand by supplementing pipeline capacity
and serving as backup supply in case of an interruption in
wellhead production. Storage also allows load balancing of
daily throughput levels on pipelines, which is necessary to
ensure smooth operation of the pipeline system. Moreover, it
enables greater system efficiency: instead of satisfying winter
demand by adding new production facilities, the industry can
place gas in storage during the summer and thus maintain
production at a much more constant level throughout the year.
A relatively recent development in the use of storage is to
manage inventory levels to take advantage of expected price
movements and to support futures market trading.

The cost of storage services can significantly influence what
customers pay for gas, both at the wellhead and at the
citygate. For those customers requiring storage services, these
services can easily add a dollar per thousand cubic feet or
more to the price of gas.' On a daily basis, the amount of gas
in storage in comparison with planned levels can affect the
current price of gas at the wellhead. Over the longer term, the
availability of storage gas in market areas allows more
efficient use of the pipeline system, which ultimately results
in lower gas prices than would be possible without storage.

Storage activity and price are strongly affected by weather,
which is a key factor in the annual planning cycle that
companies undertake to ensure that adequate supplies are
available to meet customer requirements. The industry injects
large amounts of gas into underground storage reservoirs
from April through October. During these months, gas
demand declines as temperatures turn milder and space-
heating needs subside. Thus the large interstate pipelines have
additional space available for shipping gas to underground
storage reservoirs.

During the heating season, the industry combines supplies
from the producing regions, including imported supplies, with
supplies from underground storage to meet most customer
demands, In addition, the industry operates peaking facilities,
such as propane-air plants, in market areas to fulfill unusual
peaks in consumption or to offset a temporary interruption in
supplies.

"Energy Information Administration, Natural Gas 1994: Issues and
Trends, DOE/EIA-0560(94) (Washington, DC, July 1994), p. 67.

The industry currently has the capability to store
approximately 8 trillion cubic feet (Tcf) of natural gas in
375 storage sites around the country (Figure 1). Of this, about
46 percent (3.7 Tcf) is considered working gas storage that
can be withdrawn as necessary (see box, p. 3). On a peak day,
the industry has the capability to deliver more than 120 billion
cubic feet of natural gas to consumers,’ and underground
storage can supply as much as half of this demand. To meet
the substantial heating load in the Northeast and Midwest,
more than half of the country's working gas capacity is
located east of the Mississippi River. Approximately 28
percent is located in the major producing region, whereas
only 16 percent is located in the West where much of the
population lives in areas with relatively moderate climate
(Figure 1).

In the longer term, storage activity is also influenced by
institutional arrangements, such as who owns the gas in
storage, who has rights to use the storage facility, and the
possibility of trading these rights. Regulatory changes
initiated in the mid-1980's have transformed the once highly
regulated industry to one in which competitive factors
dominate the market. These regulatory changes have
significantly affected storage operations and the type of
storage facilities being put in place. In particular, Federal
Energy Regulatory Commission (FERC) Order 636 mandated
that by 1993 (1) storage service be unbundled, that is, offered
as a distinct service, separately charged and itemized, (2)
customers be offered greater access to underground storage
capacity or the right to use space in storage reservoirs, and (3)
customers be given the opportunity to sublease any of their
contracted storage capacity. With customers now responsible
for developing their own contract services and arrangements,
storage has become much more important in the daily
business operations of all industry sectors.

During its first heating season under the new, less regulated,
“open-access” environment, the industry was tested by
extreme weather conditions in January 1994, which prompted
near-record storage withdrawals (see box, p. 4). The extensive
storage capability in market areas, combined with more
operational and contractual flexibility, allowed sufficient gas
to flow to meet record monthly consumption levels.

*The 120 billion cubic feet per day refers to the physical capability of the
industry to deliver gas. It is a measure of the peak-day design capacity of the
entire system, including pipeline, storage, and peak-shaving facilities.
National Petroleum Council, The Potential for Natural Gas in the Unued
States: Transmission and Storage (Washington, DC, December 1992).

3Based on an estimate of deliverability from storage of 68 billion cubic
feet per day (Table 4, Chapter 3).

Energy information Administration 1
The Value of Underground Storage in Today's Natural Gas Industry



Appendix A

Underground Natural Gas Storage Operations

This appendix presents a brief perspective on various types of
underground natural gas storage operations in the United
States today. It includes a discussion of the types of
companies that own storage, the types of facilities used in
storage operations, the characteristics of each, and how each
type is integrated into daily operations of mainline and local
distribution systems. It also includes a brief discussion of
alternative natural gas storage mediums such as liquefied
natural gas and propane-air facilities, which are used to meet
temporary demand spikes for natural gas service.”

Overview

Underground storage, in common usage, is gas transferred
from the reservoir of discovery to other reservoirs, usually
closer to market areas, where it is stored until needed to meet
market demand. Natural gas is stored in underground
reservoirs (Figure Al) primarily to ensure the capability of
the gas industry to meet seasonal fluctuations in demand.
Underground storage supplements the industry's production
and delivery systems, allowing supply reliability during
periods of heavy gas demand by residential and commercial
consumers for space heating. Storage is also used
occasionally as a conservation measure to prevent flaring and
other waste when production rates exceed marketability.

The three principal types of underground storage sites used in
the United States today are: (1} depleted reservoirs in oil
and/or gas fields, (2) aquifers, and (3) salt cavern formations.
Each type has its own physical characteristics (porosity,
permeability, retention capability) and economics (site
preparation costs, deliverability rates, cycling capability),
which governs its suitability to particular applications.

The most important characteristic of an underground storage
reservoir is its capability to hold natural gas for future

“For detailed engineering and technical information regarding
underground storage of natural gas, see Gas Engineers Handbook: Fuel Gas
Engineering Practices (New York: Industrial Press Inc., 1974); and Donald
L. Katz and others, Handbook of Natural Gas Engineering (New York:
McGraw-Hill Book Company). For general historical information on the
early gas storage industry, see American Gas Association, Inc., The
Underground Storage of Gas in the United States and Canada, 19th Annual
Report on Statistics, X54170 (December 31, 1969).

delivery. The measure of this is catled working gas capacity:
the amount of natural gas inventory that can be withdrawn to
serve customer needs. In addition to working (top storage)
gas, underground storage reservoirs also contain base
(cushion) gas and, in the case of depleted oil and/or gas field
reservoirs, native gas. Native gas is the gas that remains after
economic production ceases and before conversion to use as
a storage site. Upon development of a storage site, additional
gas is injected and combined with any existing native gas in
order to develop and maintain adequate storage reservoir
pressure to meet required deliverability rates. The resulting
(permanent) inventory is referred to as the base or cushion
load. During heavy demand periods, some base gas may be
withdrawn temporarily and delivered as working gas, but over
the long term, base levels must be maintained to ensure
operational capability.

Relatively small quantities of gas are stored as liquefied
natural gas (LNG) in specially constructed insulated
containers, and small volumes of compressed gas are stored
in tanks commonly referred to as gas holders. For short
periods the pipes themselves are used for storage by
compressing more gas into the same space; this is called line
packing. Peak demands (peaking service) are also met by
synthetic gas or propane and other natural gas liquids.

In 1915, natural gas was first successfully stored underground
in Welland County, Ontario, Canada. Several wells in a
partially depleted gas field were reconditioned. Subsequently,
gas was injected into the reservoir and withdrawn the
following winter. In the United States, in 1916, Iroquois Gas
Company placed the Zoar field, south of Buffalo, New York,
into operation as a storage site. In 1919, the Central Kentucky
Natural Gas Company repressured the depleted Menifee gas
field in Kentucky. By 1930, nine storage pools in six different
States were in operation with a total capacity of about 18
billion cubic feet. Before 1950, essentially all gas storage was
in partially or fully depleted gas reservoirs.

