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Utlilities Deregulation
Utilities Deregulation

The Deregulation of Natural Gas

Regulation of the natural gas industry in the United States has historically been a tumultuous ride, resulting in dramatic changes in the industry over the past 30 or more years. This section will outline the major historical regulatory events related to the natural gas industry, and show how the current structure of the industry in the U.S. is the product of a long regulatory evolution.

Today, competitive forces are being relied upon more heavily to determine market structure and operation. However, this has not always been the case. Almost all aspects of the natural gas industry were regulated at one point - a situation which led to tremendous difficulties in the industry, including the natural gas shortages experienced in the 1970s. To learn more about the current regulatory environment, click here.

This section provides a timeline of important regulatory events regarding the natural gas industry. Click on the links below to skip ahead to later sections:

Click here to view a condensed timeline of important regulatory developments.

The Early Days of Regulation

The regulation of natural gas dates back to the very beginnings of the industry. In the early days of the industry (mid-1800s) natural gas was predominantly manufactured from coal, to be delivered locally, generally within the same municipality in which it was produced. Local governments, seeing the natural monopoly characteristics of the natural gas market at the time, deemed natural gas distribution a business that affected the public interest to a sufficient extent to merit regulation. Because of the distribution network that was needed to deliver natural gas to customers, it was decided that one company with a single distribution network could deliver natural gas more cheaply than two companies with overlying distribution networks and markets. However, economic theory dictates that a company in a monopoly position, with total control over its market and the absence of any competition will typically take advantage of its position, and has incentives to charge overly-high prices. The solution, from the point of view of the local governments, was to regulate the rates these natural monopolies charged, and set down regulations that prevented them from abusing their market power.

As the natural gas industry developed, so did the complexity of maintaining regulation. In the early 1900s, natural gas began to be shipped between municipalities. Thus natural gas markets were no longer segmented by municipal boundaries. The first intrastate pipelines began carrying gas from city to city. This new mobility of natural gas meant that local governments could no longer oversee the entire natural gas distribution chain. There was, in essence, a regulatory gap between municipalities. In response to this, state level governments intervened to regulate the new 'intrastate' natural gas market, and determine rates that could be charged by gas distributors. This was done by creating public utility commissions and public service commissions to oversee the regulation of natural gas distribution. The first states to do so were New York and Wisconsin, which instituted commissions as early as 1907.


The Beginnings of Federal Regulatory Involvement

With the advent of technology that allowed the long distance transportation of natural gas via interstate pipelines, new regulatory hurdles arose. In the same sense that municipal governments were unable to regulate natural gas distribution that extended beyond their areas of jurisdiction, the state governments were unable to regulate interstate natural gas pipelines. Between 1911 and 1928, several states attempted to assert regulatory oversight of these interstate pipelines. However, in a series of decisions, the U.S. Supreme Court held that such state oversight of interstate pipelines violated the interstate commerce clause of the U.S. Constitution. These cases, known as the 'Supreme Court Commerce Clause' cases, essentially stated that interstate pipeline companies were beyond the regulatory power of state-level government. Without any federal legislation dealing with interstate pipelines, these decisions essentially left interstate pipelines completely unregulated; the second regulatory gap.

However, due to concern regarding the monopoly power of interstate pipelines, as well as conglomeration of the industry, the federal government saw fit to step in to fill the regulatory gap created by interstate pipelines.

In 1935, the Federal Trade Commission issued a report outlining its concern over the market power that may be exerted by merged electric and gas utilities. By this time, over a quarter of the interstate natural gas pipeline network was owned by only 11 holding companies; companies that also controlled a significant portion of gas production, distribution, and electricity generation. In response to this report, in 1935 Congress passed the Public Utility Holding Company Act to limit the ability of holding companies to gain undue influence over a public utility market. However, the law did not cover the regulation of interstate gas sales. Click here to view the Public Utility Holding Company Act as it exists today.

The Natural Gas Act of 1938

In 1938, the federal government became involved directly in the regulation of interstate natural gas with the passage of the Natural Gas Act (NGA). This act constitutes the first real involvement of the federal government in the rates charged by interstate gas transmission companies. Essentially, the NGA gave the Federal Power Commission (the FPC, which had been created in 1920 with the passage of the Federal Water Power Act) jurisdiction over regulation of interstate natural gas sales. The FPC was charged with regulating the rates that were charged for interstate natural gas delivery, as well as limited certification powers. The NGA specified that no new interstate pipeline could be built to deliver natural gas into a market already served by another pipeline. In 1942, these certification powers were extended to cover any new interstate pipelines. This meant that, in order to build an interstate pipeline, companies must first receive the approval of the FPC.

The rationale for the passage of the NGA was the concern over the heavy concentration of the natural gas industry, and the monopolistic tendencies of interstate pipelines to charge higher than competitive prices due to their market power. While the NGA required that 'just and reasonable' rates for pipeline services be enforced, it did not specify any particular regulation of prices of natural gas at the wellhead.

To learn more about the Natural Gas Act, click here.

The Phillips Decision - Wellhead Price Regulation

As mentioned, the NGA instituted no specific regulatory oversight of sales of natural gas from producers to the pipelines: wellhead prices were unregulated. However, in Supreme Court cases during the early 1940s, it was determined that wellhead prices were subject to federal oversight if the selling producer and the purchasing pipeline were affiliated companies. However, the FPC contended that if the natural gas producer and pipeline were unaffiliated, natural market forces existed that would keep wellhead prices competitive.


