Natural Gas Distribution

Industry Snapshot

The production segment of the natural gas industry in the United States in the late 2000s was controlled by about 24 major operators, although there were over 8,000 natural gas producers from large, integrated companies to single owners with partial interest in a well. Once the natural gas was extracted, over 550 companies processed the 17 trillion cubic feet of natural gas and 720 million barrels of natural gas liquids produced annually in the United States. About 160 pipeline companies then transported the natural gas through nearly 300,000 miles of pipeline, of which 185,000 was interstate pipeline. Storage facilities were provided by about 115 natural gas storage operators. The final step from producer to consumer was handled by local distribution companies (LDCs). In the late 2000s, the natural gas LDC segment remained highly fragmented with over 1,200 gas utility operators, despite deregulation in the 1990s. Although many LDCs retained monopolies over their local markets, some states offered consumers distribution choices.

The United States is the world's second largest producer and consumer of natural gas, and the use of this cleaner-burning fuel was expected to rise into the 2020s. U.S. consumption of natural gas averaged 22 trillion cubic feet annually during the late 2000s, accounting for 24 percent of all energy needs. About 90 percent of all natural gas used in the United States is produced domestically, with most of the rest coming from Canada. Industrial uses accounted for about 30 percent of natural gas demand, followed by electrical generators, 25 percent; residential, 25 percent; commercial, 15 percent; and other, 5 percent. Sustained high prices of natural gas during the late 2000s were cause for concern in the industry. According to the Department of Energy, 21.5 trillion cubic feet of natural gas was consumed in 2008.

Organization and Structure

Local distributing companies (LDCs) receive their supplies of gas from a transmission system at a transfer point called the "city gate." The utility then delivers the gas through mains and distribution lines to end users in a particular geographic area. There are four traditional classes of gas utility customers: individual residences, commercial establishments, industrial facilities, and electric utilities. There are two types of customers within these classes. "Core" customers require stable amounts of gas on demand because gas is their only source of fuel. "Non-core" gas customers can switch to other types of fuel when gas is unavailable or too expensive. Residential and commercial customers are typical core customers while industrial and electric-generating companies are examples of non-core customers.

LDCs are subject to regulation by state public utility commissions (PUCs). PUCs establish rates for different classes of customers. Prices per unit are typically lower for large users. In setting rates, PUCs attempt to find an appropriate balance between the different interests of consumers, who want low rates, and company investors, who seek adequate returns on their investments.

In addition to state PUCs, federal regulations also influence the gas distribution industry. In 1992, the Federal Energy Regulatory Commission (FERC) issued Order 636. Although the most direct impact of Order 636 was on the gas transmission industry, it also affected local distribution companies. The provisions of the order necessitated changes in the way distribution companies arranged for gas purchases, transportation, and storage. FERC's order also permitted pipelines to pass transition costs on to distribution companies.

The natural gas distribution system continues to "unbundle" in a deregulated industry, giving end users more choices than ever over who delivers their gas supplies. The largest and most profitable customers of many local distribution companies, which are often referred to as LDCs or gas utilities companies, switched to alternate gas sources. In some cases, industrial users and electric utilities contracted with pipeline companies to construct direct access to transmission systems and bypass the LDC altogether. In other instances, the customer purchased the actual gas from independent suppliers but continued to buy transmission services from the LDC.

To cope with the changing industry environment, LDCs began to implement far-reaching marketing efforts. They offered services to large industrial users, such as natural gas storage, in attempts to keep profitable customers within the system. They obtained new industrial customers by promoting fuel switching away from electricity and oil. LDCs also expanded efforts aimed at increasing demand through the development of new technologies, including vehicular natural gas and natural gas fuel cells.

Background and Development

The nation's earliest gas distribution companies delivered synthetic gas, manufactured from coal, to cities for use in lighting. In the late 1800s, naphtha gas, which is derived from crude petroleum, replaced coal gas. By the time the first company to distribute natural gas, the Fredonia Gas Light and Water Works Company, was formed in New York, approximately 300 companies were already delivering manufactured gas. Other local distribution companies were formed in the closing years of the nineteenth century, including Brooklyn Union Gas Company, which was incorporated in 1895, and East Ohio Gas Company, founded in 1898 by the Standard Oil Company. Many early gas distribution companies were owned by holding companies involved in other segments of the natural gas industry. The Public Utility Holding Act of 1935 required large holding companies to divest themselves of their public utility companies.

In 1937, Texas became the first state to require the addition of an odorant in distributed natural gas. Ethyl mercaptan, originally introduced in Germany in 1880, aided in detecting natural gas leaks and provided an early warning system to help prevent disasters. The use of mercaptan and mercaptan blends gave natural gas, a compound that has no inherent smell, a distinctive odor.

