White Paper: Coal Mine Methane in
Today's Natural Gas Market
Prepared for
Environmental Protection Agency
Atmospheric Pollution Prevention Division
Prepared by
ICF Incorporated
May 12,1997
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ACKNOWLEDGEMENTS
This report was prepared under Work Assignment 3-03 of the U.S.
Environmental Protection Agency Contract 68-D4-0088 by ICF Incorporated.
The principal authors were Leonard Crook, Ed Hardy and Trevor Yeats of ICF
Incorporated. The views represented here do not necessarily reflect the views
of the U.S. Environmental Protection Agency. Mention of trade names or
commercial products does not constitute endorsement or recommendation for
use.
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I. INTRODUCTION 1
II. OVERVIEW OF THE NATURAL GAS INDUSTRY TODAY : 3
A. The Industry Before FERC Order 636 3
B. Order 636 5
C. General Structure and Operation of the Gas Industry Today , 6
1. Production and Consumption 6
2. Major Players in the Industry Today-Who Does What 10
3. Scope of Current Regulation 12
D, Gas Prices and Gas Price Formation 12
E. Implications for Coal Mine Methane 16
III. HOW NATURAL GAS IS MARKETED TODAY ;17
A. Elements of Gas Sales Contracts 17
B. Elements of Gas Transportation Agreements 20
1. Direct Transportation Service 20
2. Released Capacity 22
3. Operational Issues 22
C. Creating Value with Contract Terms 24
1. High Value Markets 25
2. Tailoring Contract Terms 25
3. Value-added from Bundling Gas with Other Services 26
IV. STRATEGIES FOR COAL MINE METHANE 28
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List of Figures
EXHIBIT 1 LEGISLATIVE AND REGULATORY ACTIONS LEADING TO A COMPETITIVE GAS
MARKET 4
EXHIBIT 2 ORDER 636 CHANGES 5
EXHIBIT 3 MAJOR NATURAL GAS BASINS 7
EXHIBIT4 1995 US GAS CONSUMPTION BY CENSUS REGION (BCF) 7
EXHIBIT 5 1995 US GAS CONSUMPTION EAST OF THE MISSISSIPPI 8
EXHIBIT 6 US NATURAL GAS CONSUMPTION BY SECTOR 8
EXHIBIT 7 SEASONAL GAS DEMAND BY SECTOR (1995) 9
EXHIBIT 8 1995 NATIONAL GAS PRICES AND NETBACKS 14
EXHIBIT 9 REGIONAL GAS PRICES 15
EXHIBIT 10 US HISTORICAL GAS PRICES BY SECTOR 15
EXHIBIT 11 GAS PRICES BY SECTOR FOR REGIONS EAST OF THE MISSISSIPPI, 1995 16
EXHIBIT 12 PIPELINE TARIFF RATES, S/MMBTU 21
EXHIBIT 13 EXAMPLES OF GAS QUALITY SPECIFICATIONS 23
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I. INTRODUCTION - ninytor; DC :;04GC
The natural gas market has .undergone revolutionary changes in the last decade. It has been
transformed from a utility service to a commodity market. This is largely a consequence of the
Federal Energy Regulatory Commission's (FERC's) Order 636, passed in 1992, which
restructured the natural gas pipeline industry- In the past, government regulations prescribed
everything from the price of natural gas to who could buy, sell and transport it and under what
conditions. Today the natural gas industry has evolved to a market-based industry where
normal commercial relationships largely define industry operations. There are far fewer
regulatory barriers to industry operations, making it much easier for the marketing of coal mine
methane.
Marketing coal mine methane can be profitable. Some operators of gassy coal mines have
certain advantages when competing in the natural gas industry:
• In most cases, drilling and gathering costs for methane removal from mines can be
considered a "sunk" cost for purposes of marketing the methane, since these wells
would have been necessary for mining operations. The costs of marketing
methane, therefore, can be lower than comparable conventional gas production.
• Many gassy mines are located east of the Mississippi, near major gas consuming
regions. These mines would compete with Appalachian gas supplies and as such
can receive higher netback prices for mine owners than those received by natural
gas producers in the Southwest or Canada.
• Many gassy mines are also located downstream of natural gas pipeline bottlenecks
in Texas and Louisiana, giving them an edge in making cold-weather winter
deliveries, when most of the interstate pipelines are running at capacity.
• Abandoned coal mines may be especially sutitable for gas storage. Storage with
rapid withdrawal capability is a high value service in the gas industry.
In order to take advantage of these opportunities, however, coal mine operators must make a
long-term commitment to get their gas to market. This includes the capital costs needed to
produce the gas and move it to major pipeline connections, as well as the development of
commercial relationships with marketers, transporters and customers.
This paper introduces the reader to today's natural gas market and explains under what
conditions the sale of coal mine methane in the natural gas market is possible. Ultimately,
whether a coal mine operator can profitably sell the methane from a mine will be determined
by the particulars of the situation and market conditions.
This paper is organized in three sections. The first section provides an overview of the natural
gas industry, with emphasis on the significance of FERC Order 636. It outlines the general
market structure, identifies the key players in the industry and describes the market factors that
determine gas prices in the post-Order 636 environment. This section also addresses how
changes in the industry affect the marketing of natural gas. The second section focuses on
the details of marketing natural gas through a discussion of the structure of typical gas sales
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contracts and transportation agreements. The final section focuses specifically on the
marketing of coal mine methane.
This paper assumes that coal mine methane producers are similar to any small to medium
sized gas producer in that there are no inherent liabilities or advantages associated with coal
mine methane that would not also be faced by any gas producer similarly located. Natural gas
is a commodity, and coal mine methane sold as natural gas is commercially indistinguishable
from any other source of gas.
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II. OVERVIEW OF THE NATURAL GAS INDUSTRY TODAY
A. The Industry Before FERC Order 636
The modem natural gas industry began with the construction of large diameter pipelines made
possible by advances in metallurgy in the late 1920s. Prior to this, natural gas transmission
was a local affair, and was regulated, if at all, by state utility commissions. Federal regulation
followed the construction of long distance interstate pipelines with the Natural Gas Act in 1938.
The Federal Power Commission, predecessor to FERC, was given the responsibility of
regulating the construction of interstate pipelines, interstate pipeline transportation tariffs, and
later with the Supreme Court decision in Phillips Petroleum Co. v. State of Wisconsin in 1952,
the wellhead price of gas itself.
Interstate pipelines historically served as the wholesale merchants of gas, buying gas at the
wellhead from individual producers, aggregating supplies, transporting gas to market, and
reselling it to focal distribution companies (LDCs). Pipelines owned the gas they sold; they
were not in the business of transporting gas for others, and as such, the infrastructure they
developed served the merchant function. The interstate pipelines operated large gathering
networks drawing gas from thousands of wells. These fed into processing plants where gas
was stripped of hydrocarbons, water and liquids, and then to the long distance mainline
transmission systems that connected with the LDCs. Pipelines operated storage facilities near
markets to supplement winter gas supply and help balance pipeline flows.
As the principal natural gas merchants, pipelines exercised major control over the natural gas
industry. They alone bought gas for resale in interstate commerce.1 Pipelines purchased gas
under long term (20 year) contracts and resold the gas under long term "service agreements"
to LDCs as part of a "bundled service" that included in one price the cost of gas and all the
delivery services. (In rare instances pipelines sold directly to industrial plants. Transportation
services-as opposed to sales services-were even more rare.) Pipeline rates were based on
cost-of-service concepts and pipelines' profits were based on their net investment in capital
equipment (rate base).
This constituted a highly restrictive system that limited market entrants and, with regulated
prices for natural gas, led to widespread shortages of gas in interstate markets after the 1973
oil crisis.2 Congress responded with the Natural Gas Policy Act (NGPA) in 1978, which raised
interstate prices for new gas production. These higher-priced supplies led to an oversuppiy of
natural gas (known as the "natural gas bubble"). Downstream pressure to open up the system
eventually led to partial gas price deregulation in 1985 and subsequently to full deregulation in
1989.3
11n the terminology of the FERC, the initial purchase of gas from the producer by the pipeline was the
"first sale," with the "resale" being the sale of this gas to the LDC.