In some areas of the country, particularly the Midwest,
suitable depleted gas/oil fields were unavailable for potential
conversion to storage fields. As a result, the concept of using
an aquifer formation for storage was tested and developed.
Although the testing was done in the 1930's, it was not until
the early 1950's that attention was turned to the use of
aquifers for storing natural gas.

Energy Information Administration 43
The Value of Underground Storage in Today's Natural Gas Industry



Figure A3. Typical Configuration of Aquifer Storage

Meters beneath
the surface

ot

4000.

Diagrammatic cross section

of an aquifer storage

reservoir:

1. Aquifer. Porous, 8. Deviated well.
permeable layer 9. Upper aquifer
(reservoir). observation well.

2. Impermeable cap rock, 10. Peripherat

3. Upper control aquifer. observation well.

4.Gas, 11. Water level

5.Water, monitoring well,
6.Strainers, 12, Water level

7. Operating well. gas/water

interface.

18, Neutron logging
well,

F. Closure,

1c

Source: Gaz de France, "Underground Storages Facilities" (June 1992): Recreated by Energy Information Administration, Office of Planning,

Management, and Information Services.

operation today were developed when the market price for
natural gas was very low. In today's market, developing
aquifer storage can be a very expensive undertaking.

Aquifer storage deliverability during the heating season is
designed around specific customer requirements. These
requirements may be for deliveries over a set period of time,
for instance, 20, 60, or 120 days. The overall facility design
reflects these combined requirements. These requirements
also delimit the degree of cycling, that is, the number of times
total working levels may be depleted and replenished during
a heating season, that may occur at an aquifer site. The
sustained delivery rate cannot exceed design limits.
Otherwise, unlike depleted oil and gas reservoir storage where
cushion gas can be tapped when needed, tapping cushion gas
in an aquifer storage site can have an adverse effect upon
reservoir performance,

Lastly, and perhaps the most important constraint on the
future use of aquifer formations for natural gas storage, is the

environmental qualifier. In the early 1980's, the U.S.
Environmental Protection Agency (EPA) issued regulations
that tightly restrict the future development of aquifer storage
in an effort to avoid further or potential contamination of
available water supplies. A permit for aquifer storage will be
issued only if the potential site has salinization levels that
make the water unusable for drinking or most agricultural
purposes. Additional restrictions also apply.

Salt Formations

Salt formations have several properties that make them ideal
for storing natural gas. A salt cavern is virtually impermeable
to gas and once formed, a salt reservoir's walls have the
structural strength of steel. Thus, gas cannot easily escape the
large hollowed-out shape that forms a salt storage cavern
(Figure A4).

Energy Information Administration 49
The Value of Underground Storage in Today's Natural Gas Industry



temperature of 60 degrees Fahrenheit.

Storage Measures

Several measures are used throughout the report to assess the capability of the industry to deliver gas from storage at any point
in time, They are usually expressed as volumes of gas and are normally reported at a pressure base of 14.73 psia and a

Total capacity is the maximum volume of gas that can be stored in an underground storage facility and is
determined by the physical characteristics of the reservoir. For storage facilities under the jurisdiction of the Federal
Energy Regulatory Commission, a facility's "certificated capacity" and total capacity are one and the same.

Base gas (or cushion gas) is the volume of gas needed as permanent inventory in a storage reservoir to maintain
adequate pressure and deliverability rates throughout the withdrawal season. The amount of base gas required in a
reservoir depends on how the operator intends to operate or manage the storage facility.

Working gas capacity is total capacity minus base gas.

Working gas is the volume of gas in the reservoir above the designed level of the base gas. It is gas that is
temporarily stored in a reservoir with the express purpose of being withdrawn at a future date, usually (in the case
of baseload facilities) during the heating season. The amount of working gas is always less than or equal to working
gas capacity.

Deliverability is a measure of the amount of gas that can be delivered from a storage facility in a given length of
time, Also referred to as the deliverability rate, withdrawal rate, or withdrawal capacity, deliverability is most often
measured in terms of million cubic feet per day. The deliverability of a given storage facility is variable, and depends
on factors such as the amount of gas in the reservoir at any particular time, which dictates the pressure within the
reservoir, compression capability available to the reservoir, the configuration and capabilities of surface facilities
associated with the reservoir, and other factors. In general, a facility's deliverability rate varies directly with the
amount of working gas in the reservoir: it is at its highest when the reservoir is most full and declines as working

gas is withdrawn.

Recent restructuring of the gas industry has been influenced
not only by changes in regulation by FERC and other
regulatory bodies, but also by the development of new
markets. In particular, the natural gas futures market has led
to new sectors of the gas industry and to new ways certain
sectors conduct their business. Marketing companies, the
major growth sector in the gas industry in the past 10 years,
use the futures market as a means of establishing the price for
mid-term contracts and as a means to hedge price risk for both
short-term and mid-term supply contracts.* The futures
market can also be used to hedge the price risk associated
with having gas in storage.

This report discusses the important role of storage in the
natural gas market and how it affects the production,
transmission, and pricing of natural gas. This chapter

“Energy Information Administration, Natural Gas 1994: Issues and
Trends, DOE/EIA-0560(94) (Washington, DC, July 1994).

highlights the unique qualities of natural gas as a commodity
and how the ability to store gas adds value. Chapter 2
examines the short-term characteristics of the market,
specifically the relationship between storage and price relative
to expected storage levels and weather, using some daily data
from the severe cold spell of January 1994. This attention to
daily data brings into focus important issues, such as short-
term shifts in price, that would otherwise be obscured.
Chapter 3 addresses the longer term aspects of the market,
discussing how the regulatory and market changes during the
past few years have affected storage operations and the type
of storage facilities being put in place. In particular, it
highlights the increasing role of salt cavern storage facilities,
the status of market-based rates for storage, and the
development of a secondary market for storage capacity.

Energy Information Administration 3
The Value of Underground Storage in Today's Natural Gas Industry



DISCLAIMER

This report was prepared as an account of work sponsored
by an agency of the United States Government. Neither the
United States Government nor any agency thereof, nor any
of their employees, make any warranty, express or implied,
or assumes any legal liability or responsibility for the
accuracy, completeness, or usefulness of any information,
apparatus, product, or process disclosed, or represents that
its use would not infringe privately owned rights. Reference
herein to any specific commercial product, process, or
service by trade name, trademark, manufacturer, or
otherwise does not necessarily constitute or imply its
endorsement, recommendation, or favoring by the United
States Government or any agency thereof. The views and
opinions of authors expressed herein do not necessarily
state or reflect those of the United States Government or
any agency thereof.