During World War II, fuel oil and gasoline rationing led to an expansion of natural gas markets. Production during the war years increased by 55 percent. Natural gas was a key ingredient in more than 5,000 industrial processes and was used as an industrial fuel as well as in the manufacture of explosives. Natural gas usage continued to increase following the war, and from 1945 to 1954 consumption doubled.

To meet demand, local distribution companies purchased gas from an available pipeline that reached their area. The pipeline typically sold the gas at a single price that represented an average of all the categories of gas handled by the pipeline and included charges for transportation and storage. Changes in federal regulations during the 1980s and 1990s required pipelines to "unbundle" their services and offer gas utilities access to gas transmission services separately from gas purchases. As a result, local distribution companies were permitted to buy gas from a variety of sources.

As the gas distribution industry entered the 1990s, residential use accounted for about one-fourth of the nation's natural gas consumption. Because residential use fluctuated according to weather patterns, weather was an important issue. The industry judged "normal weather" as the mean of temperatures experienced over a 30-year period and adjusted its norms every 10 years. A "degree day" was defined as a measurement comparing the daily mean temperature to a guide of 65 degrees Fahrenheit. Although the decade began amid a series of years with warmer than average temperatures and a slowed economy, demand for natural gas grew.

Environmental and conservation efforts contributed to increased demand for natural gas. In some instances, state regulatory agencies required electric utilities to use more natural gas and to encourage their customers to switch from using electricity during peak demand periods. Often the preferred replacement fuel was natural gas. Wisconsin and Vermont, for example, required electric utilities to help retail customers shift from electricity as their primary source of energy in instances where switching fuels would be cost effective. Under the ruling, residential customers with electric heat were offered assistance in converting to other fuels.

Maximizing use of their system's capacity by providing gas to a variety of users was a vital concern to local distribution companies. Gas utilities hoped that improvements in natural gas cooling technologies for uses such as refrigeration and air conditioning would help balance winter and summer demand.

Another concern facing local distribution companies was "bypass," which is a process for natural gas suppliers to provide direct sales and service to large users, circumventing the local gas utility. According to bypass proponents, the practice provided an opportunity for customers to shop around for the best gas prices. According to critics, bypass provisions unfairly affected small users, such as residential customers, because the distribution companies lost substantial loads, resulting in higher fixed costs being passed on to the remaining customers.

For the nation, deregulation meant that industries that used a lot of natural gas became more competitive internationally, while consumers paid more of the real cost of the gas they used. Analysts predicted that the trend toward unbundling was in the consumer's best interest. An increasing number of companies began to offer unbundled delivery at the residential level as well as at the level of larger customers. In spite of deregulation and other changes, profits among natural gas distributors continued to soar, in large part due to the reduction in operating and maintenance costs that unbundling allowed.

As of August 1999, residential end users in 23 states and the District of Columbia were able to purchase natural gas from one of several suppliers but have their local utility company deliver it. These options accommodated roughly 22 million, or 40 percent, of the 55 million households with natural gas service. Between 1996 and 1999, 4 million residential customers actually switched to a non-utility supplier. According to a December 1998 report published by the U.S. General Accounting Office (GAO), residential customer choice programs resulted in individual savings of 1 to 15 percent on the gas bill. New York was a leader in offering customer choice to residential customers, and Ohio made customer choice a state policy. As of 1999, Georgia had the largest number of residents exercising purchase options. The state's largest natural gas utility, Atlanta Gas Light, continued to offer delivery services of natural gas, irrespective of the residential user's purchase source. In 1997, 88 percent of all gas consumed by electric utilities companies was purchased under this option, as was 33 percent in commercial/industrial facilities.

In the early 2000s, the American Gas Association (AGA) estimated that overall natural gas consumption would increase 40 percent by 2015. By 2010, the United States was expected to use 30 trillion cubic feet (tcf) annually. In order to accommodate these needs, industry analysts estimated new pipeline costs to be as much as $32 billion, in addition to another few billion dollars for storage. New England states were anticipated to be the first to require more pipeline construction, as nuclear and coal energy facilities continued to shut down and convert to natural gas. The Southeast was also a priority.

Other factors contributed to the steady but consistent growth of the industry. New technology increased the development of polyethylene piping that could withstand higher pressures, from 100 to 125 psi. Other developments included new devices for detection of natural gas leaks. The industry spent $4 billion in 1999 for safety, with reportable incidents dropping from 290 in 1988 to 206 in 1998. Finally, in 1999, the Gas Research Institute announced a joint venture with Germany's Karl Weiss GmbH & Company to bring to North America the new "trenchless" technologies for pipeline maintenance which required only two digging holes, and to install the cured-in-place (CIP) liners to service lines and mains.