In 1954, however, this all changed with the Supreme Court's decision in Phillips Petroleum Co. v. Wisconsin (347 U.S. 672 (1954)). In this decision, the Supreme Court ruled that natural gas producers that sold natural gas into interstate pipelines fell under the classification of 'natural gas companies' in the NGA, and were subject to regulatory oversight by the FPC. This meant that wellhead prices - that is, the rate at which producers sold natural gas into the interstate market - would be regulated much the same as natural gas that was sold by interstate pipelines to local distribution utilities.

The Phillips decision had a complicated and far-reaching effect on the natural gas industry. In regulating wellhead prices, the FPC instituted a traditional 'cost-of-service' rate making determination. This system of setting rates relied on the cost of providing the service, rather than the market value of that service. This meant that prices were set to allow companies to charge prices high enough to cover the actual costs of producing natural gas, plus a 'fair' profit. Where regulating pipelines had been possible with this method due to the relatively small number of interstate pipeline companies, the large number of different natural gas producers meant that regulating producers was an extreme administrative burden for the FPC. Three eras of producer regulation ensued each with its own difficulties, until finally wellhead price control culminated in the natural gas shortages of the 1970s.

From 1954 to 1960, the FPC attempted to deal with producers and their rates on an individual basis. Each producer was treated as an individual public utility, and rates were set based on each producer's cost of service. However, this turned out to be administratively unfeasible, as there were so many different producers and rate cases that a tremendous backlog developed at the FPC. For example, in 1959, there were 1,265 separate applications for rate increases or reviews, the FPC was only able to act on 240 cases.

Due to this enormous backlog, the FPC in 1960 decided to set rates based on geographic areas. The U.S. was divided into five separate producing regions, and the FPC set rates for all wells in a particular region. The FPC set interim ceiling prices based on the average natural gas contract prices paid during 1959-1960 for a particular area. The FPC intended on using these interim ceiling prices until it could determine a 'just and reasonable' rate that it could apply to all natural gas sales from a particular region. However, the process for determining area wide rates took much longer and was much more difficult than anticipated, and by 1970 rates had been set for only two of the five producing areas. To make matters worse, for most of the areas, prices were essentially frozen at 1959 levels. The problem with determining rates for a particular area based on cost-of-service methodologies was that there existed many wells in each area, with vastly different production costs.

By 1974, the FPC had determined that area wide pricing was unfeasible. In an effort to find a system of wellhead price regulation that worked, the FPC adopted national price ceilings for the sale of natural gas into interstate pipelines. Realizing that the prior price ceilings, based on the cost-of-service approach, were much lower than the market value of interstate natural gas, the FPC set a national price ceiling of $0.42 per million cubic feet (mcf) of natural gas. Although this price ceiling doubled the prices that had been set during the 60s, it was still significantly less than the market value of the natural gas being sold. This system of price controls was in place until the passage of the Natural Gas Policy Act (NGPA) in 1978.

The Effects of Wellhead Price Controls 1954-1978

All three of these systems of price control discussed above had disastrous effects on the natural gas market in the United States. The artificially low price ceilings that had been set since 1954 had a number of outcomes in the market, coming to bear in the late 60s and 70s. Because the set rates for natural gas were below the market value of that gas, demand surged. The low prices of natural gas, as set by the FPC, meant that consumers were receiving good value for their money. This combined with the oil price surges experienced during the OPEC crisis in the 70s made natural gas an even more attractive fuel.

However, at the same time, there was little incentive for natural gas producers to devote the money required to explore for and produce new natural gas reserves. The selling price for natural gas was so low, it simply wasn't worth it for the producers. Producers also saw little incentive to search for new reserves. While the price at which they could sell interstate gas was fixed, the finding and development costs for establishing new reserves was as variable and unpredictable as ever. Producers saw little reason to engage in the exploration of new reserves that would cost more to find than they could be sold for under FPC wellhead price control.

However, the FPC only regulated producer wellhead prices for natural gas destined for the interstate market, leaving natural gas sales within the intrastate market relatively free of regulation. So while demand was surging nationwide, economic incentives did not exist for producers to ship their gas across state lines. They could sell it at a much higher price to intrastate bidders. In 1965, a third of the nations proved reserves were earmarked for intrastate consumers; by 1975, almost half of the proved reserves were committed to intrastate consumers.

This resulted in natural gas reaching consumers in the producing states, while the consuming states were experiencing natural gas supply shortages. In fact, in 1976 and 1977, many schools and factories in the Midwest were forced to close, due to a shortage of natural gas to run their facilities. Meanwhile, in the producing states, virtually no shortage was felt, due to the thriving intrastate market satisfying natural gas demand in these states. This led to certain 'curtailment' policies, advocated by the FPC and state utility regulators. These policies essentially set a schedule of priority, directing distributors and transporters to curtail supplies to certain customers who were deemed 'low priority'. However, these policies resulted in numerous litigation suits and FPC proceedings that turned out to be extremely complicated and time consuming. Realizing that something must be done at the federal level to reduce the strain of these supply shortages and demand surges, Congress enacted the Natural Gas Policy Act in 1978.

