Deregulation of Natural Gas
Natural gas in the twenty-first century.(Energy in the Twenty-First Century)
The deregulation of well-head natural gas markets and the reorganization of the natural gas pipeline industry have allowed the retention of sufficient natural gas supplies and the maintenance of prices significantly less than regulated levels in the past. The provision of natural gas is now different from the sale of pipeline transportation services while the local distribution services is being separated from gas commodity sale. The gas production sector is still highly competitive, particularly more so in the transportation markets.
The Natural Gas Industry, like the electricity industry, closes the century in the throes of revolution. The wellhead-to-burnertip regulation and control that characterized most of the industry's development in the twentieth century is being abandoned in favor of competitive mechanisms that have only recently become available to the industry. The latest advances in information and communications technology have made it possible to create "virtual markets," with electronic trading linking physical gas flows and financial transactions. The future of natural gas bears little resemblance to its past.
INDUSTRY STRUCTURE
Historically, the natural gas industry had a simple structure. Hundreds of gas producers sold their product to dozens of interstate gas pipelines, whose very existence was predicated on long-term supply contracts with these producers. Beginning in 1954, the price of gas in these transactions was federally regulated. Pipelines carried the gas to local consuming markets where they sold it at the city gate to a local gas distribution company (LDC), which performed the final distribution and sale to end users. The city gate price was dictated by the pipeline's regulated tariff, while the prices paid by end users were typically set in the LDC's tariff by state regulators.
Federal and state regulation of pipeline and LDC rates and operations were justified on natural monopoly grounds. Technologically, the cost of a pipeline is roughly proportional to its diameter, while its volumetric capacity increases with the square of its diameter. This results in declining average costs as pipeline size increases. LDCs are similarly characterized and, of course, were the textbook example of natural monopoly in John Stuart Mill's Principles of Political Economy. Pipeline and LDC rates were set on a cost-of-service basis, covering "prudently incurred" costs, including an allowed rate of return on capital stock. Rate setting was a quasi-judicial process, with rate proposals presented by company lawyers, challenged by customers or their representatives, and adjudicated by regulatory commissioners. Rates were to be "just and reasonable," as opposed to economically efficient. Where possible, social or political objectives were also pursued, such as cross-subsidies favoring residential customers.
While the justification for pipeline regulation has come under fire in recent years from some quarters,(1) the organization of the pipeline industry as a regulated natural monopoly may well have been efficient, given the existing technology.(2) In a world of vacuum tubes and operator-assisted rotary-dial telephones, long-distance pipelines served to communicate and modulate supply conditions at one end of the pipe with demand conditions at the other.
Conditions are different today. High-speed communications and information technology make it possible for a single market to process millions of transactions a day. Information on market conditions across the country is readily available to any interested parties. Pipelines are only needed to deliver gas.
As a result of these innovations, wellhead gas sales are today completely competitive. Most sales are made on spot markets, where prices are highly transparent. Spot prices are converging across regions, a development that has been attributed to the increasing ability to move gas from one region to another under open-access pipeline transportation arrangements.(3) Pipeline capacity is traded in a partly deregulated, increasingly competitive environment. Local distribution services are increasingly being "unbundled" (i.e., separated) from gas sales and provided on an open-access basis. A new industry segment - natural gas marketing - has developed to arrange gas purchases and deliveries for many LDCs and end users. These marketers, as well as some producers, LDCs and end users, use natural gas futures, options, swaps and other financial instruments to hedge their financial risks and/or as an alternative to gas storage in their supply portfolios. More than half of the gas being delivered today travels from the wellhead to the consumer using third-party open access transportation and distribution services.
These developments may be traced back to the 1978 decision to decontrol wellhead gas prices. That decision established a deregulatory pattern that is now being repeated downstream in the gas transportation and distribution industries. Under this pattern, phased deregulation creates spot markets, which compete successfully with the pre-existing regulated market. Regulated firms find themselves competing with unregulated firms, many of whom are also customers of the regulated firms. Regulators attempt to "level the playing field" by deregulating the newly competitive segments of the industry, creating stranded costs in the process, and establishing the necessary conditions for the emergence of spot markets downstream, where the cycle repeats. This process began at the wellhead in the 1980s, has progressed to natural gas transmission, is currently proceeding to local gas distribution markets, and can even be seen arising in other industries such as electricity and telecommunications.