2 The shortages occurred when pipelines could not secure enough interstate supply at regulated prices
and curtailed deliveries in several interstate markets. The intrastate markets in Texas and Louisiana
where gas prices were not regulated continued to have sufficient supply.
3 In the interim, the gas market went on a roller coaster ride of high prices in the early 1980s, encouraged
by NGPA's high ceiling prices for new production; this led to a contraction in the market exacerbated by
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The 1980s saw other trends affecting the industry. The most important was the simultaneous
emergence of an unregulated spot market after 1985 and the growth of independent gas
marketers in the spot market. In this new, unregulated spot market, customers could buy gas
from producers and the newly emerging marketers at prices significantly lower than regulated
pipeline supplies. The pressure from LDCs and end use customers to access this market led
FERC to promulgate Orders 380 and 436 (see Exhibit 1), aimed at promoting pipeline
transportation services. With their customers turning to the spot market, pipelines' merchant
activities suffered since they were locked into long term take-or-pay contracts with producers at
prices above the spot market. Order 636 was aimed in part to finally resolve the so called
take-or-pay crisis.
A second important development in the gas industry was the inauguration in 1990 by the New
York Mercantile Exchange (NYMEX) of the first gas futures contract, centered on Henry Hub in
south Louisiana. Futures trading has had a dramatic impact on gas markets. Futures provide
a mechanism for price discovery and risk management and increase the number of
participants in the market.
Property seen, FERC Order 636 was one of several developments that revolutionized the gas
industry. The importance of the Order lies in how it aligned regulation to the evolving industry
and established a framework for a workably competitive gas market.
Exhibit 1
Legislative and Regulatory Actions Leading to a Competitive Gas Market
Action
Natural Gas Policy Act (1978)
FERC Order 380 (1984)
FERC Orders 436/500 (1985-1987)
Natural Gas Wellhead Decontrol Act
(1989)
FERC Order 636 (1992)
Significance
Passed in response to gas shortages, began
price rationalization and deregulation. Led to
excessive gas prices in the early 80's.
Allowed LDC's to escape minimum bill
obligations to their pipelines, which provided the
opportunity to acquire spot market gas;
exacerbated pipelines' take or pay problems.
Initial attempt at forcing pipelines to provide
transportation services and to resolve take or
pay problems.
Fully decontrolled wellhead gas prices as of
January 1, 1993.
Restructured gas industry
the 1982 recession, and a long period of gas supply excess and low prices from which the industry is only
now recovering.
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B. Order 636
FERC Order 636 made a number of technical changes to the regulation of interstate pipelines
under the Natural Gas Act. These are summarized in Exhibit 2. In the main, Order 636 made
three significant changes to the pipeline industry:
• Pipelines were forced to give up their merchant function and become solely
transporters of gas. Transportation had to be on a non-discriminatory basis-open
access—and unbundled from other pipeline services, principally storage.
• Pipeline rates were to be straight fixed variable rate (SFV) design with all fixed
costs in the demand charge and only variable costs in the commodity charge.
Rates could be discounted. This gave capacity holders clear price signals on the
costs of transportation and related services.
Exhibit 2
Order 636 Changes
Interstate gas pipelines must provide open access transportation service that is "unbundled"
from other services. Customers must be able to purchase gas storage, balancing services,
and whatever sales service the pipeline continues to provide, separate from pipeline
transportation. The transportation service provided must be equal for all customers.
Most interstate pipelines must provide "no notice" firm transportation service to customers
who want it. This service allows the customer to call on a certain level of transportation
capacity without the traditional nomination lead time. To provide this service the pipelines
that had owned or contracted for storage service retained part of their storage capacity
rather than offer all of the capacity as a separate unbundled service. ^___
Interstate pipelines must provide firm shippers on downstream pipelines with access to
capacity on upstream pipelines that the downstream pipeline has under contract. This is
intended to prevent discriminatory blockage of use of the downstream pipeline capacity.
Firm shippers on interstate pipelines are allowed to offer reserved pipeline capacity that
they do not need to other shippers. This capacity release mechanism requires posting the
idle capacity on an electronic bulletin board and awarding the capacity to the highest
bidder.
Firm shippers must be allowed to change their gas receipt points, allowing for multiple and
changing sources of supply.
Interstate pipelines are allowed to charge market-based rates for their remaining sales
service.
Generally, interstate pipeline transportation rates must use a straight fixed-variable rate
design. This rate structure recovers a significant amount of pipeline costs through charges
for the reservation of pipeline capacity (the fixed component), and the remainder of costs
on the amount of gas actually flowed through the pipe (the variable component). Some
flexibility is allowed to mitigate the detrimental financial effects that straight fixed-variable
rates have on some customer classes.
Interstate pipeline tariff provisions must not interfere with the establishment of market
centers and gas supply pooling areas.
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• Capacity holders could resell unutilized capacity to other shippers, creating a
secondary market in transportation capacity. The price of capacity was market
determined, but could not exceed the pipelines' as-billed rate.
When these changes are combined with the growth of the spot market in gas, the
development of the NYMEX gas futures contract, and the growth in the number of market
players (see next section below), the results have been the emergence of a far more dynamic
gas industry. In the next section, the paper addresses its structure and operations in the post-
Order 636 environment.
C. General Structure and Operation of the Gas Industry Today
1. Production and Consumption
The size of the US gas market has. varied over the years, but on average it consumes about
20 trillion cubic feet (Tcf) annually.4 The major gas producing regions of the US are shown in
Exhibit 3. The largest producing market is the Gulf Coast, on shore and off shore Texas and
Louisiana. Other major regions include West Texas, the Mid-Continent, and the Rockies.
Coal production is found in the Appalachians and the Black Warrior (Alabama) gas producing
regions. The Appalachians account for about 3 percent of total production, about 600 billion
cubic feet (Bcf). Production from onshore Alabama, mainly the Black Warrior basin totals
about 174 Bcf. The US imports about 10 percent of total consumption from Canada, mainly
from Alberta. Small amounts of liquefied natural gas ("LNG") are imported from North Africa,
mainly to provide peaking capacity in the Northeast in winter.
The largest gas consuming markets are located in the south and east as shown in Exhibit 4.
Out of a total market of 19.7 Tcf in 1995, the West South Central, including the
Texas/Louisiana petrochemical and power markets, accounted for 28 percent. The East North
Central region, including Chicago and the Great Lakes market, was the second largest
consuming region at 19 percent of the total. The Middle Atlantic region, including New York
and Pennsylvania, was the third largest consuming area with 12 percent of the national total.
Exhibit 5 illustrates gas consumption by sector for the US Census regions east of the
Mississippi (where 66 of the 79 mines the EPA has identified as candidates for methane
recovery are located).
Exhibit 6 shows US gas consumption from 1970 through 1995 by consuming sector. In 1995
the industrial sector accounted for 44 percent of total gas consumed. Residential consumption
was next in importance in 1995 at 25 percent. The electric utility and commercial uses
followed at 16 and 15 percent, respectively.
4 Gas is measured in several ways. In terms of volume it is measured in cubic feet-Ccf (100 cubic feet);
Mcf (thousand); Bcf (billion); Tcf (trillion). In terms of heat content it is measured in British thermal units
(Btus) and therms (100,000 Btus). One Dth (decatherm or 10 therms) equals one million Btus (MMBtu).
One Mcf equals about 1.03 MMBtu.