The Natural Gas Policy Act of 1978

In November of 1978, at the peak of the natural gas supply shortages, Congress enacted legislation known as the Natural Gas Policy Act (NGPA), as part of broader legislation known as the National Energy Act (NEA). Realizing that those price controls that had been put in place to protect consumers from potential monopoly pricing had now come full circle to hurt consumers in the form of natural gas shortages, the federal government sought through the NGPA to revise the federal regulation of the sale of natural gas. Essentially, this act had three main goals:

  • Creating a single national natural gas market
  • Equalizing supply with demand
  • Allowing market forces to establish the wellhead price of natural gas

This act attempted to accomplish these goals by statutorily setting 'maximum lawful prices' for the wellhead sale of natural gas, as well as breaking down barriers between intrastate and interstate natural gas markets. The FPC, the federal body with regulatory oversight of the natural gas market, was abolished and replaced with another body, the Federal Energy Regulatory Commission (FERC), under the Department of Energy Organization Act of 1977. Under the NGPA, FERC was given jurisdiction over the same areas as the FPC, with the exception of the import and export of natural gas, which was the jurisdiction of the new Department of Energy.

The ceiling prices for wellhead gas set by the NGPA differed from the system put in place under the NGA. Under the NGPA, increased price ceilings were set, intended to provide economic incentives for producers to search for and produce new natural gas. These ceilings and the mechanisms for increasing rates were set out in the statute, rather than relying on an independent body to determine these rates. Under the NGPA, some of the price ceilings that were set, specifically those affecting wellhead sales of new production, were designed to be phased out over a series of years, with the goal of complete deregulation of wellhead prices by 1985. However, the NGPA also dictated that gas brought into production before the passage of the Act would forever be subject to pre-NGPA regulations and price limits.

In addition to this new system for rate-setting, and the goal of deregulation of wellhead prices in seven years, the NGPA also served to break down the barriers between interstate and intrastate natural gas. Under the NGPA, FERC was authorized to approve the transportation of natural gas by an interstate pipeline on behalf of intrastate pipelines and local distribution companies - avoiding some of the regulatory hurdles that had created such a schism between interstate and intrastate markets.

The NGPA was a fundamental first step in deconstructing the regulatory problems that had been created by the NGA. The market response to the provisions of the NGPA included:

  • Pipelines, accustomed to gas shortages in the past years, signed up for many long-term natural gas contracts
  • Producers expanded exploration and production, drilling new wells and using the long-term sales contracts with pipelines to recover their investment
  • Average wellhead prices rose dramatically in the years following the NGPA
  • Prices for end-users increased, but were mitigated by the pipelines, which blended the cost of gas under new contracts with regulated gas under old contracts when selling their bundled product to their customers
  • Price increases led to decreased demand

Thus the NGPA allowed for more competitive prices at the wellhead. However, many members of the industry were unprepared for the corresponding drop in demand. The pipelines, used to the era of curtailment, were quick to sign up for long-term 'take-or-pay' contracts. These contracts required the pipelines to pay for a certain amount of the contracted gas, whether or not they can take the full contracted amount. While the NGPA did spur investment in the discovery of new natural gas reserves, the increasing wellhead price, mixed with the eagerness of pipelines to deliver as much natural gas as possible, led to a situation of oversupply.

Where it was necessary to curtail natural gas deliveries in the 60s and 70s due to high demand and low supply, the situation reversed in the period from 1980-85. Rising natural gas prices resulted in the dropping off of some of the demand that had built up when the price for natural gas was held below its market value. The resulting 'oversupply' scenario had a number of effects, including requiring the pipelines to make 'take-or-pay' payments to their suppliers despite no longer needing the amount of natural gas that had previously been contracted. Customers of the pipelines, purchasing a 'bundled' product - including the natural gas itself and the transportation of that gas - lobbied for reduced natural gas prices. In addition, pipeline customers sought the right to purchase their own gas from producers and transport it over the interstate pipelines, instead of purchasing the bundled product directly from the pipelines.

To learn more about the Natural Gas Policy Act, click here.

The Move towards Deregulation

The Natural Gas Policy Act took the first steps towards deregulating the natural gas market, by instituting a scheme for the gradual removal of price ceilings at the wellhead. However, there still existed significant regulations regarding the sale of gas from an interstate pipeline to local utilities and local distribution companies (LDCs). Under the NGA and the NGPA, pipelines purchased natural gas from producers, transported it to its customers (mostly LDCs), and sold the bundled product for a regulated price. Instead of being able to purchase the natural gas as one product, and the transportation as a separate service, pipeline customers were offered no option to purchase the natural gas and arrange for its transportation separately.

Several events led up to the 'unbundling' of the pipelines' product. In the early 1980s, noticing that a significant number of industrial customers were switching from using natural gas to other forms of energy (for example, electric generators switching from natural gas to coal), several pipelines instituted what they called Special Marketing Programs (SMPs). Essentially, these programs, which were approved by FERC, allowed industrial customers with the capability to switch fuels the right to purchase gas directly from producers, and transport this gas via the pipelines. However, SMPs were found discriminatory by the District of Columbia Circuit Court of Appeals in several 1985 cases. The court ruled that SMPs were discriminatory in that no other customer of the pipelines had the ability to purchase their own natural gas and transport it via pipeline. As a result of this, SMPs were eliminated on October 31, 1985.