Table B3. Proposed Underground Storage by State, 1994-1999 (Continued)

Expansion FERC
Year in Project? Docket Reservoir
Project Name/State Operator County Service (X=Yes) Number Type
OKLAHOMA
MANCHESTER WILLIAMS BROTHERS GRANT 1995 DEPL FIELD
ENGINEERING
OKFUSKEE UNIGAS CORP OKFUSKEE 1994 DEPL FIELD
PENNSYLVANIA
LAUREL FIELDS-CALLEN RUN NATIONAL FUEL GAS JEFFERSON 1996 CP90-2086 = DEPL FIELO
RIVERSIDE RIVERSIDE GAS, GREENE 1995 CP94-292 DEPL FIELD
STORAGE
TEXAS
ATKINSON GAS STORAGE KEBO OIL LIVE OAK 1994 DEPL FIELD
BETHEL PHASE 3 LONE STAR GAS ANDERSON 1995 x SALT DOME
HILBIG LOWER COLO. RIVER BASTROP 1994 DEPL FIELD
AUTH
LOOP PHASE 2 AMERICAN GAS GAINES 1994 x SALT BED
STORAGE
LOOP PHASE 3 AMERICAN GAS GAINES 1995 x SALT BED
STORAGE
MARKHAM (CAVERN #2) COASTLINE(UTTCO) MATAGORDA 1994 x SALT DOME
MOSS BLUFF PHASE 3 ‘TEJAS POWER CORP LIBERTY 1995 x SALT DOME
NICHOLS STATION PLANT SW PUBLIC SERVICE 1994 SALT DOME
NORTH FELMAG AMERICAN GAS, GAINES 1994 DEPL FIELO
STORAGE
SALADO GAS STORAGE AMERICAN GAS GAINES 1994 SALT BED
STORAGE
SPINDLETOP SABINE GAS JEFFERSON 1995 x SALT DOME
(SABINE-CAVERN ‘TRANSMISSION
SPINDLETOP SABINE GAS JEFFERSON 1994 x SALT DOME
SABINE-CAVERN ‘TRANSMISSION
SPINDLETOP (WINNIE P L) WINNIE PIPELINE JEFFERSON 1997 x SALT DOME
STRATTON RIDGE (AMOCO) — AMOCO BRAZORIA 1994 x SALT DOME
STRATTON RIDGE (MG) MG STORAGE CORP BRAZORIA 1994 SALT DOME
UTAH
CLAY BASIN EXPANSION QUESTAR DAGGETT 1994 x CP93-408 —-DEPL FIELD
VIRGINIA
SALTVILLE TENNECO ENERGY SMYTH 1995 SALT DOME
RES/VIRGINIA
WYOMING
ELK BASIN RETROFIT WILLISTON BASIN PARK 1994 x CP93-283  DEPLFIELD

66

Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Figure 8.

Heating
4 Season

Heating
Season

2
2
8

2.50 +

2.00 4

1.50 4

1.00 +

Henry Hub Spot Price
(Dollars per Million Btu)

0.50 4

Heating
Season

Storage Levels and Spot Prices Are Not Clearly Related

Heating
Season

0.00 T
1990 1991 1992

Total Storage
(Trillion Cubic Feet)

1993 1994

T
1990 1991 ' 1992

1993 q 1994

Note: The heating season runs from November of one year through March of the next year. The price data are beginning-of-month prices
that apply to deliveries made during the month. The storage data are amounts of gas in storage available at the beginning of the month, but are
more typically reported as end-of-month levels. For example, the data shown here for November 1990 are reported in the data sources as the
price for (the beginning of) November 1$90 and the storage level for (the end of) October 1990.

Sources: Prices: McGraw-Hill, Inc., inside F.E.R.C.'s Gas Market Report. Storage: Energy Information Administration, Natural Gas Monthly,

various issues.

(November 1). Although fill rates are determined by the
operational characteristics of each facility, those who want to
store gas also have some leeway in determining how much gas
to inject each month. They balance their need to have gas in
storage by November | with the desire to buy gas when they
believe it is cheapest during the nonheating season.

The concept of how much gas must be in storage by certain
times in the nonheating season has been undergoing a
systematic change in recent years. For example, between 1990
and 1993, the percentage of working gas capacity that was
filled generally drifted lower. Then during 1994, the percentage
increased (see Chapter 3, Figure 19). This changing pattern
makes it particularly difficult to determine a simple relationship
between spot prices and storage levels from data for the
nonheating season.

During the heating season, however, there is much less
flexibility in the proportion of capacity that must remain filled

because winter weather creates space-heating demands that
require sufficient gas to be in storage, ready to meet customer
needs. Even during the heating season, however, the influence
of storage activity on price is expected to be minor in the
months of November and December because stocks of gas are
high relative to expected monthly deliveries.> By the end of
January though, large amounts of gas have been withdrawn
from storage. Because significant deliveries from storage will
still be required in subsequent months, storage is likely to be a
stronger component of spot price levels during the latter part of
the heating season.

"This may have changed somewhat as a result of Order 636. Contracts
now held by many local distribution companies (LDC's) for storage capacity
require the LDC to withdraw a certain amount of gas from storage each month,
If such withdrawals exceed the needs of the LDC's customers, the gas will
likely be sold on the spot market. This may have a depressing influence on
price even if it occurs in the months of November or December.

12 Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry





Incompletely Specified Behavioral Equation

Instead of using a robust estimator, another approach to determining an equation that better explains the behavior of PR is to
use a dummy variable for the outlying observations. The estimated magnitude for the dummy variable coefficient is an indicator
of the unexpected change in PR possible during a period of great price uncertainty. It is important to note that although the
dummy variable coefficient is estimated for two particular days, the estimated shift in the magnitude for the premium represented
by the magnitude of the coefficient could apply to any day during a period of great uncertainty on natural gas spot and futures
markets. It is also assumed, in this instance, that the distribution of the error terms is normal. The dummy variable represents all
influences on PR on February 2nd and 3rd that are not accounted for by the other variables in the equation. However, industry
perceptions probably account for a large part of these influences. The industry had passed through severely cold weather in mid-
January, experienced another dip in temperature at the end of January, and even though temperatures were rising in early
February, yet another cold blast was forecasted. Pipeline capacity was tight and spot prices had been volatile during January's
bid week in late January when most contracts for February deliveries are negotiated. Thus, the level of price uncertainty in the
industry was probably great. When the equation is estimated with a dummy variable for the February observations, the following
results are obtained (standard errors are reported in parenthesis):

PR, = 0.265 + 0.017DT, - 0.0080TP, + 0.81FEB 6
(0.051) (0.0026) (0.0029) (0.114)

R?= 0.761, n= 38, and the number of degrees of freedom = 34.

Summary of Estimated Results for Equations 5 and 6

The estimated magnitudes for the coefficients in equations 5 and 6 are similar in that the coefficients vary by less than a standard
error. Therefore, the estimated results do not appear to be sensitive to the choice of estimator. Equation 6, however, is used to
summarize the relationship between the price premium and the chosen variables. This choice is made because this estimation
explains more of the variability in PR, and because it also provides us with a useful estimate of the possible shift in the magnitude
of the price premium during a period of much uncertainty.

Evaluation of Estimated Results for Equation 6

An examination of the plots of the residuals from equation 6 against the predicted value of PR and against DT and TP (Figures D1
through D3) did not reveal any pattern, such as an increase or decrease in the magnitude of the residuals as the magnitude of the
explanatory variable or the predicted value of the premium increased. Thus, the assumption of the constancy of the variance of
the error terms appears to be satisfied.

To evaluate the independence of the error terms, the standard Durbin-Watson test was examined which yielded a value of 1.99,
strongly suggesting that the error terms one time period apart are independent. A runs test on the residuals was also examined.
There were 20 negative residuals and 19 positive residuals. With this number of positive and negative residuals, the expected
number of runs is 21 with a standard deviation of 3 runs. Since there are 18 runs in the residuals, the assumption of the
independence of the error terms appears to be satisfied by this test as well.

In previous econometric investigations of PR (usually adjusted for the cost of borrowing money or the cost of storage implicit
in the futures price) it was common to regress this variable on storage levels (S) to examine the degree to which the variable
increases when S declines, However, this approach is not appropriate for natural gas markets because storage levels are judged
to be low only when they are low relative to expected demand. For example, 1.8 Tef of gas can be considered very high for
March, placing downward pressure on prices, but very low for January, putting upward pressure on prices because the amount
of the demand that is expected to be satisfied from storage withdrawals is much higher for January than for March.