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Exhibit 3
Major Natural Gas Basins
Permian
East
Texas
Appalachia
Black Warrior
Texas/Louisiana
Gulf Coast
Exhibit 4
1995 US Gas Consumption by Census Region
(Bcf)
Source: U.S. Department of Energy, Energy Information Administration / Natural Gas Annual 1995
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Exhibit 5
1995 US Gas Consumption East of the Mississippi
RositJtntial
Commercial
Industrial
Electric
Source U.S Dep»rtment of Energy. Energy I
Exhibit 6
US Natural Gas Consumption by Sector
_ 5000
5
1970 1975 1980 1985 1990 1995
•Industrial —•—Residential Electric Utilities —^-Commercial
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Industrial consumption is heavily influenced by economic conditions and the prices of
competing fuels. Similarly, the electric generation market is highly dependent on power
demand and alternative fuel pricing. Firms in these sectors are more likely to purchase gas
from marketers and producers than from LDCs. Residential and commercial demand is highly
seasonal and almost entirely served by LDCs. The typical residence consumes 125 Mcf per
year; industrial and electric power plants can consume tens of thousands of Mcf per day.
One of the major characteristics of the gas market is the seasonality of consumption, due to
the fact that gas is used substantially as a heating fuel. Exhibit 7 illustrates the seasonal
nature of demand by end user sector. Note the winter peaking usage characteristic of
residential and commercial demand and the "counter seasonality" of industrial and electric
utility demand.
Exhibit 7
Seasonal Gas Demand by Sector
(1995)
2,500
1.500 -
3 1.000 -
Feb Mar Apr May Jun Jul Aug Sep Oct
O industrial O Residential O Commercial • Elec Gen.
Dec
Source: DOE-EIA Natural Gas Monthly. March 1 996
This suggests a major opportunity for gassy coal mines located near market areas: the
potential use of coal mines as sites for natural gas storage. The emerging gas market has
created a premium for storage located near markets, as LDCs and end users search for ways
to create stability of supply without signing long-term commitments to pipelines. Mines offer
another advantage. Because they are simply large underground spaces, they hold the
potential for high injection and deliverability rates, which is also an advantage in today's
market. It means that customers can have quick turnaround during periods of high demand.
The Leyden coal mine in Jefferson County, Colorado (operated by Public Service of Colorado)
has a total working gas capacity of 3 Bcf, but can accept high rates like 130 MMcfd of injection
and, even higher, 185 MMcfd of peak withdrawal.
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2. Major Players in the Industry Today-Who Does What
Gas is handled by a variety of players on its path from the well to the consumer. The players
and their roles are described below.
Producers explore, drill and operate gas wells. There
are thousands of gas producers in the US which draw
from 284,000 wells (in addition to gas from oil wells).
The average gas well produces 184 Mcf per day. The
largest produce in the thousands of Mcf per day. In the
Appalachian producing region, where most of the
promising coal bed methane coal mines are located, the
average well produces only 14 Mcf per day. The largest
producers in the US include the major integrated oil
companies-Exxon, Shell, Chevron, et. al. At the other
end of the spectrum are the small producers, the "mom
and pop" operators, often with a small number of wells.
Key Industry Players:
Producers-produce and sell gas
Gatherers-move gas to market
Processors-prepare gas for sale
Pipelines-longdistance
transporters
Marketers-middleman merchants
UDCs*-retai!ers
End users-consumers
In many cases the producer, or operator or the gas well, will not own the mineral rights to the
gas in the ground. In these cases, the producer makes royalty payments to the owner. The
typical royalty payment is one-eigth of the value of production. Thus, if the wellhead value is
$2.00 per MMBtu, the owner would receive about $0.16 per MMBtu. The bulk of the price
goes to the producer who bears the expense and risk of drilling and marketing the production.
Gathering pipelines collect gas from the wells and deliver it to processing plants. Large
producers own their gathering systems. Other gathering systems are owned by independent
operators or by pipeline affiliates (although in recent years most of these have been spun off
as independent companies). The gathering pipeline rates are generally not regulated, unless
the gathering system is part of an interstate pipeline or operates across state boundaries or
offshore, which subjects it to FERC jurisdiction. For smaller producers, gathering charges can
be significant where gatherers have local monopolies.
Processors take the gas from the field, remove impurities and, in some cases, strip out liquids
(which are sold as natural gas liquids-NGLs-in a separate market) and prepare the gas to
meet certain specifications required in the market. Natural gas is generally sold when it leaves
the processing plant, or at the point it is delivered into the interstate pipeline grid. Producers
should be aware that some volume of gas will be sacrificed in processing, and that an
additional volume will be used as fuel in compressor stations (or simply lost) as it travels
through the interstate pipeline system. Historically, the trip from the wellhead to the interstate
delivery point has cost about 10 cents/Mcf.
The merchant function of the pre-Order 636 pipelines has been taken over by the marketers.
Most gas today is sold through gas marketers, who aggregate supplies and "repackage" them
with transportation and pricing terms for resale to LDCs or end-users. Marketers also provide
services to producers that may include financing, hedging, gathering, processing or other
related support activities. Most of the major producers act as their own marketers and may
also market gas for others. Smaller producers usually sell gas to marketing companies since
they do not have the resources to market their gas. Marketers will also provide an array of
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similar services to their resale customers. Many pipelines and LDCs have marketing affiliates
who act as independent marketing companies. There are hundreds of marketing companies
of various sizes and specialties. The largest independent companies include Enron and
Natural Gas Clearinghouse (NGC). Some marketers specialize geographically or work only
with certain kinds of end users. The Eastern Group is a regional marketer active in the
Appalachians.
Interstate pipelines provide transportation services under standard tariffs (general operating
rules and rates kept on file at the FERC) and individual transportation agreements. The
contract agreement to transport gas will be between the shipper and the pipeline. The shipper
of a block of gas can be anyone in the chain of sale with a transportation agreement with the
pipeline or pipeline capacity owner—the producer/production owner, the marketer, the LDC, or
the gas end-user. (In most cases, producers are not the shippers of record; rather who they
sell to will hold the transportation rights.)
The contract path is described in the transportation service agreement and names a receipt
and a delivery point. The pipeline takes the gas from the receipt point, typically a numbered
meter station/tap in the producing zone at the outlet of a gathering system or processing plant,
and redelivers the gas to a delivery point, usually an LDC's citygate meter station. Some
pipelines have delivery points at end user facilities where these are large industrial or electric
power plants.
Besides transportation, pipelines also provide storage services or market hub services.
(These are increasingly provided by independent operators as well.) Storage provides winter
peak service and shorter term storage services (often referred to as "parking"). The latter allow
shippers to match flows with market demand and to respond to price swings — i.e., store when
the market price falls and withdraw when the price rises. Most storage is in depleted gas fields
and requires wells and compressors to inject the gas into the field. The rates of withdrawal
depend on the permeability of the field. These fields are suitable for winter peaking storage.
Mined caverns, usually salt domes, are used for short term storage and have the desired
characteristic of quick injection and withdrawal. These storage services command a premium
in the market.
Market hubs are places where several pipelines meet and where gas is transferred between
pipelines. Major hubs include Henry Hub in Louisiana, Katy Hub near Houston, AECO-C in
western Canada, Lebanon near Dayton, Ohio, and Leidy in Pennsylvania.
LDCs, being the primary retailers of natural gas, receive gas from the interstate pipelines
through their citygates (LDCs may take deliveries through more than one citygate), step down
the pressure, and redeliver or resell gas to customers on their distribution systems. LDC
services for their distribution territories are provided under general rate and service schedules
which are filed with the state public utilities commission. Virtually all LDCs provide
transportation-only services to large end users. In several states, public utility commissions
are considering programs to allow direct sales from marketers to residential and small
commercial end users, with the LDC providing only transportation service.
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3. Scope of Current Regulation
Economic, environmental and safety regulation of the gas industry is divided between a
number of state and federal agencies. The regulations that affect gas transportation and sales
are described below.