However, the practice of allowing customers to purchase their own gas, and use pipelines only as transporters rather than merchants, was not abandoned. In fact, it became part of FERC policy to encourage this separation by way of Order No. 436.

FERC Order No. 436

In 1985, FERC issued Order No. 436, which changed how interstate pipelines were regulated. This order established a voluntary framework under which interstate pipelines could act solely as transporters of natural gas, rather than filling the role of a natural gas merchant. This order provided for all customers the same possibilities that the SMPs of the early 1980s had afforded industrial fuel-switching customers, thus avoiding the discrimination problems of the earlier SMPs. Essentially, FERC allowed pipelines, on a voluntary basis, to offer transportation services to customers who requested them on a first come, first served basis. The interstate pipelines were barred from discriminating against transportation requests based on protecting their own merchant services. Transportation rate minimums and maximums were set, but within those boundaries the pipelines were free to offer competitive rates to their customers. Although the framework established by Order 436 was voluntary, all of the major pipeline systems eventually took part.

FERC Order No. 436 had a number of immediate effects, including:

  • Pipelines began offering transportation service to all customers
  • Pipeline customers realized cost savings, in that the spot market prices of natural gas were much lower than the prices offered for natural gas by the pipelines (due to the long term 'take-or-pay' contracts that the pipelines were bound under)
  • The payments necessary under these 'take-or-pay' contracts increased for pipelines, as few customers were willing to purchase higher priced gas from the pipelines
  • Pipelines and producers were often forced into litigation to resolve issues surrounding 'take-or-pay' contracts

FERC Order No. 436 also had a number of longer term effects, including:

  • The transportation function became the primary function of pipelines, as opposed to offering the bundled merchant service
  • A wide variety of natural gas purchasing and transportation patterns and practices emerged due to the availability of choices to the end user
  • New pricing patterns emerged, known as 'netback' pricing, in which a reasonable price was set at the point of consumption, and that minus the cost of distribution, minus the cost of transportation, gave the 'netback' price to the producer at the wellhead

The movement towards allowing pipeline customers the choice in the purchase of their natural gas and their transportation arrangements became known 'open access'. Order No. 436 thus became generally known as the Open Access Order.

While the general thrust of Order 436 was upheld in Court, several problems arose regarding the 'take-or-pay' contracts under which the pipelines were still obliged. Given these problems, and under remand from the D.C. Circuit Court of Appeals, FERC issued Order No. 500 in 1987. This order essentially encouraged interstate pipelines to buy out the costly take-or-pay contracts, and allowed them to pass a portion of the cost of doing so through to their sales customers. The LDCs to which these costs were passed through were allowed by state regulatory bodies to further pass them on to retail customers. However, the open access provisions of Order No. 436 remained intact.

Open access to pipelines also spurred the first appearances of natural gas marketers. To learn more about natural gas marketing, click here.

The Natural Gas Wellhead Decontrol Act of 1989

As mentioned, under the NGPA, the deregulation of natural gas producers sale prices at the wellhead had begun. However, it wasn't until Congress passed the Natural Gas Wellhead Decontrol Act (NGWDA) in 1989 that complete deregulation of wellhead prices was carried forth. Under the NGWDA, the NGPA was amended and all remaining regulated prices on wellhead sales were repealed. As of January 1, 1993, all remaining NGPA price regulations were to be eliminated, allowing the market to completely determine the price of natural gas at the wellhead.

The NGWDA stated that 'first sales' of natural gas were to be free of any federal price regulations. The Act defined 'first sales' as the sale of gas:

  • To a pipeline
  • To a local distribution company
  • To an end user
  • Preceding the sale to any of the above
  • Determined by FERC to be a first sale

Excluded from falling under the definition of a first sale were any sales of gas by pipelines and local distribution companies, including interstate pipelines.

FERC Order No. 636

While FERC Order No. 436 made the unbundling of pipeline services possible, the establishment of transportation only services by a pipeline continued to be only voluntary. FERC Order No. 636 completed the final steps towards unbundling by making pipeline unbundling a requirement. Issued in 1992, the Order states that pipelines must separate their transportation and sales services, so that all pipeline customers have a choice in selecting their gas sales, transportation, and storage services from any provider, in any quantity. Order 636 is often referred to as the Final Restructuring Rule, as it was seen as the culmination of all of the unbundling and deregulation that had taken place in the past 20 years. Essentially, this Order meant that pipelines could no longer engage in merchant gas sales, or sell any product as a bundled service. This Order required the restructuring of the interstate pipeline industry; the production and marketing arms of interstate pipeline companies were required to be restructured as arms-length affiliates. These affiliates, under Order 636, could in no way have an advantage (in terms of price, volume, or timing of gas transportation) over any other potential user of the pipeline.

FERC Order No. 636 is the culmination of deregulating the interstate natural gas industry. Distilled to its main purpose, the Order gives all natural gas sellers equal footing in moving natural gas from the wellhead to the end-user or LDC. It allows the complete unbundling of transportation, storage, and marketing; the customer now chooses the most efficient method of obtaining its gas.