As a consequence of comments made by John Fenton of the Commodity Futures Commission (CFTC) (at a meeting of the
Washington Statistical Society on Tuesday, November 22, 1994) that a variable representing daily storage levels should be useful
for explaining PR, an additional equation was estimated as a final step in evaluating equation 6. This equation includes a variable

Energy Information Administration 81
The Value of Underground Storage in Today's Natural Gas Industry



Increasing Importance of Salt Cavern Storage

The sharp increase in storage withdrawals during the January 1994 cold spell included a somewhat larger share from salt
caver facilities than in January 1993—2.8 percent versus 2.3 percent. Withdrawals from new salt storage facilities accounted
for some of the increased share in January 1994, yet most can be attributed to older salt facilities. Withdrawals from these
older sites grew from 13.5 billion cubic feet (Bcf) in January 1993 to 18.6 Bef in January 1994. Total withdrawals from salt
cavern storage during January 1994 were 21.4 Bef.

The heavy demand for storage gas also highlighted the importance of salt cavern facilities for rebuilding storage inventories.
Although total storage injections during January were significantly less in 1994 than in 1993, injections into salt cavern
storage more than doubled (from 4.2 to 10.9 Bcf), representing almost one-third of the month's total (33.3 Bcf).

The expanded use of salt cavern storage was maintained throughout the 1993-94 heating season, accounting for 2.8 percent

(66 Bcf) of withdrawals and 15.4 percent (55 Bef) of injections. In comparison, during the previous heating season, salt
cavern storage represented 1.9 and 9.0 percent, respectively, of total withdrawals and injections.

Monthly Salt Cavern Injections and Withdrawals, Heating Seasons, 1991-92 Through 1993-94

(Million Cubic Feet)

Injections Withdrawals
Month 1991-92 1992-93 1993-94 1991-92 1992-93 1993-94
Heating Season
November 10,511 7,456 10,272 5,756 5,503 5,150
December 4,217 5,317 7,922 5,307 4,629 10,733
January 2,537 4,218 10,874 11,349 13,524 21,353
February 3,105 3,618 12,255 9,808 11,326 20,278
March 3,390 6,620 13,696 8,376 10,916 8,758
Total 23,760 27,229 55,019 40,596 45,898 66,272
Percent of
All Storage 5.0 9.0 15.4 1.8 1.9 2.8
Total Heating Year 68,685 78,265 118,342 63,942 80,067 110,240

Source: Energy Information Administration, EIA-191, "Underground Gas Storage Report."

36

Energy information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Regional Spot Prices Reacted Differently to Cold Spell

The price of natural gas increased dramatically in much of the United States during the January 1994 cold spell. Spot prices
changed significantly at locations serving major storage markets and northern and eastern end-use markets, and modestly or
not at all at locations serving western markets and minor storage markets. This section looks at spot price behavior at several
different locations from January 14 through 25 (Figure 15).

The Henry Hub is a major transfer point that handles large volumes of gas on a daily basis. So many buyers and sellers
engage in gas transactions at this point that the Henry Hub was chosen as the delivery point for natural gas futures
contracts. Gas from this hub serves many end-use and storage markets, yet there is little storage nearby. The spot price
exhibited greater variability at the Henry Hub than at most other major transfer points for natural gas in the United
States. This greater variability was most probably a consequence of the accessibility of the Henry Hub to the major
markets experiencing large shifts in demand. Other factors include the large number of exchanges of different sizes
that take place at the hub on a regular basis and the lack of nearby storage sites to augment supply from production
sites. Because of the large volumes of gas that pass through the Henry Hub and the attention that price at the Henry
Hub receives within the industry, reported prices probably better measure the full range of transactions that take place
at this hub than at many other major exchange points for natural gas. Prices varied by more than $1.00 per million Btu
(MMBtu) during the period considered. For example, leading up to the most severe part of the coid spell, the Henry
Hub spot price rose from a low of $2.35 per MMBtu on Friday, the 14th of January, to $3.25 per MMBtu on
Wednesday, the 19th of January. On the 19th alone, prices varied by $0.21 per MMBtu.

The variability in price between days was also great at a location on the Iroquois pipeline system near the U.S./Canada
border at Niagara Fails. This system serves the New England market where storage is scarce or nonexistent. Price
variation was strikingly comparable to the Henry Hub prices, varying from a low of $2.35 per MMBtu on the 18th of
January to a high of $3.25 on the 19th. After the 20th, prices plummeted and stayed constant between days much as
they had prior to the 19th.

Texas Eastern Transmission Corporation's (TETCO's) Katy Hub, like the Henry Hub, is near a major producing region.
Located near Houston, the Katy Hub is a major transfer point for gas in east Texas, the heart of the gas industry, and
was a prime candidate for deliveries through the futures contract. Several major storage sites, including numerous salt
dome sites, are located in east Texas, effectively increasing the supply of gas available from this area. This may help
explain the relative lack of price variability at the Katy Hub during the cold spell. It is also consistent with other
statistics of increased injections into storage and increased industrial consumption during February in Texas, which
suggest that supplies were more than adequate in Texas at the end of January.

The Panhandle Eastern Pipeline Company (PEPL) interconnect, in the panhandle of Oklahoma, exhibited similar price
variability to that of the Katy Hub. This suggests that both locations experienced similar supply and demand conditions
during the time period.

The Appalachian locations on the Columbia Gas Transmission system are mostly in Pennsylvania, Ohio, and West
Virginia. There are major space-heating markets for natural gas near these points, which are supported by nearby
storage facilities. The many storage sites may explain, in part, the relatively modest increase in price during the cold
weather.

The San Juan and Permian locations, which primarily serve western markets, in particular California, were not
experiencing cold weather during the period. Hence, spot prices remained relatively constant at these locations.

Only the Northwest interchange experienced less price variability than the San Juan and Permian locations. This lack
of variability is explained by the fact that this interchange serves the west coast market exclusively.

During the time period, prices varied between days as the changing conditions brought on by the cold weather manifested
themselves. Prices increased as the weather became colder, but they soon returned to previous levels once the most severe
weather had passed.

20

Energy information Administration
The Value of Underground Storage in Today's Natural Gas Industry



Figure 19, Storage Capacity Utilization in 1994 Reversed the Declining Trend, Moving Higher Than 1991
Levels Near the End of the Nonheating Season

p> 1005

Oo

o

Qa

S

°

a 80 4

oO

D

&

<

S 60-4

=

3

<

8

3 40 4

a

«

o

o

g 204

5 1994

o

£

4

S

= oF T T T T T T
Apr May Jun Jul Aug Sep Oct

Nonheating Season

Source: Energy Information Administration, EIA-191, “Underground Gas Storage Report.”

on behalf of their bundled sales customers became the
responsibility of these former sales customers as well as some
new customers,

The uncertainties associated with this transition to unbundled
storage service have fostered a certain degree of caution,
particularly for those customers less experienced in managing
inventories. Perhaps more importantly, individual customers
are making their own decisions about inventory requirements,
which in aggregate may require greater capacity than if
pipeline companies, with their system-wide approach, still
controlled storage levels. Further, because many of these
customers are local distribution companies (LDC's) with a
service obligation to end-use customers, they may tend to err
on the side of holding too much inventory rather than too
little. Finally, the increased ratio of working gas to working
gas capacity can be attributed partly to customers taking
advantage of a drop in spot market prices that began in
August 1994.