The basic regulatory structure remains the same under FERC Order 636. FERC still regulates
interstate pipelines. Pipelines must have FERC certificates of public convenience and
necessity in order to construct new facilities, and these certificates give pipelines the right of
eminent domain. FERC no longer regulates producer prices or oversees production issues,
but it still must approve any changes to pipeline rates and services. Pipelines' services and
rates are described in the tariff which is kept on file at FERC in Washington, D.C. FERC also
responds to requests for investigation of wrongdoing by interstate gas pipelines. Examples of
problems that require investigation are allegations of discriminatory behavior with respect to
transportation access, pricing, or rules that discriminate against classes of shippers and
construction activities not in accordance with certificates. FERC can order pipelines to
interconnect with shippers' facilities.
State public utility commissions regulate the rates and services of LDCs. Although regulations
imposed on LDCs vary among the individual states, the types of jurisdiction are similar to those
of FERC. Construction expenditures, tariffs, and customer complaints are regulated and
resolved at the state level. Some state regulators are experimenting with incentive rate
designs intended to reward both the LDC and its customers for cost savings.
A producer selling gas will encounter regulatory requirements when dealing with transporters,
both pipelines and LDCs. For pipelines, this may involve FERC review of a pipeline's
proposed addition of a receipt point if it involves new construction and any additional capacity
needed (such as adding pipeline or new compression) to support a new source of supply.
Pipeline transportation rates and LDC transportation services are subject to regulatory reviews
by FERC and state commissions, but absent an ongoing rate case in which the shipper
chooses to participate, there is little involvement with regulatory authority.
The major areas of future regulatory change are in the state regulation of LDCs. Several
states are in the process of considering rules to allow small residential and commercial
customers of LDCs to have the same level of access to interstate sales and transportation
services as do the large industrial customers. In essence this would do to the LDCs what
Order 636 has done to the pipelines.
D. Gas Prices and Gas Price Formation
The key to realizing opportunities from coal mine methane is understanding the dynamics of
gas prices. This section focuses on interstate wholesale gas prices—that is the price of gas
received by producers and paid by LDCs or large end users. Retail prices behind the citygate
are noted to provide a more complete picture.
Natural gas prices are denominated in dollars per Mcf, MMBtu or Dth. (LDC rates are
expressed in cents per therm.) Prices are quoted at major market hubs (where several
pipelines converge); at LDC citygates, or at pipeline pooling points (the outlets of large
processing plants or where a number of gathering systems deliver gas to a mainline pipeline).
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The national marker price for gas is quoted at Henry Hub, Louisiana, where the NYMEX
futures contract is traded. Recent prices have averaged about $2.30 per MMBtu, but over the
course of a year can swing from under $2.00 to over $5.00. The price of gas quoted at
locations other than Henry Hub will differ from Henry Hub due to transportation differentials
and local market conditions. Weekly gas journals, the internet, and traders provide spot
market prices at most any market location on a daily basis. The Henry Hub spot price is listed
daily in the Wall Street Journal, as are the various gas futures and options contracts.
As a general matter, gas prices in the spot market are determined for the following month
during "bid week," which is about a 10-day period when buyers and sellers make their deals
before nominations for deliveries are due to the pipeline transportation managers. Bid week
generally extends to the first day or two of the new month, as traders clean up details—that is,
search for gas supplies for packages of gas that were supposed to be delivered. Weekly and
daily prices (so-called aftermarket prices) diverge from the monthly bid week prices depending
on supply and demand.
The fundamental aspect of the post-Order 636 market is that gas prices are formed in a largely
transparent way by the forces of supply and demand; producers are price takers. Weather
greatly influences demand for gas, since gas is used primarily as a heating fuel. The prices of
competing fuels, like residual fuel oil, also influence demand for gas, but to a somewhat lesser
extent. Supply is set by the available productive capacity and is subject to short term
disruptions like hurricanes or freezing weather in the Gulf Coast.
The price received by the producer is referred to as the "netback" or what is left after all
transportation and related charges have been netted out. Prices in the different producing
markets are related to each other by the transportation differentials between producing and
consuming markets. This is illustrated as follows and in Exhibit 8:
• The marginal producer in the Gulf Coast sells gas for around $1.75 per MMBtu.
Delivery to the New York market costs about $0.50 per MMBtu, yielding a price at
the New York citygate of $2.25. This sets the market price in New York.
• A Canadian producer selling into New York must meet this price, but his
transportation costs are $1.35 from Alberta, yielding a netback from New York of
only $0.90. If the Canadian producer could find another market with higher
netbacks, he would sell his gas to those markets. (As in fact many do in diverting
Canadian gas to California and Chicago.)5
• At the same time, an Appalachian producer who is closer to the New York market
faces a transportation cost of $0.35 per MMBtu, and can realize a netback price of
$1.90 per MMBtu.
5 Recent pricing patterns in fact suggest that Alberta production is setting the price in the Chicago
market, since the delivered cost of gas to Chicago is lower than the cost in the Gulf Coast plus normal
transportation rates. This means Gulf Coast producers will direct their gas to the east coast until those
lines are filled.
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Exhibit 8
1995 National Gas Prices and Netbacks
Note: All prices are in S/MMBtu;
Supply area prices are delive red-to-pipeline; market area prices are citygate
Source: Natural Gas Week. Natural Gas Daily
The result of netbacking on regional prices is illustrated in Exhibit 9. Gas delivered in the
Appalachian region-signified by the Columbia Broad Run price-commands a premium over
Henry Hub by the transportation differential between those two points. For the same reason,
the New York citygate price is higher than Broad Run. (Rockies prices have been significantly
lower due to the lack of transportation access out of the region and soft California demand.)
Exhibit 9 also illustrates the annual volatility in gas prices and underlying seasonality in prices.
Finally, retail gas prices charged by LDCs are the sum of the wholesale price and the
transportation and distribution margins allowed by state regulators as illustrated in Exhibit 10.
As shown, residential customers have paid the most for gas and the large, frequently dual
fueled, customers have paid the least. Exhibit 11 shows gas prices in the residential,
commercial, industrial and electric utility sectors for the US Census regions east of the
Mississippi.
14
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Exhibit 9
Regional Gas Prices
1994 1995 1996 Average 94-95
New York $2.45 $2.24 $3.34 $2.68
Henry Hub S2.00 $1.72 $2.76 $2.16
Rockies $1.62 $1.08 $1.51 $1.40
Columbia Broad Run $2.23 $1.80 $3.07 $2.37
».•>*
Source: Natural Gas Week
i
i*
Henry Hub New York Rockies Columbia Broad Run
ann-0496-6684500100-regoasl.pre
Exhibit 10
US Historical Gas Prices by Sector
1970
1975
1980
1985
1990
1995
Residential —•—Commercial Industrial -*^- Electric Utility
15
Mail code 3
1200Pennsylvan: = NW
; DC
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Exhibit 11
Gas Prices by Sector for Regions East of the Mississippi, 1995
MA SA ENC
BResidential BCommercial • Industrial DElectric Utility
ESC
Implications for Coal Mine Methane
Order 636 and other changes in the gas industry suggest the following for coal mine methane
producers:
• Producers have a wide array of potential markets and opportunities to sell gas.
Most gassy coal mines are near major gas consuming regions and markets. Mine
operators can sell gas through marketers or directly to LDCs or end users in these
markets.
• In today's gas market, coal mine methane producers have a greater opportunity to
tailor gas sales deals to meet their needs and operating characteristices.
• Transportation access should not be a barrier to reaching markets with the
secondary market in capacity and general open access rules. The cost of making
physical interconnections and other related pipeline capacity additions will be a
factor in individual situations.
• Producers of coal mine methane should be generally well positioned to receive
higher netbacks than producers more distant from high value consuming markets.
Individual situations may vary with local gathering and pipeline capacity conditions.
• The seasonal demand for gas, the pricing patterns of gas, and the high cost of
pipeline capacity (see the next section) highlight the value of storage in the gas
market. Using abandoned coal mines for storage would provide a market for coal
mine methane and a valuable service in the gas market.