Order 636 also requires that interstate pipelines offer services that allow for the efficient and reliable delivery of natural gas to end users. These services include the institution of 'no-notice' transportation service, access to storage facilities, increased flexibility in receipt and delivery points, and 'capacity release' programs. No-notice transportation services allow LDCs and utilities to receive natural gas from pipelines on demand to meet peak service needs for its customers, without incurring any penalties. These services were provided based on LDC and utility concerns that the restructuring of the industry may decrease the reliability needed to meet their own customers' needs. The capacity release programs allow the resale of unwanted pipeline capacity between pipeline customers. Order 636 requires interstate pipelines to set up electronic bulletin boards, accessible by all customers on an equal basis, which show the available and released capacity on any particular pipeline. A customer requiring pipeline transportation can refer to these bulletin boards, and find out if there is any available capacity on the pipeline, or if there is any released capacity available for purchase or lease from one who has already purchased capacity but does not need it.

To learn more about FERC Order No. 636, click here.

To learn more about the structure of regulation as it exists today, and the effect that this regulation has on industry, click here

Benefits Of Energy Deregulation 
With energy deregulation, consumers have more freedom when choosing their energy providers. More energy providers throw their hats in the ring, meaning consumers do not have to depend on one particular company to meet their energy needs. This freedom of choice gives consumers power. They can choose one energy provider over another depending on various factors such as cheaper prices, better customer care, greener energy, and any other variable that affects them. Tied to this power to choose, is the next benefit, better quality services. With the field now open to new providers, there is a new sense of competition. This renewed competition is pushing energy companies to provide better quality services in an effort to attract and keep customers. Consumers can easily switch to an energy provider that offers the best service. Obviously, each provider would want to perform in all aspects of service provision. A third benefit is that energy deregulation would likely lower the cost of energy for consumers. When there was only one energy provider in the state, that provider determined what the cost of power would be. With the introduction of competitors, the cost of energy has decreased in the state. Most energy providers will price their services more reasonably so that they can secure customers rather than lose them to their competitors. Obviously, the biggest winner here is the consumer. Energy deregulation has helped businesses to lower their production costs. At the end of the day, this will translate into a larger net profit, which it can pass down to its customers in form of lower prices for goods and services. Energy deregulation has opened up the field to more energy providers, meaning more competition. As such, energy deregulation has helped consumers. Now, consumers can enjoy better and more reliable services at competitive prices. In addition, they have the power to choose one energy provider over another 

Natural Gas - From Wellhead to Burner Tip

The process of getting natural gas out of the ground, and to its final destination to be used, is a complicated one. There is a great deal of behind-the-scenes activity that goes into delivering natural gas to your home, even though it takes only the flick of a switch to turn it on. This section provides an overview of the processes that allow the natural gas industry to get their product out of the ground, and transform it into the natural gas that is used in your homes and in industry.

  • The Exploration section outlines how natural gas is found, and how companies decide where to drill wells for it.
  • The Extraction section focuses on the drilling process, and how natural gas is brought from its underground reservoirs to the surface.
  • The Production section discusses what happens once the well is drilled, including the processing of natural gas once it is brought out from underground.
  • The Transport section outlines how the natural gas is transported from the wellhead and processing plant, using the extensive network of pipelines throughout North America.
  • The Storage section describes the storage of natural gas, how it is accomplished, and why it is necessary.
  • The Distribution section focuses on the delivery of natural gas from the major pipelines to the end users, whoever they may be.
  • The Marketing section discusses the role that natural gas marketers play in getting the gas from the wellhead to the end user.

Please click on the links to the left to learn about how natural gas gets from deep underground, all the way to the burner tip!

Natural gas marketing
Natural gas marketing is a relatively new addition to the natural gas industry, beginning in the mid-1980's. Prior to the deregulation of the natural gas commodity market and the introduction of open access for everyone to natural gas pipelines, there was no role for natural gas marketers. Producers sold to pipelines, who sold to local distribution companies and other large volume natural gas users. Local distribution companies sold the natural gas purchased from the pipelines to retail end users, including commercial and residential customers. Price regulation at all levels of this supply chain left no place for others to buy and sell natural gas. However, with the newly accessible competitive markets introduced gradually over the past fifteen years, natural gas marketing has become an integral component of the natural gas industry. In fact, the first marketers were a direct result of interstate pipelines attempting to recoup losses associated with long term contracts entered into as a result of the oversupply problems of the early 1980s. To learn more about the history of natural gas regulation, click here.

Natural gas marketing may be defined as the selling of natural gas. In even looser terms, marketing can be referred to as the process of coordinating, at various levels, the business of bringing natural gas from the wellhead to end-users. The role of natural gas marketers is quite complex, and does not fit exactly into any one spot in the natural gas supply chain. Marketers may be affiliates of producers, pipelines, and local utilities, or may be separate business entities unaffiliated with any other players in the natural gas industry. Marketers, in whatever form, find buyers for natural gas, ensure secure supplies of natural gas in the market, and provide a pathway for natural gas to reach the end-user. It is natural gas marketers that ensure a liquid, transparent market exists for natural gas. Marketing natural gas can include all of the intermediate steps that a particular purchase requires; including arranging transportation, storage, accounting, and basically any other step required to facilitate the sale of natural gas.

Essentially, marketers are primarily concerned with selling natural gas, either to resellers (other marketers and distribution companies), or end users. On average, most natural gas can have three to four separate owners before it actually reaches the end-user. In addition to the buying and selling of natural gas, marketers use their expertise in financial instruments and markets to both reduce their exposure to risks inherent to commodities, and earn money through speculating as to future market movements.