Unbundled storage services provide users with a means to
evaluate more closely their use of storage relative to their
specific needs and purchasing strategies. For those customers
who have just recently begun to cope with unbundled
services, it is not surprising that 1994 would be a year of
cautious operations, And, with customers making their own
inventory management decisions, an upward shift in

aggregate inventory levels may occur. In the future, however,
as storage users become more accustomed to managing their
own inventories, the trend toward lower levels of working gas
in storage, and for increasing weather-adjusted withdrawals,
may resume,

New Market Requirements Are
Driving Storage Expansions

Order 636 and significant new developments in supply and
demand conditions have required market participants to
explore new approaches to the use of storage facilities,
develop new services, and propose substantial additions to
existing storage capacity. Although additions to underground
storage capacity for the traditional seasonal services of
augmenting mainline transmission capacity continue to be
proposed, a substantial portion of the proposed additions have
very different characteristics. These include: (1) rapid
inventory turnover capability, (2) location in the Gulf Coast
producing region or near new transmission capacity, (3)
sponsorship by independent developers rather than interstate
pipeline companies, (4) year-round capability for withdrawal
and injection, and (5) little or no notice required for
withdrawal and injection.

Energy Information Administration 23
The Value of Underground Storage in Today's Natural Gas Industry



where T, is the temperature on day t at a particular site (the average of the daily high and low temperatures at the site), and NT,
is the normal temperature on day t at the same site (the average of the long-term average high and low temperatures at the site).
Thus, as temperatures fall below normal, the deviation in temperature, DT, is positive and increases. A positive relationship is
expected between PR, and DT,; that is, as DT, increases (T, declines relative to NT,), PR, is expected to increase.

The variable T is a reliable measure of daily temperatures at a site as long as a large drop in temperature does not occur at the
beginning or close of a day. A further refinement of the analysis presented here would be to use hourly temperature data in order
to adjust for such shifts. For example, if the temperature declines from 40° F to 12° F between 3 a.m. and 5 a.m. and stays near
12° F throughout the day, it would probably be better to use the minimum temperature rather than the average of the high and
low temperatures as an indicator of temperatures experienced during the day.

The values of DT used for this analysis are the average of DT for four cities that are distributed across the major natural gas
space-heating region of the United States. The four cities are Kansas City, Missouri; Chicago, Illinois; Pittsburgh, Pennsylvania;
and New York, New York, The temperature changes at these sites represent the temperature changes experienced by a large
percentage of gas space-heating customers in the United States. Interestingly enough, data for several sites (Chicago and
Pittsburgh in particular) give results similar to an average of the values at the four sites in terms of explaining PR.[16] These
results follow from the interesting fact that temperature changes between days across locations in the eastern part of the United
States tend to be correlated or dependent, while temperature changes between days at the same site tend to be uncorrelated or
independent.

A previous analysis[17] found average monthly storage withdrawals to be highly correlated with average monthly declines in
temperature. Therefore, prior to examining the relationship between the daily variables, PR and DT, the issue of whether DT is
also a possible proxy variable for daily storage withdrawals was examined. The way that this issue was addressed is described
next.

An estimate of weekly storage withdrawals was computed by taking the difference in the level of weekly working gas between
weeks for the Consuming East Region as defined by the American Gas Association (AGA). This region includes the cities of
Kansas City, Missouri; Chicago, Illinois; Pittsburgh, Pennsylvania and New York, New York. (These weekly data were first
published by the AGA in December 1993). This should provide a reasonable estimate of withdrawals as long as there is only a
modest amount of injections of gas into storage for the time period covered by the analysis. An examination of monthly EIA data
indicate that storage injections were only 7 percent of withdrawals during January and February 1994. Weekly values for DT
were obtained by taking the sum of the daily values for DT, for the same 7-day period covered by the AGA weekly storage
statistics. Then, the correlation coefficient for weekly values for DT and weekly values for storage withdrawals was computed.
The correlation coefficient was found to be equal to 0.82.

Given the strong relationship between weekly values of DT and the estimate of weekly storage withdrawals, DT, is used to
approximate the behavior of daily storage withdrawals. When PR is regressed on DT, the following equation is estimated
(standard errors are reported in parenthesis):

PR, = 0.184 + 0.0182DT, ()
(0.042) (0.004)

R? = 0,37, n= 38 (the number of data points that covers the 38 trading days on the cash and futures market
for the months of January and February 1994).

The estimated coefficients are statistically different from zero as indicated by the magnitude of the standard error relative to the
magnitude of the estimated coefficient. In addition, 37 percent of the variability in PR is explained by DT (R? = 0.37). When a
robust estimator (least absolute deviation[18]) is used to reestimate the relationship between PR and DT and to evaluate the
influence of outlying observations on estimated results, it is found that the estimated coefficient for the intercept term (0.1 84)
changes by only -0.017 and the coefficient for the variable DT (.0182) changes by only -0.007. Thus, the coefficients are found
to be stable and not much influenced by outlying observations. The value of R?, however, increased to 0.51.

Estimated results for equation 3 and the robust procedure are mentioned in the main body of the text. Another estimated equation,
which is discussed next (equation 4), includes a time variable (TP). As a consequence of the examination of the residuals from
this estimation, two additional equations (equations 5 and 6) were estimated. The results of these estimations appear in

Energy Information Administration 79
The Value of Underground Storage in Today's Natural Gas Industry



Figure 10.

Henry Hub Spot Price
(Dollars per Million Btu)

Futures Price

(Dollars per Million Btu)

Premium
(Dollars per Million Btu)

Prices Reacted to the Frigid Weather in January and February 1994

Henry Hub Spot Prices Soared
3.80 Feb2
3.60
3.40
3.20 +

300 -| Jan 18

Jan 19

280 4
260 +
240 +
2.20
2,00
1.80

0

Petit

18 io Wie 12 21 28 216 203 32 90 316 gos a0 47 Ald ADT
1994

3.80 — Futures Prices Increased As Well, But Less Dramatically Than Spot Prices . . .

3.60 =
340 -
3.20 —|
3.00
2.80
2.60
240
2,20
2.00
1.80

Feb2
Jan 19

Justa t

°
tot

AAS SORGE SOADE DARA SAOARDAOOE LARS T r
18 10 118 125 21 28 25 23 a2 a9 a6 ans 30 47 4/4 421
1994

. -. Causing the Premium Value of Gas in Storage to Rise Sharply
120 > Feb2

1.00 4
Jan 19

080 -|  Jan18

060 +
040 +

020 +

ano 1 N oN

| “Ae

0.200 T r T Try TOT rey TTT T T T
V3 10 198 125 21 28 25 223 32 39 36 323 330 47 414 4/21
1994

Notes: Futures prices are for the expiring contract. The premium is the difference between the spot price and the futures price. Data are
unavailable for weekends and holidays. Because vertical scales differ, graphs should not be directly compared.
Sources; Henry Hub Spot Price: Pasha Publications Inc., Gas Daily. Futures Price: Commodity Futures Trading Commission, Division
of Economic Analysis, Premium: Energy Information Administration, Office of Oil and Gas: derived from: Henry Hub Spot Price and Futures

Price.

Energy Information Administration
The Value of Underground Storage in Today's Natural Gas Industry

15



footnote 22 in the main text. A final equation was also estimated (equation 7) to evaluate the inclusion of a stock variable in the
specification of the behavioral relationship underlying equation 6. The results reported for this estimation are not reflected in the
main text because this estimation was done for the primary purpose of evaluating the estimated results reported for equation 6.