The next section describes the elements of typical gas sales and transportation contract
agreements.
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III. HOW NATURAL GAS IS MARKETED TODAY
Order 636 has fostered creativity in deal making by increasing the variety of gas sales and
transportation arrangements. This section addresses key elements of the gas sales process.
The entire gas sales path-from wellhead to end user-involves one or more sales contracts
and one or more transportation agreements. The market forces of supply and demand set the
overall price level. The prices that individual producers realize will vary from the overall price
level depending on terms of the sales contract, location relative to the supply and consuming
markets, and transportation agreement terms.
A. Elements of Gas Sales Contracts
Gas sales contracts occur between any two parties for any period of time. The parties can
include producer/marketer, producer/LDC, producer/end user or marketer/LDC and
marketer/end user. (With today's active futures and derivatives market, one can also buy gas
from several of the major banking and commodity organizations, that is, a Morgan Stanley or
Bankers Trust can sell gas.) Gas sales contracts have certain standard contract terms that
define how the sale will be executed:
• Quantity. The quantity of gas sold is expressed in two ways: daily volume and total
contract volume. Total contract volume is equal to the daily volume multiplied by
the number of days in the contract. The daily volume is expressed as a maximum
daily quantity (MDQ), usually denominated in million Btus per day (MMBtu/d).
• Minimum purchase obligation. This is the minimum amount of gas that a buyer
must take over the term of the contract, expressed on a daily and annual basis.
Since buyers' requirements may fluctuate, having the ability to reduce takes is
desirable.
• Term. The term of a contract can be as short as a day or it can run for several
years. The spot market for gas, described by the Henry Hub price, refers to sales
of gas for one month or less. Intermediate term contracts are for periods of up to
18 months. Long term contracts of 18 months or longer are increasingly rare.
• Delivery/take obligation. The terms of the delivery can be firm or less than firm. A
firm delivery obligation means that the supplier is obligated to deliver the MDQ over
the term of the contract. Failure to do so will invoke penalties under the contract.
Less than firm can mean "as available* or obligate the supplier to make "reasonable
efforts" to meet the delivery obligation. Another permutation is that delivery will be
guaranteed for all but 10 or 15 days over the year. The companion obligation on
behalf of the buyer will be the obligation to take all gas delivered under the contract.
Failure to do so can lead to penalties and relieve the supplier of any obligation to
continue in the contract. Shippers need to have the terms spelled out. "Secondary
Firm" capacity means that there are recall rights on the volumes. Only "Primary
Firm" customers have rights to the gas at all times.
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• Delivery point The delivery point is the location where gas is delivered to the
buyer. Delivery can be made to the point of interconnection between the pipeline
and the gathering system, the outlet of a processing plant, a market hub, a city gate
or any point in between. This is largely determined by the owner of the capacity on
the pipeline. A producer will seldom hold capacity on a mainline pipeline all the way
to market.
• Force majeure. These define the "acts of God" that relieve the parties of their
obligations under the contract. These provisions sometimes also include "market-
out" terms that will allow either party to exit the agreement if market conditions
change dramatically.
• Warranties. These further define the level of obligation that the parties have to
perform under the contract. A typical "soft" warranty is a "best efforts" obligation,
which requires the parties to use best but not heroic efforts to assure performance-
i.e., that the gas is delivered. For a producer, this may include an agreement to
replace gas not delivered with other gas or other fuels. Some contracts wil! be
warranted with the reserves themselves: if the supplier fails to perform, the buyer
can take over the reserves. Corporate warranties put the producing corporation's
balance sheet behind the contract, which, depending on the quality of the corporate
assets, can be the strongest warranty.
The price of gas will also be included in the contract and is typically expressed in reference to
a commonly followed market price or as a formula. This is the area of greatest variety in
contract terms. Some typical pricing provisions include the following:
• Fixed price. A short term contract-one month or less-will have a fixed price for a
fixed quantity which will be related to the current spot market price of gas. Longer
term contracts rarely have fixed prices over the entire term of the contract. Where
fixed prices are offered in longer term arrangements, they usually are at a
substantial premium to the market to cover the risks inherent in fixing prices.
• Floating spot price. Some contracts will allow the price to float with the market
price of gas at a specific location as reported in the various industry weekly
newsletters: Natural Gas Intelligence, Gas Daily, Natural Gas Week, and Inside
FERC's Natural Gas Market Report, for example. Often the price will be quoted as
a discount or premium to a specific location reported price. For example, the price
may be Henry Hub plus $0.10/MMBtu or Henry Hub minus $0.05/MMBtu. The
premium or discount will be determined by a combination of transportation rate
differentials between the point of delivery and reported market price location and by
competitive pressures. These contracts will have an automatic monthly or weekly
price redetermination. Usually two publications are cited in a gas contract to protect
the parties in the event that one publication might fold.
• Base price with escalator. Often contracts will set the price for a base period and
then the price will escalate thereafter monthly or annually by some escalation factor.
This can be a fixed percent, but is more often a market index of gas prices such as
the NYMEX futures on the last day of trading for each month's contract, or an index
based on the reported prices in one or more of the newsletters. Some contracts will
18
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escalate with an economic indicator such as the Consumer Price Index or Producer
Price Index or an index tied to a specific industrial production measure. Escalators
can also be based on the price of other commodities such as oil, coal or electricity.
In one contract the escalator was tied to the change in the price of orange juice.
• Ceiling and floor prices. Longer term contracts may have provisions limiting the
range of escalation. Thus the contract may have a ceiling which limits the upside of
the contract. Producers may require higher base prices for such contracts.
Similarly, contracts may have a floor to protect the downside. Collars refer to
contracts that limit the range of escalation on the upside and downside.
• Two part prices. These prices will include a fixed price component and a floating
price component. The fixed price acts as a reservation charge and may be
expressed as either a fixed amount or some multiple of the MDQ payable monthly
regardless of how much gas is taken. The floating price may resemble the spot
market price of gas. Such contracts are available where the buyer needs flexibility
in the amount of gas taken over the term of the contract and are more common in
longer term contracts.
While basic gas prices received by sellers are the netbacks discussed in the earlier section,
the terms of the sales contract will influence the final price that the seller receives. The price
of gas will be higher with stronger delivery obligations (firm supply, strong warranties) on the
part of the seller; with lower minimum take levels (allowing the buyer to swing on the seller's
supply); with a longer term; with lower price escalation; and with more value-added service
(see below). The price of gas will be lower with weaker delivery obligations; with higher
minimum takes; with market-based pricing; with shorter term, and with pure commodity sales.
The value-added aspect of gas sales comes with tailoring a gas supply to the needs of an
individual customer. This can include anything that prices the gas in terms other than pure
spot market—such as tying it to the price of the buyer's product (e.g. orange juice or electricity).
It can also include pairing firm delivery obligations with giving a buyer greater flexibility in daily
takes. Value added service can include special billing and gas accounting services.
Such value added services are beyond the capabilities of most small producers, mainly
because doing so involves greater risk or is staff intensive. On the other hand, these are the
services that marketers provide. For these services, marketers will receive a markup on the
base gas price. This markup varies with the level of service and how the marketer bundles his
gas. For a straight sale of the commodity, the markup may be $0.02 to $0.05 per MMBtu.
When a marketer can bundle the gas with a transportation contract, backed up by storage that
would give him the ability to deliver the gas during the winter peak when supply and
transportation is tight, the margin can be enomnous-$1.00 or more per MMBtu over what the
producer receives. However, to receive such returns, marketers frequently take significant
risks. These risks are managed by the application of portfolio strategies (balancing risks
across a variety of suppliers and customers) and active hedging in the financial derivatives
markets.