To view statistics related to the selling and marketing of natural gas, including prices and volumes, click here.

In order to more fully understand the role and function of natural gas marketers, it is helpful to have an understanding of the basics of natural gas markets.

Natural Gas as a Commodity

Natural gas is sold as a commodity, much like pork bellies, corn, copper, and oil. The basic characteristic of a commodity is that it is essentially the same product no matter where it is located. Natural gas, after processing, fits this description. Commodity markets are inherently volatile, meaning the price of commodities can change often, and at times drastically. Natural gas is no exception; in fact, it is one of the most volatile commodities currently on the market. The graph below shows the

Natural Gas Volatility and Price Levels at Henry Hub
Source: Energy Information Administration, Office of Oil and Gas; based on Natural Gas Monthly publications

The price of natural gas is set by market forces; the buying and selling of the commodity by market players, based on supply and demand, determines the average price of natural gas. There are two distinct markets for natural gas: the spot market, and the futures market. Essentially, the spot market is the daily market, where natural gas is bought and sold 'right now'. To get the price of natural gas on a specific day, it is the spot market price that is most informative. The futures market consists of buying and selling natural gas under contract at least one month, and up to 36 months, in advance. For example, under a simplified futures contract, one could enter into an agreement today, for delivery of the physical gas in two months. Natural gas futures are traded on the New York Mercantile Exchange (NYMEX). Futures contracts are but one of an increasing number of derivatives contracts used in commodities markets, and can be quite complex and difficult to understand. To learn more about futures and other methods of buying, selling, and trading commodities, click here.

Major Natural Gas Market Hubs
Source: Energy Information Administration

Natural gas is priced and traded at different locations throughout the country. These locations, referred to as 'market hubs', exist across the country and are located at the intersection of major pipeline systems. There are over 30 major market hubs in the U.S., the principle of which is known as the Henry Hub, located in Louisiana. The futures contracts that are traded on the NYMEX are Henry Hub contracts, meaning they reflect the price of natural gas for physical delivery at this hub. The price at which natural gas trades differs across the major hubs, depending on the supply and demand for natural gas at that particular point. The difference between the Henry Hub price and another hub is called the location differential. In addition to market hubs, other major pricing locations include 'citygates'. Citygates are the locations at which distribution companies receive gas from a pipeline. Citygates at major metropolitan centers can offer another point at which natural gas is priced.

Physical and Financial Trading

There are two primary types of natural gas marketing and trading: physical trading and financial trading. Physical natural gas marketing is the more basic type, which involves buying and selling the physical commodity. Financial trading, on the other hand, involves derivatives and sophisticated financial instruments in which the buyer and seller never take physical delivery of the natural gas.

Like all commodity markets, the inherent volatility of the price of natural gas requires the use of financial derivatives to hedge against the risk of price movement. Buyers and sellers of natural gas hedge using derivatives to reduce price risk. Speculators, on the other hand, assume greater risk in order to profit off of changes in the price of natural gas. Some marketers who actively buy and sell in either the physical or financial markets are referred to as natural gas 'traders'; trading natural gas on the spot market to earn as high a return as possible, and trading financial derivatives and other complex contracts to either hedge risk associated with this physical trading, or speculate about market movements. Most marketing companies have elaborate trading floors, including televisions and pricing boards providing the traders with as much market information as possible.

Trading Floor at a Natural Gas Marketing Company
Source: NGSA

Physical Contracts

Physical trading contracts are negotiated between buyers and sellers. There exist numerous types of physical trading contracts, but most share some standard specifications including specifying the buyer and seller, the price, the amount of natural gas to be sold (usually expressed in a volume per day), the receipt and delivery point, the tenure of the contract (usually expressed in number of days, beginning on a specified day), and other terms and conditions. The special terms and conditions usually outline such things as the payment dates, quality specifications for the natural gas to be sold, and any other specifications agreed to by both parties.

Physical contracts are usually negotiated between buyers and sellers over the phone. However, electronic bulletin boards and e-commerce trading sites are allowing more physical transactions to take place over the internet.

There are three main types of physical trading contracts: swing contracts, baseload contracts, and firm contracts. Swing (or 'interruptible') contracts are usually short-term contracts, and can be as short as one day and are usually not longer than a month. Under this type of contract, both the buyer and seller agree that neither party is obligated to deliver or receive the exact volume specified. These contracts are the most flexible, and are usually put in place when either the supply of gas from the seller, or the demand for gas from the buyer, are unreliable.

Baseload contracts are similar to swing contracts. Neither the buyer nor seller is obligated to deliver or receive the exact volume specified. However, it is agreed that both parties will attempt to deliver or receive the specified volume, on a 'best-efforts' basis. In addition, both parties generally agree not to end the agreement due to market price movements. Both of these understandings are not legal obligations - there is no legal recourse for either party if they believe the other party did not make its best effort to fulfill the agreement - they rely instead on the relationship (both personal and professional) between the buyer and seller.

Firm contracts are different from swing and baseload contracts in that there is legal recourse available to either party, should the other party fail to meet its obligations under the agreement. This means that both parties are legally obligated to either receive or deliver the amount of gas specified in the contract. These contracts are used primarily when both the supply and demand for the specified amount of natural gas are unlikely to change or drop off.