AT THE WELLHEAD
The Natural Gas Policy Act of 1978 set the stage for phased deregulation of natural gas prices. It established countless categories of natural gas - old interstate gas, old intrastate gas, new gas discovered in old reservoirs, gas from newly discovered reservoirs, gas from deep wells, gas from tight formations, gas from the Outer Continental Shelf, gas produced with exotic technologies - and set different price levels, price paths and decontrol dates for each category (although prices for old gas were to remain permanently regulated).
Ironically, within a very few years so much gas had been brought into production in response to the higher price ceilings that the ceilings for most categories became nonbinding. The market price for gas was lower than the "lawfully established" price that most pipelines were contractually committed to pay. This resulted in a "take-or-pay" crisis, named for the "take-or-pay" clauses in gas purchase contracts wherein the pipeline promised to pay the producer the maximum lawful price for a certain quantity of gas, whether or not the pipeline actually took delivery of the gas. Once price ceilings began to exceed the market price, many pipelines found themselves committed to buy gas at a higher price than they could sell it for. Their existing contracts had become uneconomic due to the market response to wellhead price deregulation. In today's language, these contracts would constitute "stranded costs."
The take-or-pay crisis had two effects. One was the renegotiation of most gas purchase contracts to incorporate market-responsive pricing. The second was the release of untaken gas onto a spot market, which eventually became the source of most gas purchases. The emergence of a competitive spot market in turn led to the development of a gas futures market and related financial derivative products such as swaps and options. Natural gas is now firmly established as a competitively traded commodity.
IN THE PIPELINE
At the time of the take-or-pay crisis, natural gas pipelines were both sellers and transporters of natural gas. As sellers, contractually committed to high-priced gas supplies, they found themselves losing customers to lower-cost suppliers buying on the spot market. The dwindling customer base was problematic for pipeline management, accustomed to guaranteed cost recovery, and to pipeline regulators at the Federal Energy Regulatory Commission (FERC), who faced the problem of regulating only a portion of an increasingly unregulated market. It was soon apparent that trying to recover stranded take-or-pay costs from a dwindling customer base was a losing proposition. Instead, the FERC took a number of increasingly vigorous steps aimed at establishing open access on all pipelines.
At first, FERC strongly encouraged, but did not mandate, open access. FERC Order No. 436 (1985) gave pipelines incentives to provide third-party transportation services to shippers who had made their own separate gas supply arrangements. These shippers included natural gas consumers (primarily industrial end users and electric power generators), some local distribution companies, and, at the other end of the pipe, natural gas producers or marketing companies. At the same time, pipelines continued their own gas marketing activities, in direct competition with some of their shipper customers. Ultimately, it became apparent that this form of competition for gas commodity sales was unworkable.
FERC recognized the obvious - that the marketing and sale of natural gas was a competitive process and could not remain partially regulated. FERC took itself out of the business of regulating gas commodity sales by taking regulated gas pipelines out of the commodity sales business. FERC Order No. 636 took effect in November 1993, requiring that gas commodity sales be unbundled from transportation transactions. Today, pipeline companies generally conduct their sales and marketing activities through unregulated affiliates, while interstate natural gas transportation remains subject to FERC jurisdiction. The natural gas good is now purchased separately from the transportation service.
The separate provision of gas transportation service has required a complete overhaul of the natural gas pipeline industry. FERC Order No. 636 in essence transformed pipelines into time-share properties offering a variety of leasing arrangements. The most prominent service, similar to a long-term lease on an apartment, is long-term firm transportation (LTFT). An LTFT contract allows the shipper (i.e., the lease-holder) to use a given amount of pipeline capacity at any time, requiring only that the pipeline be prenotified of the intended usage. If any of the reserved capacity is not needed at any time, the shipper may sublet the capacity under a "capacity release" program established in Order No. 636 and intended to function as a competitive secondary market in released capacity. Unused capacity that is not released to a secondary shipper may be marketed by the pipeline itself as interruptible capacity (IT), which is subject to immediate recall, or short-term firm transportation (STFT) of less than a year's duration. In terms of the time-share analogy, whenever the long-term leaseholders are not in residence, the property may be occupied by tenants who are subletting the space from the long-term leaseholders. Any space that remains vacant may be rented by the property owner/managers to overnight or other short-term customers, who may be evicted on short notice if the long-term leaseholder should show up.