As previously stated, part of the difference between DSP, and DFP, is due to the cost of storing gas and the cost of borrowing
money (the daily interest rate times the number of days over which the money is to be borrowed). The daily cost of having gas
in storage, per MMBtu of gas acquired, is relatively constant from one day to the next because most storage rental space charges
are based on long-term fixed price contracts. The cost of storage at a particular time is determined more by contract conventions
than by market forces, although over time contract provisions may be changed to reflect market conditions. The interest rate is
also relatively constant from one day to the next although interest rates did begin to increase during February 1994.

A time index variable (TP), which declines in value by one unit for each trading day as the termination of contract approaches,
is used as a proxy variable to capture the cost of storage and the cost of money in the regression relationship. This proxy variable
is used because estimates of the daily cost of storing gas are not generally available.

The variable TP declines in value as the last trading day of the futures market approaches because the cost of storage and the cost
of money declines as the number of days to the termination of the contract declines. For example, in principle, if money is
borrowed to purchase and store gas 20 days before the termination of the contract, the cost of money and the cost of storage is
approximately 20 times as great as it would be if we borrowed money to purchase and store gas on the last day of trading of the
futures contract. Thus, if there are 20 days to the termination of the contract, this variable takes on the value 20, while if there
is one day to termination, it takes on the value one.

The estimated equation with both DT and TP is (standard errors are reported in parenthesis):

PR, = 0.288 + 0.0184DT, - 0.0070TP, 4)
(0.078) (0.004) (0.0043)

R?= 0.40, n=38.

Although the signs of all coefficients are consistent with expectations and the coefficient for DT is clearly significantly different
from zero, examination of the residuals from the fitted equation reveals that the r-student values associated with observations
for February 2nd and 3rd are particularly large at 4.1457 and 3.3694, respectively. Such large residuals may be due to erroneous
data, a misspecified stochastic model, or a misspecified behavioral relationship.

Misspecified Stochastic Model

Large residuals can be viewed as a consequence of the error terms being generated by a distribution other than the normal
distribution. This would be a distribution in which the chance of extreme values is greater than under a normal distribution. In
situations where information is unavailable about the distribution of the error terms in the population, a robust estimator, such
as a least absolute deviation (LAD) estimator, may be a better estimator than the ordinary least squares (OLS) estimator. The OLS
estimator is inherently very sensitive to the distributional assumption, in that the value estimated for a coefficient is potentially
very sensitive to outlying observations. LAD estimators, however, are less sensitive to the exact form of the distribution.

When the relationship between PR and DT and TP is reestimated using a LAD estimator, the following equation is estimated
(standard errors are reported in parenthesis):

PR, = 0.316 + 0.0187DT, - 0.0104TP, (5)
(0.042) (0.0023) (0.025)
R?= 0.69.
80 Energy Information Administration

The Value of Underground Storage in Today's Natural Gas Industry



Figure ES3, Storage Capacity Utilization Declined in the Early 1990's, But Increased in 1994
100 —

Working Gas as a Percent of Working Gas Capacity

T T T T T T
Apr May Jun Jul Aug Sep Oct
Nonheating Season

Source: Energy Information Administration, EIA-191, "Underground Gas Storage Report."

Figure ES4, Proposed Salt Facilities Will Provide More Withdrawal Capability Relative to Total Capacity Than

Depleted Fields
80 - Share of Proposed Additions, 1994-1999
( Depleted Field
HB Aquifer
60 4 Salt Cavern
e
8
5 40 4
a.
20 4
Additions to Total Additions to
Storage Capacity Withdrawal Capacity

Source: Energy Information Administration, Office of Oil and Gas, "Proposed Natural Gas Storage Projects,” data base as of October 31,
1994, based on Federal Energy Regulatory Commission filings and information from various industry news sources.

Energy Information Administration xi
The Value of Underground Storage in Today's Naturat Gas Industry



Salt bed or dome storage is prepared by injecting water
(leaching) into a salt formation and shaping a cavern.** It is
the most costly of the three types of facilities to develop, often
two to three times more expensive. Because they are
susceptible to cavern wall deterioration over time and to salt
water incursion, these facilities may incur high workover
costs, as well as additional expenses for special equipment on
site. However, deliverability rates are high because a salt
formation reservoir is essentially a high-pressure storage
vessel (that is, an underground tank). Base gas requirements
are low (about 25 percent) and can usually be withdrawn fully
in an emergency. On average, salt formation storage is
capable of multiple cycling of inventory per year, in
comparison to the typical one cycle or less for depleted gas/oil
field and aquifer storage. As such, salt formation storage is
well suited for meeting large swings in demand.

Eleven of the existing natural gas salt storage formation sites
once were used to store natural gas liquids (NGL) or brine
and were converted to natural gas storage. Although more
than 100 salt formation caverns in the United States and
Canada are used to store NGL's, not too many conversions are
expected because most of them are extremely small in size.

A salt cavern site occupies a much smailer area than an oil or
gas reservoir. On average, the amount of acreage taken up by
a depleted gas/oil field reservoir is more than a hundred times
the amount of acreage taken up by a salt dome. Consequently,
a salt cavern storage operation is generally easier to monitor
than a gas/oil field reservoir operation made up of many
wells,

Development time is also much less for salt formation storage
than for gas/oil field reservoirs. On average, it takes about 18
to 24 months to develop a salt reservoir while a gas/oil field
Teservoir takes 24 to 36 months, Thus, a new salt formation
storage site will begin to pay off sooner than a gas/oil field
reservoir,

For the same working gas capacity, new salt formation
storage reservoirs are also capable of yielding much greater
revenues for a heating season than conventional gas/oil field

“The leaching process requires drilling a well into the salt structure, one
or more wells for brine disposal, fresh water sources (frequently a well is
drilled into freshwater formations), pumps for fresh water injection and brine
disposal, a pump and storage tank for the blanket liquid used to control
upward leaching of the cavern roof, the blanket material (usually a light
hydrocarbon), and the associated gathering lines connecting the wells and
pumps, The total quantity of water that must be cycled through the cavern
is 7 to 10 times the cavern volume. The entire leaching and dewatering
process takes from 4 to 6 months per Bef of gas storage volume. In an area
where fresh water supplies are limited, leaching time may be significantly
extended, Leaching costs, excluding disposal wells and costs directly
associated with drilling the injection/withdrawal well, make up roughly 15
to 25 percent of the average salt cavern storage project.

reservoirs. This is because the working gas capacity of a salt
formation storage facility can be turned over three, four, or
more times during a heating season while generally a gas/oil
field operation can be turned over only once. Most of the
Nation's salt dome storage facilities are located in Texas,
Mississippi, and Louisiana. Although used effectively by
electric utilities in the South to satisfy daytime peak cooling
loads during the summer, several salt cavern operations
located in Louisiana and Mississippi have attracted LDC's as
well as other types of customers located in the Northeastern
United States. Perhaps in response to this demand, several salt
storage sites are being developed in New York State (see
Appendix B). These facilities would augment directly the
operations of nearby gas distribution companies.

In summary, although they are the most expensive type of
storage to develop and maintain, salt formation storage
facilities permit withdrawals at high rates and can be drawn
down quickly in emergency situations. As such, salt formation
sites are well suited for peaking operations to meet dramatic
swings in gas demand.

Other Types of Natural Gas Storage
LNG Storage

Liquefied natural gas (LNG) storage facilities are also used
for peaking purposes, but relative to underground storage
projects are much more expensive to institute and maintain.
LNG is generally used as a peak-shaving medium (see the
following section) in areas where underground storage or
facilities for other supplemental fuels, such as liquefied
petroleum gases, are unavailable or inappropriate. In such
situations, natural gas in the gaseous state is received via
Pipelines and is locally transformed at very low temperatures
into the liquid state and placed in specially built LNG storage
tanks. During peak-load periods it is returned to the gaseous
form and fed into the local distribution system.