Use of financial derivatives has expanded greatly in the last five years with the increase in gas
price volatility. The principal derivatives used in gas markets are futures contracts and options
on futures. These are publicly traded and quoted daily in major newspapers. (The standard
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contract is for 10,000 MMBtu per day delivered at Henry Hub for one month.) Producers can
use these instruments to fix forward prices and reduce their risk. Indeed, many gas supply
contracts today have prices floating at the monthly closing NYMEX contracts or some near
equivalent spot market index. Producers will then use derivatives to "shape" the final price
they receive in order to match their own risk preferences. Other derivatives instruments
include over-the-counter swaps, offered by financial institutions and commodities traders.
Swaps allow parties to a contract to exchange cash flows with a third party in order to lower
risk.
B. Elements of Gas Transportation Agreements
The fundamental objective of Order 636 was to provide open access transportation to all
potential shippers on a non-discriminatory basis and to allow a secondary market in unutilized
pipeline capacity to develop. As a consequence, pipeline transportation capacity can be
acquired directly from a pipeline or indirectly in the secondary market through the "capacity
release" mechanism.
1. Direct Transportation Service
Entering into a long term capacity contract with an interstate pipeline is a substantial financial
commitment with ongoing operational obligations. On some new pipelines constructed in the
West, producers hold the long term contracts; however, most of the capacity on interstate
pipelines is in fact controlled by LDCs with long term contracts. It is rare for a small producer
to own pipeline capacity because of the cost. Transportation agreements will have the
following key elements:
• Capacity. Expressed as MDQ and denominated in MMBtus or Mcf per day.
• Receipt and delivery points. These define the endpoints of a capacity holder's
ownership of capacity: the receipt point (where the transportation begins) and one
or more citygate delivery points where the pipeline's obligation ends. Capacity
holders have firm rights to the capacity between these points, as well as firm rights
through the receipt and delivery points themselves. (These points are a shippers
primary receipt and delivery points. Shippers can use alternative or secondary
receipt or delivery points, but they will not have first priority of shipment there.)
• Rates. The transportation agreement will refer to the tariff on file at FERC for rates.
These are two part, demand/commodity rates. The monthly demand charge
recovers the cost of the capacity and is multiplied by the MDQ. This is a fixed
monthly cost regardless of the amount of gas that is shipped. The commodity
charge covers the variable costs of transportation, usually a few cents per MMBtu
plus the fuel charge, which is taken in kind and is expressed as a percent of
throughput. Many long distance pipelines have either zoned rates or mileage based
rates, where the total cost depends on distance. Some pipelines that resemble web
systems will have postage stamp rates, one price for shipment anywhere on the
system, regardless of distance. The major pipelines serving the Appalachian
region-Columbia Gas Transmission (Columbia) and Consolidated Natural Gas
(CNG) are the latter. Their rates are as follows:
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Columbia FTS: Demand = $8.80/MMBtu/mo; Commodity = $0.0267/MMBtu; Fuel =
2.41%
CNG FT: Demand = $5.72/MMBtu/mo; Commodity = $0.0371/MMBtu; Fuel = 2.0%
• Operational rules. The transportation agreement will again refer to the tariff for
operational rules. These cover nominating procedures (each month and each day,
shippers must inform the pipeline of how much gas they propose to transport);
scheduling (daily flow rates); overrun penalties (for taking too much gas from the
pipeline); balancing penalties (shippers are required to balance receipts with
deliveries daily and monthly). The pipeline agreement will also cite shippers'
obligations when the pipeline issues Operational Flow Orders (OFOs).
• Special provisions. Occasionally, a shipper will request special services from a
pipeline that protect the shipper from incurring onerous penalties described above.
This can include an Operational Balancing Agreement that allows the pipeline to
resolve imbalances among multiple shippers. In addition, the agreement may also
cover the construction of a new interconnection between a gathering line and the
pipeline, or a new delivery interconnect. In these cases the cost of the new facilities
will either be paid in advance by the shipper or through a rate adder.
In evaluating the cost of transportation, a shipper takes into account the large fixed costs
associated with contracting for firm transportation capacity. For example, the fixed charges for
10,000 MMBtu per day of firm transportation capacity on Columbia and CNG would run
$88,000 and $57,200 respectively per month, which equates to $1,056,000 and $686,000 per
year. Thus it is clear that in order to justify this kind of expenditure, a shipper has an incentive
to use the capacity at a high load factor-that is to fill it up all the time.
Exhibit 12 presents the load factor calculations for Columbia's FTS service and CNG's FT
service.6 The 100 percent load factor assumes the capacity is fully employed; while the 70
percent load factor calculation presents the cost of firm capacity per MMBtu of throughput
when the capacity is not used 30 percent of the time. Because of this cost structure, it is
incumbent on the capacity holder to purchase the minimum capacity necessary. But since gas
use is so seasonal, there is almost always excess capacity available outside the winter
months. Hence, many shippers seek released capacity transportation service.
Exhibit 12
Pipeline Tariff Rates, $/MMBtu
Pipeline
Columbia Gas Transmission
CNG Transmission
100% Load Factor Rate
$0.32 plus 2.41% fuel
retention
$0.23 plus 2% fuel retention
70% Load Factor Rate
$0.44 plus 2.41% fuel
retention
$0.31 plus 2% fuel retention
6 FTS refers to "Firm Transportation Service" while FT stands for "Firm Transportation" service.
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2. Released Capacity
Because of the seasonal nature of gas demand and the inherent uncertainties of the market,
and because pipeline capacity is expensive, capacity holders with excess capacity on hand
release unused capacity to other parties to recover some of their fixed costs. The original
capacity holder remains liable for the demand charges due the pipeline. In addition, all of the
same pipeline tariff terms and operating rules apply to the secondary shipper over the term of
the contract with the primary shipper.
Released capacity is usually sold for a specific period of time which can be daily, monthly or
longer. Often released capacity will have a "call back" provision, that allows the capacity
owner to take back the capacity for a period of time when demand is high. As such, released
capacity that is subject to call-back may not be described as firm transportation service and
anyone shipping under such released capacity may be subject to interruptions. However,
where the released capacity agreement has no callback provision, it is as reliable as any direct
purchased capacity from the pipeline.
The cost of released capacity is expressed as a one-part rate that recovers for the primary
shipper some portion of his demand charges and all of the variable costs. Under FERC rules,
the price of released capacity is capped at the pipeline's underlying transportation rate
expressed at the 100 percent load factor. Seldom do primary shippers recover their full costs
of capacity, since by its definition such capacity is surplus. In addition, service that is subject
to recall rights is less firm and thus less valuable. February released capacity on Columbia
and CNG have gone for $0.23 and $0.18 respectively. Last July, Columbia capacity was
trading around $0.028 per MMBtu and CNG for $0.0153 per MMBtu. Compare these rates
with the 100 percent load factor in Exhibit 12. As is shown, the rates are much lower.
There are two ways to acquire released capacity: by pre-arrangement with the capacity holder
and via bidding on the pipeline's electronic bulletin board (EBB). A shipper may make a deal
directly with a capacity holder. If the agreed price is below the maximum rate, the terms of the
deal must be put on the EBB where it is subject to bidding from other shippers. If none offer
the same price and terms, then the release is consummated. Alternatively, some primary
capacity holders post available capacity on the EBBs which others can acquire at the posted
prices.
One aspect of released capacity should be noted. Capacity holders can only release capacity
between their contracted primary receipt and delivery points. Replacement shippers who wish
to receive and deliver gas at these primary receipt and delivery points will have the functional
equivalent of firm service. However, most use intermediate points of receipt and delivery. As
such their receipt and delivery points will not have the same degree of firmness, since other
primary users may use these points. This is a consideration when selling gas using released
capacity or selling gas to someone who is using released capacity.