The daily spot market for natural gas is active, and trading can occur 24 hours a day, seven days a week. However, in the natural gas market, the largest volume of trading occurs in the last week of every month. Known as 'bid week', this is when producers are trying to sell their core production and consumers are trying to buy for their core natural gas needs for the upcoming month. The core natural gas supply or demand is not expected to change; producers know they will have that much natural gas over the next month, and consumers know that they will require that much natural gas over the next month. The average prices set during bid week are commonly the prices used in physical contracts.

The Financial Market

In addition to trading physical natural gas, there is a significant market for natural gas derivatives and financial instruments in the United States. In fact, it has been estimated that the value of trading that occurs on the financial market is 10 to 12 times greater than the value of physical natural gas trading.

Derivatives are financial instruments that 'derive' their value from an underlying fundamental; in this case the price of natural gas. Derivatives can range from being quite simple, to being exceedingly complex. Traditionally, most derivatives are traded on the over-the-counter (OTC) market, which is essentially a group of market players interested in exchanging certain derivatives among themselves, as opposed to through a market like the NYMEX. Basic types of derivatives include futures, options, and financial swaps. To learn more about the basics of derivatives, click here.

Source: NGSA

There are two possible objectives to trading in financial natural gas markets: hedging and speculation. Trading in the physical market involves a certain degree of risk. Price volatility in the natural gas markets can result in financial exposure for marketers and other market players as the price changes over time. Trading financial derivatives can help to mitigate, or 'hedge' this risk. A hedging strategy is created to reduce the risk of losing money. Purchasing homeowner's insurance is a common hedging activity. Similarly, a marketer who plans on selling natural gas in the spot market for the next month may be worried about falling prices, and can use a variety of financial instruments to hedge against the possibility of natural gas being worth less in the future. Countless strategies exist to hedge against price risk in the natural gas market, including natural gas futures, derivatives based on weather conditions to mitigate the risk of weather affecting the supply of natural gas (and thus its market price), etc. To learn more about the basics of hedging in the natural gas market visit the New York Mercantile Exchange here.

Financial natural gas markets may also be used by market participants who wish to speculate about price movements or related events that may come about in the future. The main difference between speculation and hedging is that the objective of hedging is to reduce risk, whereas the objective of speculation is to take on risk in the hope of earning a financial return. Speculators hope to forecast future events or price movements correctly, and profit through these forecasts using financial derivatives. Trading in the financial markets for speculative purpose is essentially making an investment in financial markets tied to natural gas, and financial speculators need not have any vested interest in the buying or selling of natural gas itself, only in the inherent underlying value that is represented in financial derivatives. While great profits may be made if the expectations of a speculator prove correct, great losses may also be incurred if these expectations are wrong. While the instruments used for hedging and speculation are the same, the way in which they are used determines whether or not they in fact reduce, or increase, the risk of losing money.

Now that some of the basics of the natural gas market have been covered, we can examine the function of natural gas marketers.

Marketers in Action
Source: NGSA

Natural Gas Marketers

Any party who engages in the sale of natural gas can be termed a marketer, however they are usually specialized business entities dedicated solely to transacting in the physical and financial energy markets. It is commonplace for natural gas marketers to be active in a number of energy markets, taking advantage of their knowledge of these markets to diversify their business. Many natural gas marketers are also involved in the marketing of electricity, and in certain instances crude oil.

Marketers can be producers of natural gas, pipeline marketing affiliates, distribution utility marketing affiliates, independent marketers, and large volume users of natural gas. A recent study of the origins of natural gas marketers found that 27 percent of the top 30 natural gas marketers in 2000 were entities spun off from interstate pipeline companies. An equal percentage was made up of entities affiliated with local distribution companies. About 30 percent of the top natural gas marketers were originally affiliated with producers, and entities formed from large volume natural gas consumers comprise 6 percent. Finally, independent, newly formed entities represent 10 percent of top natural gas marketers.

Marketing companies, whether affiliated with another member of the natural gas industry or not, can vary in size and the scope of their operations. Some marketing companies may offer a full range of services, marketing numerous forms of energy and financial products, while others may be more limited in their scope. For instance, most marketing firms affiliated with producers do not sell natural gas from third parties; they are more concerned with selling their own production, and hedging to protect their profit margin from these sales.

There are basically five different classifications of marketing companies: major nationally integrated marketers, producer marketers, small geographically focused marketers, aggregators, and brokers.

The major nationally integrated marketers are the 'big players', offering a full range of services, and marketing numerous different products. They operate on a nationwide basis, and have large amounts of capital to support their trading and marketing operations. Producer marketers are those entities generally concerned with selling their own natural gas production, or the production of their affiliated natural gas production company. Smaller marketers target particular geographic areas, and specific natural gas markets. Many marketing entities affiliated with LDCs are of this type, focusing on marketing gas for the geographic area in which their affiliated distributor operates. Aggregators generally gather small volumes from various sources, combine them, and sell the larger volumes for more favorable prices and terms than would be possible selling the smaller volumes separately. Brokers are a unique class of marketers in that they never actually take ownership of any natural gas themselves. They simply act as facilitators, bringing buyers and sellers of natural gas together.