During the late 1960's, the concept of importing LNG into the
United States as a supplemental supply of gas was first
proposed. Even though transportation and storage costs were
recognized as potentially very high, the source gas was
initially very low-priced. While overall cost per unit remained
high relative to domestic natural gas, much of the incremental
cost of LNG use was included in the rate base. Because
planning and system development for such an undertaking
require long lead times, it was not until the mid-1970's that
many of the elements were finally in place. By then, however,
Prices for imported energy products, including LNG, changed
the outlook for LNG imports as a competitive gas source.
LNG imports reached a high of 252 billion cubic feet in 1979,
but because of contractual and pricing problems with foreign

Energy Information Administration 51
The Value of Underground Storage in Today's Natural Gas Industry



Table B3. Proposed Underground Storage by State, 1994-1999 (Continued)

Capacity Capacity
(billion cubic feet) (MMcf per day)
Working Total Cost
Project Name/State Total Base Gas Gas Withdrawal —_ Injection (Thousand $)
OKLAHOMA,
MANCHESTER 18.50 3.50 15.00 250 400 $30,000
OKFUSKEE 45.00 15.00 30.00 600 200 $70,000
TOTALS; Projects = 2 63.50 18.50 45.00 850 300 100,000
PENNSYLVANIA
LAUREL FIELDS-CALLEN RUN 24.90 12.80 12.10 130 50 $76,000
RIVERSIDE 5.64 2.54 3.10 48 48 $24,000
TOTALS: Projects = 2 30,54 15.34 15.20 178 98 100,000
TEXAS
ATKINSON GAS STORAGE 39.00 11.00 28.00 400 300 $23,000
BETHEL PHASE 3 5.00 4.50 3.50 200 ° $29,000
HILBIG 4.80 1.80 3.00 60 30 $15,000
LOOP PHASE 2 2.00 1.00 1.00 200 100 $2,500
LOOP PHASE 3 2.00 1.00 1.00 200 100 $2,500
MARKHAM (CAVERN #2) 4.50 1.30 3.20 250 90 $11,700
MOSS BLUFF PHASE 3 6.00 2.00 4.00 300 0 $17,000
NICHOLS STATION PLANT 4.20 1.20 3.00 300 150 $13,000
NORTH FELMAG 5.60 0.00 5.60 140 150 $0
SALADO GAS STORAGE 3.00 0.00 3.00 260 0 $0
SPINDLETOP (SABINE-CAVERN 470 1.90 2.80 120 ° $0
SPINDLETOP (SABINE-CAVERN 5.40 2.50 2.90 240 600 so
SPINDLETOP (WINNIE P L) 10.30 0.00 10.30 1000 0 $46,000
STRATTON RIDGE (AMOCO) 1.40 0.40 1.00 100 0 $8,300
STRATTON RIDGE (MG) 12.50 5.30 7.20 250 100 so
TOTALS: Projects = 15 110.40 30.90 79.50 4,020 1,620 168,000
UTAH
CLAY BASIN EXPANSION 26.30 11.10 15.20 258 130 $49,600
TOTALS: Projects = 4 26.30 14.10 18.20 258 130 $49,600
VIRGINIA
SALTVILLE 0.25 0.00 0.25 25 0 $0
TOTALS: Projects = 4 0.25 0.00 0.25 25 0 $0
WYOMING
ELK BASIN RETROFIT 0.00 0.00 0.00 55 ar $3,692
TOTALS: Projects = 1 0.00 0.00 0.00 85 27 $3,692
U.S. TOTAL 20,746 7,804 $2,166,834

MMcf = Million cubic feet.

Note: Two liquefied natural gas storage projects (one new, one expansion) have also been proposed by Cove Point LNG at Cove Point,
Maryland, which would add 4 Bcf working gas capacity, 1,000 MMcf per day withdrawal capacity, and 15 MMcf per day injection capacity. Totals
may not equal sum of components because of independent rounding.

Source: Energy Information Administration, Office of Oil and Gas, "Proposed Natural Gas Storage Projects," data base as of October 31,
1994, based on Federal Energy Regulatory Commission filings and information from various industry news sources.

Energy Information Administration 67
The Value of Underground Storage in Today's Natural Gas Industry



Table 5. Storage Service Providers Seeking to Charge Market-Based Rates

. Capacity
Application Status/ Date FERC Facility State | Reservoir Working Injection Withdrawal
Company Applied Action Name Type Gas (Bcf) (MMcfid) (MMcfid)
Approved
Richfield Gas Storage 1-7-92 6-16-92 Richfield KS Depleted 3.5 22.9 43.6
(CP92-285) West Field Field
Transok? 10-16-92 7-20-93 Greasy Creek OK Depleted 13.2 130.0 225.0
(PR93-02) Field
Petal Gas Storage 11-18-92 9-4-93 Petal MS Salt Cav 3.5 160.0 320.0
(CP93-69) (Chevron)
Koch Gateway 9-30-93 3-31-94 Bistineau LA Depleted 42.5 NA 430.0
Pipeline? (RP93-205) Field
Bay Gas Storage® 10-12-93 3-25-94 S. AL- AL Salt Cav 15 6.0 17.5
(PR94-01) Mcintosh
Ouachita River Gas® 10-21-93 9-30-94 Ouachita LA Depleted 27.0 250.0 550.0
(CP94-38) River Field
Avoca Natural Gas 12-23-93 7-17-94 Avoca NY Salt Cav 5.0 250.0 500.0
Storage (CP94-161) (Phases 1-3)
Total - - - - - 96.2 - 2,086.1
Not Approved
ANR Pipeline® 11-1-93 5-2-94 Various MI Depleted NA NA NA
(RP94-43) Field
Cove Point LNG 11-393 "9-28-94 Cove Point MD LNG 7 24 15.0 400.0
(CP94-59)
Michigan Consolidated 3-2-94 7-19-94 Various MI Depleted 141.6 NA 3,151.0
Gas (PR94-09) Field
Total - - - - - - - -
Pending
Enron 41-15-93 = Napoleonville tA __ SaltCav 46 200.0 400.0
(PR94-02)
Entre Energy 4-28-94 - Chandeleur LA Depleted 26.0 300.0 300.0
(CP94-389) 29 Field
Llano, lac, 9-28-94 - Grama Ridge NM Depleted 14.5 NA 75.0
(PR94-21) Field
Total - - - - - 45.1 - 775.0

*FERC granted initial approval for 4.0 Bcf to be made available as interstate storage services at market-based rates. The remainder is retained
for intrastate storage services but may be made available in the future to interstate markets at market-based rates, subject to FERC review and

approval.

Represents only a portion of capacity available at the Bistineau facility. The remainder is reserved for no-notice and operational purposes.
Represents only a portion of capacity. The remainder is retained for intrastate service.
*Preliminary authorization only.
*tn a Section 4 rate filing, ANR proposed a 2-year pilot program utilizing market-based pricing for unspecified “new storage services." Capacities

proposed for these services were not enumerated.

Bef = Billion cubic feet, MMcf/d = Million cubic feet per day. NA = Not available. LNG = Liquefied natural gas.

Source: Federal Energy Regulatory Commission, as of January 20, 1995.