3. Operational Issues
The day to day business of transporting gas can be complicated and involved. A significant
aspect of meeting contract obligations requires attention to the details of delivery. Many
producers and all marketers have large transportation/exchange departments to manage daily
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business of moving gas and tracking the gas accounts. This is part of the value added service
they provide customers. The major operational issues are the gas quality requirements,
nominating and scheduling, balancing, and managing under occasional operational flow
orders. These are addressed below.
a. Gas Quality
Natural gas must have certain physical characteristics before gas pipelines and LDCs will
accept the gas into their systems. These conditions are designed to prevent an increment of
gas from contaminating the system supply. These requirements are described in the General
Terms and Conditions portion of the pipeline tariff. Gas supply contracts require the producer
to meet the quality requirements. The quality specification for CNG and Columbia are shown
in Exhibit 13.
Exhibit 13
Examples of Gas Quality Specifications
Specification
Hydrogen sulfide content
Sulfur content
Particulates content
Carbon dioxide content
Nitrogen content
Oxygen content
Heating value
Columbia Gas Transmission
0.25 grain max per 100 cubic ft.
20 grains per 100 cubic ft.
Must be commercially free of
particulates
Not specified
Not specified
Not specified
Min. of 969 Btu per cubic ft.
CNG Transmission
0.25 grain max per 100 cubic ft.
20 grains per 100 cubic ft.
Must be free of dust, gums, dirt,
and objectionable odors
Max. 3 percent by volume
Max. 3 percent by volume
Max. 0.2 percent by volume
Within range of 967 to 1 100 Btu
per cubic ft.
The gas industry standard water content is 7 Ibs. per Mmcf. Methane from unmined coal
seams frequently meets these requirements or can be made to with minimal processing
(dehydration is the most common). On the other hand, typical gob gas composition includes
the following elements:
Oxygen
Nitrogen
Carbon dioxide
Water vapor
between 2 and 8 percent
between 9 and 26 percent
between 3 and 9 percent
saturated
Gob gas will require in most cases more processing to prepare it for market.
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b. Nominations and Scheduling
Pipelines operate on a monthly and daily cycle for scheduling the flow of gas volumes through
the pipeline system. Approximately one week before the start of the month shippers must
submit their nominations for how much gas they plan to flow on a daily basis for that month,
expressed as MMBtu or Mcf per day. The nominations must indicate the receipt point and
delivery points for the gas being shipped. Pipelines then schedule the flows and indicate
priorities of delivery. Any shipper with firm capacity will have the top priority. Other shippers
will be scheduled behind the firm shippers, assuming capacity is available. Shippers are
required to submit gas at roughly equal rates throughout the day.
Daily nominations are also required throughout the month. Usually by 10 AM each day,
shippers are required to notify the pipeline of expected deliveries for the next day. Daily
nominations allow the pipeline and shippers to adjust throughput to account for variability in
demand. Many pipelines allow intra-day nominations for the same reason.
c. Balancing
Pipelines require that shippers' receipts equal their deliveries of gas. Due to the variability of
demand and supply over the course of a month, receipts and deliveries can get out of balance,
which can have ripple effects throughout the system and cause operational problems. To
prevent these imbalances from becoming unmanageable, the pipelines have instituted tariff
rules that limit the size of supply/delivery imbalances that are allowed. Tolerances of five to
ten percent are typically allowed without penalty. Some pipelines apply penalties to daily
imbalances and others allow daily imbalances to be summed over a period of a month,
allowing corrections to be made during the month to avoid a monthly net imbalance. Cash
settlements are made monthly on imbalances for both the price of the gas and any penalty
charges. If the shipper has a positive imbalance, the pipeline will pay a discounted price for
the positive imbalance volume. If the shipper has a negative imbalance, the pipeline will
charge the shipper a premium price for the imbalance volume. Shippers can use scheduling to
control monthly imbalances. For example, daily overages early in a month can be
counteracted by nominating underages in subsequent days.
d. Operational flow orders
Pipelines use operational flow orders (OFO) to maintain gas flows as best they can in
emergency situations. Given several hours notice, a pipeline can order shippers to inject and
withdraw specified volumes of gas at specified receipt and delivery points on the pipeline.
OFO's are not to be used as a routine daily tool to manage gas flows.
OFOs can adversely affect a producer's ability to meet contract obligations. In such cases, the
shipper may turn to other supplies or use special operational balancing agreements with the
pipeline to maintain deliveries.
C. Creating Value with Contract Terms
As the first section of this paper points out, coal mine operators, like any gas producer, will be
price takers for the methane they produce, because market forces determine the underlying
24
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price of gas. Producers, however, can receive above (or below) market prices depending on
the specifics of the particular supply arrangements they enter into. The price received for gas
will be determined by the value of the gas in the particular market where it is sold (geographic
and sectoral), by the value that the specific sales terms create, and by the additional services
the seller provides.
1. High Value Markets
Value is added in several ways. The first has been mentioned in the previous description of
netback pricing: location can "create" value for the producer fortunate enough to be located
near consuming markets that are also a considerable distance from other gas supplies. The
northeast is an example.
Similarly, there are high value market sectors. Specific kinds of customers will have a higher
value than others. Customers that use higher cost alternatives to gas (e.g., low sulfur residual
fuel oil, distillate fuel, propane, electricity) will value gas more than those who can use lower
cost alternatives (high sulfur residual fuel oil, coal). This points to certain industrial and electric
generating uses as well as to residential and commercial users. Historically, the latter have
been restricted to purchasing gas from LDCs.
Some states are experimenting with unbundling the services that LDCs provide to their
customers, similar in concept to what Order 636 did with interstate pipeline services. This
includes New York and Vermont in the northeast and Maryland in the mid-Atlantic. Such
unbundling will open up new high value, profitable markets to producers and marketers. A
number of aggressive marketers are positioning themselves for this market, with the intent of
becoming national brand name providers of natural gas.
The costs of reaching high value markets are high. While selling to LDCs may only require
responding to requests for proposals or some minimal marketing effort (including, however,
establishing credit worthiness as a prerequisite) reaching end users can be a substantial
undertaking. Aiming towards these markets will involve substantial sales and contract
management efforts. More important, however, is the necessary investment in pipeline
capacity, storage and other delivery mechanisms that involve substantial costs in financial and
personnel resources.
2. Tailoring Contract Terms
Another way many producers and marketers distinguish their gas product is by developing
contract terms that create additional value for the buyer. These terms can include the
following:
• Pricing. Sellers can create a higher value gas supply by tailoring the pricing terms
to the needs of the customers. This can include providing fixed prices for a period
or matching the price movement to the product value of the customer (as is done
with some electric power plants where the price of gas will be tied to the price of
electricity in the power pool in order to guarantee the customer's power plant will be
dispatched). Such arrangements create value by shifting risk to the producer.
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Where the producer can tolerate this risk, this can yield higher prices and higher
returns. Marketers are especially well equipped to manage these risks.
• Delivery/take variability. Buyers will pay a premium for the right to vary the level of
takes from a supplier. Some suppliers, therefore, offer "swing" contracts that
impose no minimum take obligations on buyers. Again, this places the supplier at
risk since he must lay off the gas not taken to other buyers. In the alternative, the
supplier may have a storage contract that allows him to divert untaken gas to
storage for withdrawal later.
• Firm supply/price. Some buyers may value a firm gas supply at a known price.
That is, the buyer knows the gas will always be there at either a previously arranged
price or at a widely known market price, such as the spot price for a specific locale.
• Long term supply. Guaranteed supply for a long term can provide additional value
in that it provides some supply certainty and lower transaction costs.
As noted in several instances above, most of these contract terms for adding value require the
supplier/producer to take on additional risk-either market risk or commodity risk. The financial
markets provide more or less effective ways to manage these risks-at a cost. Marketers
manage these risks by using portfolio techniques to balance their obligations and exposures,
in addition to making widespread use of derivatives. Finally, to be able to provide some of the
delivery guarantees, suppliers have to have other physical and contractual assets in pipeline or
storage capacity to effect these contract terms.