Thus, the market for pipeline capacity is subdivided into a primary market, consisting of long-term firm transportation contracts, and a secondary market in which capacity released by the holders of LTFT contracts competes with IT or STFT services offered by the pipeline. Once again, the pipeline is competing with its customers, this time for capacity sales instead of gas commodity sales.
As was the case when wellhead markets were beginning to be deregulated, pipeline companies are saddled with a higher cost structure than their competitor-customers. Pipeline tariffs are designed to recover fixed costs from LTFT rates. As more short-term capacity becomes available at a lower price on the secondary market, demand for the pipelines' higher-priced long-term capacity is declining. Shippers are failing to renew some of their LTFT contracts when they expire. This again raises the specter of stranded costs - investments in pipeline capacity that cannot be recovered at market rates.
Ten years ago, many pipelines were saddled with long-term natural gas take-or-pay obligations whose costs could not be recovered in the more competitive market for natural gas. Today, many pipelines are saddled with sunk investments in pipeline capacity whose costs may not be recoverable in the more competitive market for pipeline capacity. The stranded cost issue took the form of take-or-pay contracts at the wellhead and is now taking the form of pipeline capacity turnbacks.
FERC responded to the take-or-pay crisis by establishing a truly competitive wellhead gas market. Similarly, the ultimate solution to the capacity turnback crisis is likely to be a truly competitive natural gas transportation market. Initial steps in this direction are underway as FERC considers proposals for negotiated or market-based rates. If adopted, market-based rates would simply acknowledge and formalize the existing practice of widespread variations from established cost-of-service tariffs. Most pipeline rates are already de facto market based.(4)
The market for pipeline services is likely to continue to evolve toward true competition. Such a market would offer a variety of short-term transportation services with prices established in a spot market, possibly matched to gas commodity transactions. For instance, a gas marketer might procure gas transportation capacity at the time of the gas commodity purchase. Alternatively, the marketer might acquire a portfolio of long- and short-term transportation capacity, which would be used to deliver gas supplies acquired separately.
In this new environment, it would be only natural to see a futures market develop for transportation capacity. This could be an explicit market in capacity futures or it could be an implicit valuation based on differentials between the current gas commodity futures contracts located at certain production-area hubs and new futures contracts located at city gates. Financial products associated with explicit or implicit capacity futures could then be used to finance or refinance capacity that now depends on failing regulatory cost recovery mechanisms.
BEHIND THE CITY GATE
Local distribution companies are facing the next wave of upheaval in the natural gas industry. As local suppliers of natural gas they face increasing competition from natural gas marketers. Nearly half of all gas sales to end users are already arranged by non-LDC suppliers,(5) who typically use the LDC system for third-party distribution. Thus, one element of the familiar deregulation pattern is already in effect at the local level - regulated LDCs are competing for retail gas sales with some of their customers.
Competition in retail gas markets is expected to intensify as the imminent deregulation of electric generation provides opportunities for "total energy marketing."(6) Single-product LDCs operating under regulated cost-of-service rates will find themselves at a severe competitive disadvantage in this new world.
The local distribution industry is already reorganizing to meet new competition. Some are experimenting with unbundling - giving all customers access to third party suppliers and restricting the LDC role to one of third party distribution only. Some are merging with other gas or electric utilities in an effort to achieve economies of scale in energy marketing.(7)
As competitive marketing of gas and other energy services increases, pressure for total unbundling of LDCs is likely to intensify, leading to a restructuring of the distribution industry similar to that of the pipeline industry. If this scenario comes to pass, LDCs will become exclusively distributors of natural gas, with commodity sales and marketing activities conducted (if at all) by unregulated affiliates.