All marketing companies must have, in addition to the core trading group, significant 'backroom' operations. These support staff are responsible for coordinating everything related to the sale and purchase of physical and financial natural gas; including arranging transportation and storage, posting completed transactions, billing, accounting, and any other activity that is required to complete the purchases and sales arranged by the traders. Since marketers generally work with very slim profit margins, the efficiency and effectiveness of these backroom operations can make a large impact on the profitability of the entire marketing operation.

In addition to the traders and backroom staff, marketing companies typically have extensive risk management operations. The risk management team is responsible for ensuring that the traders do not expose the marketing company to excessive risk. Top-level management is responsible for setting guidelines and risk limitations for the marketing operations, and it is up to the risk management team to ensure that traders comply with these directives. Risk management operations are quite complex, and rely on complex statistical, mathematical, and financial theory to ensure that risk exposure is kept under control. Most large losses associated with marketing operations occur when risk management policies are ignored or are not enforced within the company itself.

The marketing of natural gas is an integral part of the natural gas supply chain. Natural gas marketers ensure that a viable market for natural gas exists at all times. Efficient and effective physical and financial markets are the only way to ensure that a fair and equitable commodity price, reflective of the supply and demand for that commodity, is maintained.

To learn more about what factors affect the supply and demand for natural gas, and an overview of natural gas markets in the United States, click here.

Natural gas is an extremely valued resource in our society. It is not surprising, then, that the natural gas industry generates a great deal of commerce, in the United States and worldwide. This section is intended to provide an overview of the business side of the natural gas industry, including statistics and figures about the industry.


  • The Industry and Market Structure section provides an overview of the structure of the natural gas industry, and the functioning of the natural gas market.
  • The Natural Gas Demand section discusses the factors that affect the demand for natural gas, including trends that are expected to provide for steadily increasing demand for natural gas.
  • The Natural Gas Supply section discusses the supply of natural gas reaching the market, and what factors affect the ability of producers to bring natural gas to the market.

Please click on the links to the left to delve into the big business side of natural gas!


About Electric & Natural Gas Deregulation

Regulation of public utilities by federal and state governing bodies dates back to the 1930s and was instrumental in forming the vast infrastructure we have today. Without the oversight and a guarantee of financial return on investment, we would not have had the money or rules needed to build the reliable systems that now span the continental U.S. Through the years, there have been a number of regulations (Federal Power Act of 1935, Public Utilities Holding Company Act of 1935, Natural Gas Act of 1938, Public Utilities Regulatory Policy Act of 1978, Energy Policy Act of 2005, et. al.) that have helped shape the relationship between utilities and their customers. Though the rules have changed over time, allowing deregulation of the natural gas and electric industries, two things remain constant. Federal regulation of interstate commerce is performed by the Federal Energy Regulatory Commission (FERC), and regulation of intrastate affairs is handled by the respective state Public Utilities Commissions.

The electric and natural gas industries are very similar in their structure and operation. Each has three distinct components (i) the commodity SUPPLY portion (ii) the long-distance TRANSMISSION of the commodity and finally (iii) the local DISTRIBUTION of the commodity to our homes and businesses. For many years, your local utility handled all three phases of the business in a "vertically integrated" manner. After decades of growth, construction, and addition of market participants, it was determined that competition could safely be introduced via deregulation of the natural gas and electric industries. To address the needs of a competitive environment, those three phases of utility operations were separated, rearranged and in some cases sold off to other companies or regional transmission organizations.

Supply - Transmission - Distribution

Deregulation of the electric and natural gas markets came on the heels of deregulation in the airline, trucking and telephone industries. Those industries underwent drastic changes during periods of expansion and contraction. Today, airfare and phone rates adjusted-for-inflation, are considerably less than they were in the 1980s and many new products and services exist. In deregulation of the natural gas and electric industries, only the price of the commodity supply has been opened to competition. This means consumers in many states, who are served by investor-owned utilities, are now able to choose who supplies their natural gas and/or electricity. The transmission and distribution of natural gas and electricity is not open to choice, and the price for those services continues to be set by state and federally approved tariffs. The push for deregulation of natural gas and electric came when the FERC decided it should limit its authority to wholesale transactions. This move cleared the way for individual states to determine if and how they should allow retail price competition.

The table below shows which commodities have been deregulated for each state. In deregulated states, retail consumers are able to shop for a supplier other than their utility. The utility continues to deliver the natural gas or electricity regardless of who is chosen to supply the commodity. The utility also continues to maintain the distribution system, respond to emergencies and read meters. The reasons for choosing an alternate supplier can be many, but most consumers tend to seek (i) lower prices (ii) price stability not available with variable utility rates (iii) longer-term contracts or (iv) energy produced by environmentally friendly sources. Please note that not all areas of a deregulated state may be open to competition, or active at all times. Please contact Independent Energy Consultants with questions about deregulation of electric and natural gas in your particular market.

Electric and Natural Gas Deregulation by State With Links to State Utility Commissions



State Commodity State Commodity State Commodity State Commodity State Commodity
DE EL & NG ME EL & NG NJ EL & NG SD NG* EL Electric
FL NG MD EL & NG NM EL & NG TN NG NG Natural Gas
GA NG MA EL & NG NY EL & NG TX EL & NG * Available only to the Largest Consumers
HI NA MI EL & NG NC NG* UT NG* NA Not Applicable


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