3. Value-added from Bundling Gas with Other Services
Pipelines prior to Order 636 were able to reap monopoly profits by bundling gas with delivery
services. Order 636 directed pipelines to unbundle their services to allow buyers to purchase
separately only those services they wanted. Marketers and others have been able to generate
greater profits by rebundling gas with delivery services particularly with storage and firm
pipeline capacity.7 A producer or supplier who controls pipeline or storage capacity during the
winter peak in New York, for example, will be able to realize a significantly higher price than in
the Gulf Coast. The value in this instance is the gas-cum-delivery capability. Suppliers can
provide several kinds of bundled services, all of which require the ability to get gas to a market
that is in short supply because of delivery bottlenecks.
• Peak or winter service. A supplier will provide firm gas delivery during the peak
demand period, requiring the supplier to have delivery capabilities.
• Balancing services. A supplier will take over gas balancing obligations and will
provide volumes necessary to meet imbalance corrections.
• Management services. A supplier will provide all gas accounting, billing and other
"back-room" services.
7 Bundling by marketers is not necessarily monopolistic since there are many marketers competing on
generally the same footing as opposed to a single pipeline serving a given market.
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• Btu service. A supplier will guarantee that the buyer receives the necessary Btus to
meet his equipment needs. This may involve providing gas, coal, oil, or propane
interchangeably, on short notice.
• Back-up or stand-by services. The supplier will be the provider of last resort to
guarantee deliveries where guarantees are needed.
• Financial services, price guarantees. Increasingly, the large suppliers provide
financial hedging services to customers. This will include executing and managing
futures and options positions or providing price/commodity swaps. Such risk
management is becoming an increasingly valuable capability.
• Creative bundling. There have been some very creative deals in recent years. One
marketer sold gas bundled with SO2 trading allowances.
In short, bundling requires a range of capabilities and assets. These are most often held by
marketers and the larger producers.
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IV. STRATEGIES FOR COAL MINE METHANE
This paper has described in broad terms how the natural gas market operates. Today's gas
market is largely a result of the regulatory changes that have occurred under FERC Order 636.
From the standpoint of the gas producer-whether from a coal bed or more conventional
settings-this has resulted in market-based pricing, a greater access to the market, and wider
opportunities to market gas to secure the highest value for production, including through the
use of risk management tools.
The advantage that a coal mine operator can have relative to conventional gas producers is
that drilling and related methane drainage costs may have to be borne in many cases. With
the cost of gas wells being sunk costs, the profitability of marketing the methane will depend
on the price recieved relative to the incremental costs of preparing the gas for market.
Coal bed methane production in advance of mining can also improve mining profitability. It has
been shown that methane drainage prior to mining improves mine productivity. Reducing
methane content in the coal seam minimizes gas seepage into the mine that would require
suspension of minining operations until the gas was vented. Producing the coal bed methane
reduces gas outs and improves overall mine productivity. A developer can market the
enhanced productivity benefits to the mine.
The prices producers of coal mine methane will receive will depend on the quality and reliability
of the gas produced, the location of the gas relative to competing supplies, and the extent to
which the mine operator can create value through the addition of related services and
bundling. Thus four broad options are available to producers from coal mines:
• Partner with a gas producer to develop and market the methane from a coal mine in
exchange for royalty payments. Because coal mine operators are not in the gas
business, in most cases they will find it advantageous to allow a gas producer to
develop the methane potential and take the marketing risk. The mine owner would
receive a royalty for all gas developed and sold. Typical royalties for gas production
are one-eighth of the wellhead value of the gas (after all gathering, processing
costs have been subtracted from the sales price). Some coal mine operators
receive between three-sixteenths to one-quarter royalties. The higher royalties may
be due to the fact that in some cases, wells for methane production are already in
place. Higher royalty shares may be negotiated with greater participation by the
mine operator. The major issues involved with such arrangements involve
coordinating gas and coal production, safety issues, and mine management.
• With the contracting and pricing flexibility that is characteristic of the market today,
mine operators may be in a better position to sell output consistent with their
operational requirements. Thus, variability in gas production from coal mines may
not preclude the marketability of the methane, although it may reduce the price to
the mine operator.
• Actively produce and market methane as a commodity. Especially where a mine
already has wells and gathering systems in place, it may be more advantageous to
directly sell methane to aggregators (marketers or LDCs) rather than accept a
royalty payment. The price that a coal mine methane producer would receive would
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be the netback to the region of the coal mine gas production. For an Appalachian
producer, this may mean the Columbia Appalachian price or the CNG South Point
price. For mines further west, the price could be a Lebanon or Chicago price. (It is
possible that the final price received would be a discount off the regional price to
account for localized transportation.)
The cost of marketing gas in this way would be any costs associated with getting
the gas into the transmission system, including gathering and the cost of
interconnection. Inteconnection costs are generally modest, depending on the
pressure of the pipeline that must be tapped into. Hot taps (taps made into a line
under pressure) typically cost a few thousand dollars for a low pressure (300 psi),
small diameter system, to over $100,000 for a large diameter high pressure system.
This strategy assumes that the buyer would own the mainline transportation
capacity.
Such a strategy would still allow a producer to develop special contract terms or use
derivatives to hedge risk or create more pricing certainty. If the price received from
this approach meets a producer's investment criteria, this would be the lowest cost,
least risky approach.
Acquire pipeline capacity to the market. This more aggressive strategy is suitable
for larger producers and could be accomplished by acquiring capacity directly from
the pipeline or indirectly through the secondary market. Having pipeline capacity
can do two things: get the producers' gas to a market more accessible to many
more buyers and provide a greater certainty of supply to buyers. Having the ability
to deliver gas to a major hub would provide greater opportunities for sales at
prevailing market prices. Having gas bundled with capacity, particularly nearer
markets, will allow producers at times to capture higher prices. The major additional
cost of this option is the cost of securing pipeline capacity. There will be additional
marketing costs to manage the capacity and sales.
Become more like a gas marketer. For larger producers of coal mine methane,
acting as a gas marketer in providing a variety of services related to gas (and
possibly coal) is another option. Several opportunities suggest themselves:
=> Some coal mines may have special opportunities to provide a total Btu type
service that would include the provision jointly of coal and gas. Such Btu
deals involve more typically gas/oil/propane, since these fuels can be used
interchangeably in some applications. Coal mine operators could provide
joint coal and gas services in some cases to nearby power producers for use
in both baseload and peaking units.
=> Some gas marketers have acquired SO2 allowances to bundle with gas
supply to enhance the value of the gas. Similar strategies can be followed
by coal bed methane operators, and expanded to include NOx or
greenhouse gas emissions reductions.
=> Where coal mine methane production is well situtated relative to markets
(i.e., both in terms of proximity and pipeline capacity availability), the mine
operator should be able to secure higher netbacks. As a general matter,
Appalachian production should receive higher prices than gas produced in
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the Gulf Coast or other gas producing areas. Typically, Appalachian
production commands a $0.20 per MMBtu premium over gas from the Gulf
Coast. Higher netback prices for coal mine methane will enhance mine
profitability. The prices that such production could command can be further
enhanced through providing special delivery and contract terms.
=> High deliverability gas storage-storage that allows rapid injection and
withdrawal-commands significant premiums in the market. Abandoned coal
mines can be used for such storage development. The proximity of such
storage to market areas would allow users of storage to receive higher
seasonal gas prices. Coal mine methane production can be used to fill or
provide some portion of the gas in storage.
While the opportunities of such arrangements for receiving higher returns would be greater, so
too would the costs of developing a marketing organization and investing in the necessary
infrastructure.
For any of these strategies, methane producers should employ creative contracting and pricing
strategies. These may involve special pricing terms, delivery assurances, and the like.
The opportunities available to methane producers are far greater than in the past. The
ultimate success of methane marketing ventures will depend on local conditions affecting the
cost of getting gas to market and the prices that the methane can command.
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