The Value of Underground Storage in Today's Natural Gas Industry

Energy Information Administration

37



Some believe that this "capacity release" argument will
eventually be used by large storage providers to attempt to
justify market-based rates, and that its success will probably
parallel whatever success the corollary argument for market-
based transportation rates has with FERC. Currently,
Transcontinental Gas Pipeline Company has a case pending
before FERC that requests market-based transportation rates
for its system. The company uses the argument that the
competitive force of transportation capacity release is
sufficient to preclude market power. FERC has delayed
hearings on the case until it has at least 12-months' experience
with transportation capacity release to assess its impact and
effectiveness,

Storage Capacity Release

As with transportation capacity, FERC requires that interstate
storage providers allow their customers to release unused
storage capacity. FERC also requires storage providers to
facilitate release transactions by posting available capacity on
their electronic bulletin boards (EBB's).* Since Order 636
went into effect on November 1, 1993, however, storage
capacity release activity has been quite limited, Capacity
release has taken place in the storage facilities of only a few
storage providers.

The storage capacity release market is referred to as a
secondary market. The primary market comprises a set of
contracts between storage service providers and their
customers. Such contracts give the customer, such as a
distribution company, the right to store gas in a storage
facility. Thus, the distribution company has rented some
unidentified portion of space within a storage site for storing
gas that it owns. The release market is used to sublet this
space,

One reason for the lack of activity in the release market is
simply that the concept and practice of unbundled storage
services is so new in the industry. Before Order 636, few
shippers had any experience in buying unbundled storage
services, and the concept of capacity release, much less a
market for released capacity, was nonexistent. It seems likely
that shippers, having just contracted for storage services
separately for the first time, are being conservative, even
cautious, about releasing capacity until they have more
experience in using and managing their capacity.

Under Order 636, FERC requires pipeline companies to adminster a
capacity release program for its system by providing electronic bulletin
boards where capacity offers are posted, bids are evaluated, and winning
bids are determined, See Energy Information Administration, Natural Gas
1994: Issues and Trends, DOE/EIA-0560(94) (Washington, DC, July 1994),
p. 45,

Another reason for this lack of activity may be that current
rate structures and rate design guidelines for the major renters
of storage capacity—local distribution companies—provide
few incentives for them to pursue storage capacity release.
State public utility commissions (PUC's) may reevaluate these
regulations and require LDC's to itemize and separately
charge for storage services provided for customers. If a PUC
is persuaded that LDC's are purchasing too much storage
capacity, it could also disallow the associated costs from the
rate base. At least one State is experimenting with providing
incentives for LDC's to utilize the secondary market to cut
costs. In North Carolina, an LDC is permitted to keep as
profit 10 percent of the revenues received from marketing
released storage capacity. If experiments of this type prove
successful, other States are likely to follow suit, which would
probably expand the storage release market.”

A third reason for the tack of activity could be that firm
storage capacity is being rebundled and sold with the
unregulated natural gas commodity and possibly firm
transportation service instead of being released through
pipeline company-operated EBB's. Some of these transactions
are devised under arrangements known as “buy-sell”
agreements. Many of these transactions do not have to be
done through EBB's in that all buy-sell agreements made
before November 1, 1993, were "grandfathered" by Order
636 as being exempt from the capacity release program.

The use of arrangements that are not posted on the EBB's,
such as those under buy-sell agreements under Order 636,
has been labeled the "gray market" for capacity.’ Several
reasons exist why shippers might prefer to trade unneeded
storage capacity through the gray market instead of through
the capacity release program: (1) to avoid using cumbersome
EBB's, (2) to preselect trading partner(s), (3) to earn higher
margins by creating a value-added product and by limiting
price discovery, and (4) to speed up the transaction by
avoiding the competitive bidding process.

Despite the shortcomings of the capacity release market and
its small size, available data give some indication of the
market's potential. First, the capacity release market allows a
buyer to enter into short-term agreements for storage capacity

Jeff D. Makholm, "Gas Pipeline Capacity," Public Utilities Fortnightly
(October 1, 1994), p. 20.

“There are several types of buy-sell agreements. Many permit shippers
to sell a rebundled package of firm storage capacity or firm transportation
capacity along with the natural gas commodity to an end user. For example,
under one type of buy-sell agreement, the shipper or LDC will purchase gas
on behalf of an end user, then transport or store the gas for the end user
under the firm rights the shipper had purchased from an interstate pipeline
company.

“'Philip M. Marston, "The Rumbte of Bundles: A Review of Experience
Under the Capacity Release Experiment” (Hadson Gas Systems, Inc., August
1994),

Energy Information Administration 39
The Value of Underground Storage in Today's Natura! Gas Industry



Figure D3. Residuals Plotted Against Variable TP

4.00 —
3.00 4

2.00 + .

oe
.

1.00 4 . .

Residuals (Dollars per MMBtu)
°
°
=)

T T T T 1
0 5 10 15 20 25° 30 35

Variable TP

Source: Regression equation 6.

representing daily storage levels on day t -1 (S,,:) relative to expected demand on the next day (D,). The procedure used to
construct the variable is described below. In short, the American Gas Association's weekly storage statistics series is used to
construct a daily gas storage series (S,.,). This amount is, in turn, normalized by the inverse of daily normal temperatures on day
t (i.e. INT, which is used to represent expected deliveries on day t because expected deliveries should be related to normal
temperatures. For example, as daily normal temperatures decline, space-heating demands are expected to rise. Thus, the ratio
(S,./CI/NT,)) is a proxy variable for S,./D,.

Daily values for S are obtained by interpolating between weekly values of working gas in storage S,,, which is the amount of gas
in storage reservoirs used to serve markets. The daily weights (w,) used for the interpolation are calculated in the following way:

w, = (HT, - TVET, - T) (0)

where HT,, is the high value for T (defined previously) experienced during week m. The daily weights are multiplied by the
change in working gas between week m and week m+1 to obtain the daily decrements in working gas between weeks. These
amounts are then subtracted from the working gas level at the end of week m.

When the relationship between PR and DT, TP, FEB and the new variable S,.,/D, is estimated, the following results are obtained
(standard errors are reported in parenthesis):

PR, = 0.385 + 0.017DT, - 0.053(S/D,,;) - 0.00785TP, + 0.79FEB (8)
(0.108) (0.000025) (0.042) (0.0029) (0.114)

R? = 0.764.

Thus, it is found that S, ,/D, has the expected negative sign; that is, PR declines as storage levels rise relative to expected demands.
However, the standard error of the coefficient relative to the magnitude of the coefficient indicates that the coefficient is not
statistically different from zero. The R? value increases only modestly between equations 6 and 8. The estimated coefficients also
do not change much between equations.

Energy Information Administration 83
The Value of Underground Storage in Today's Natural Gas Industry



Figure 1. Storage Facilities Are Heavily Concentrated Near Major Eastern Markets

Consuming West

_¥

* Depleted Fields

4 aquifers
© salt caverns

Producing

Consuming East

Consuming East Region

Consuming West Region

Producing Region

Working Gas Working Gas Working Gas
Capacity Capacity Capacity

State (Bef) State (Bcf) State (Bef)
fowa 98 California 222 Arkansas 3
Minois. 317 Colorado 57 Kansas 120
Indiana 35 Minnesota 2 Louisiana 285
Kentucky 105 Montana 203 Mississippi 52
Maryland 16 Oregon 7 New Mexico 64
Michigan 617 Utah 54 Oklahoma 133
Missouri 8 ‘Washington 15 Texas 369
Nebraska 15 Wyoming 46
New York 75
Ohio 238
Pennsylvania 329
West Virginia 209

Total 2,062 606 1,026

Percent of U.S. Total 56 16 28
U.S. Total 3,694

Bef = Billion cubic feet.

Note: Regions are those established by the American Gas Association.
Source: Energy Information Administration, Office of Oil and Gas, Natural Gas Pipeline Geographic Information System

(November 1994).

Energy Information Administration
The Value of Underground Storage in Today’s Natural Gas Industry