Continuing deregulation remains the most influential factor in the distribution of natural gas within the United States in the late 2000s. Prices are no longer regulated, so supply and demand determine the cost of natural gas. Interstate pipeline no longer owns the gas transmitted and only transports natural gas from supply to the end user.

However, LDCs that focus on distribution alone have not taken over local markets as quickly or as successfully as was expected following deregulation. One problem for LDCs is liability for consumers who do not pay their bills. As the last in line from production to transportation to distribution, LDCs are the ones left holding the bill, specifically the unpaid bill. In addition, natural gas distribution makes up only one-third of the energy industry, all of which underwent deregulation. Faced with the challenges of deregulating the entire industry, local areas tended to bypass issues that would successfully implement the separation of transmission from distribution. As a result, most LDCs continued to perform both transmission and distribution functions related to their businesses.

During the early 2000s, the energy industry was significantly disrupted. California experienced energy shortages and outages, which were later blamed on poor decisions and greedy policies among several energy providers who stood accused of creating an artificial crisis or who at least negatively contributed to the problem by withholding supply. When Houston-based Enron imploded under allegations of shady accounting practices in 2001, the bottom dropped out of the energy industry. As a result, credit ratings plummeted and investors disappeared, making it difficult for new distributors to enter existing markets and leaving established LDCs with very little influx of new competition.

Current Conditions

In 2005, research firm Fitch Ratings projected that the price for natural gas would remain stable around $5 per million cubic feet, with a slight decline in price in 2007. However, both supply and demand issues are hard to predict in the natural gas industry as supply disruptions are possible and demand depends on the overall economy as well as the severity of the winter months. While the overall milder winters of the mid-2000s regulated prices, production companies were extracting natural gas from deeper, harder to reach areas, causing upward price pressures. The DOE estimated that 1 million British thermal units (Btus) of natural gas would cost approximately $12.18 in 2007, with the same amount of electricity costing nearly twice that amount. Additionally, the DOE projected that natural gas would cost less than heating oil ($16.01), kerosene ($19.48), and propane ($20.47).

Industry advocates and executives such as Robert W. Best, CEO of Atmos Energy, blamed the high prices and supply issues on the lack of adequate access to new drilling sites. "It is a flaw in policy to put potential producing areas off limits. How are we going to make up for production that is denied to consumers from regions that are off limits? We are going to import LNG [liquid natural gas]," Best told Pipeline & Gas Journal in April 2005. "We need every segment of this industry to be a very healthy segment--including the distribution segment--and we could have it if we could get more supply." Subsequently, in 2006, President George W. Bush signed an act that required oil and gas leasing in two previously banned areas of the Central Gulf of Mexico and lifted restrictions on leasing in Bristol Bay in the North Aleutian Basin of Alaska. Lifting the ban in these areas and allowing them to be part of the five-year leasing program for 2007-2012 meant access to approximately 25 trillion cubic feet of natural gas resources.

About 2,200 establishments engaged in this $131.7 billion industry in 2007 with a workforce numbering 81,600. These employees earned nearly $5.9 billion in wages. According to the U.S. Department of Energy's (DOE) Energy Information Administration, natural gas consumption in the United States was expected to increase by 2030, from an average of 22 trillion cubic feet in the late 2000s to 26.1 trillion cubic feet. Demand would be driven by the electric power sector, which was projected to increase from 2005 to 2020. However, generation from new coal and nuclear plants was expected to overtake some of the growth from natural gas-fired generation.

Industry Leaders

Sempra Energy, of San Diego, California, distributed natural gas to 6.2 million customers through its two subsidiaries, Southern California Gas and San Diego Gas & Electric. In 2008, Southern California Gas reported revenue of $4.77 billion, and San Diego Gas & Electric reported revenue totaling $3.25 billion. Sempra reported revenue of nearly $10.8 billion in 2008.

Pacific Gas & Electric (PG&E), of San Francisco, California, a subsidiary of PG&E Corporation, served 4.1 million gas customers and 5 million electric customers in the late 2000s. Severely affected by the California energy shortage, PG&E operated under bankruptcy protection from 2001 to 2004. In 2008, PF&E reported revenue totaling more than $14.6 billion.

Atmos Energy, of Dallas, Texas, was the industry's largest pure player, focusing all its business operations on natural gas distribution. With its $1.9 billion purchase of TXU Gas Company of North Texas in 2004, Atmos expanded its operations significantly. The company has about 3.2 million natural gas customers in 12 Midwestern states. In 2008, Atmos reported revenue of $7.22 billion.

Other industry leaders included Nicor, Inc., of Naperville, Illinois, with 2.1 million gas customers; Southwest Gas Corporation, of Las Vegas, Nevada, with 1.6 million gas customers; and Public Service Electric & Gas, of Newark, New Jersey, with 1.7 million gas customers.