If the pipeline model is followed at the local distribution level, LDCs would sell rights to distribution capacity using the time-share approach, featuring long-term leases, short-term leases, subleases and one-night stands. Many LDCs in fact already offer such services to their industrial and large commercial customers. As with the pipeline industry, this process could lead to shorter-term arrangements - conceivably even the commoditization of local distribution services, though this is more problematic in those cases where LDCs really do hold a natural monopoly.
NATURAL GAS MARKETING
The separation of the natural gas commodity sale from the sale of transmission and distribution services has given rise to a new segment of the industry - the natural gas marketer. In 1995 there were some 264 natural gas marketers in the United States and Canada, including a "core" of ten large marketers (each with 1995 sales in excess of one trillion cubic feet) with a combined market share of 36 percent, and a "fringe" of more than 200 smaller companies. The numbers indicate a highly competitive industry; however, scale economies in natural gas marketing have led to an ongoing consolidation of this industry, which has shrunk from 313 companies only three years ago.
Economies of scale in gas marketing arise from a number of sources. Most prominent is the ability of large marketers to take advantage of geographical differences in demand and to arbitrage price imbalances across various supply regions. For example, a marketer with customers in Florida and Chicago can contract with producers for a steady volume of gas throughout the year, sending a greater proportion of its supply to Chicago in the winter and a greater proportion to Florida in the summer (to produce electricity for air-conditioning). This marketer, by assuring producers of a steady year-round market, may be able to negotiate better price and supply terms than one whose customers are located only in Chicago or only in Florida.
A typical marketer will purchase gas (either by contract with a producer or on the spot market) and ship it to the customer, using pipeline and distribution capacity to which either the marketer or the customer has contractual rights. Some customers of the marketing company, including LDCs and large end users, may have their own pipeline capacity rights, in which case they only pay the marketer for the gas supply. However, with the prospective transformation of LDCs into distribution-only companies, marketers are likely to account for the major portion of pipeline and distribution capacity holders in the future.
It is likely that, early in the twenty-first century, natural gas marketers will be purchasing, shipping, and selling natural gas to most end users throughout the United States. A gas consumer will buy gas from any one of a wide array of marketing companies, who will arrange for the purchase of gas and its delivery to the consumer, sending the customer a single bill that covers the gas commodity cost as well as its long-distance transmission and local distribution costs. A process that for most of the twentieth century was the province of heavily regulated pipelines and LDCs will now be almost completely deregulated and competitive.
The impending restructuring of the electric power industry will add even more competitive pressure by expanding the opportunities available to marketers. Natural gas marketers are already beginning to market electric power and, more importantly, to arbitrage across fuels by taking advantage of the ability of electric power producers to use a variety of fuels. For example, deals have been reported in which a marketer bought power that had been generated from coal and traded this power to an electric utility for gas that the electric utility now did not need for its own generating plant. The marketer took that gas and sold it to another gas consumer, making a profit on the entire series of transactions.
The deregulation of electric generation could facilitate the emergence of a "Btu market," making it possible to move various fuels to their highest valued uses, achieving greater efficiency and potentially reducing costs across the board. For the gas industry, this implies even greater competition. Not only will gas be competing directly with fuel oil in dual-fuel boilers (as has been the case for many years), gas will also be competing indirectly with coal, hydro and even nuclear power. If, as expected, deregulation results in lower electricity prices, gas may also find it harder to maintain its recent inroads in the home heating and commercial cooling markets. The ultimate solution may be the complete integration of the natural gas and electric utility industries. The recently announced acquisition of Portland General Corp. (an electric utility) by Enron Corp. (primarily an integrated natural gas company) is a step in this direction.
WHAT ABOUT SUPPLY?
The outlook for natural gas supply has varied widely over the history of the industry. In the years before interstate pipelines had connected the gas production areas to distant consuming markets, gas was considered so abundant as to be almost worthless. In the late 1940s, there was more than a thirty-year supply of gas at then-prevailing production rates. Few oil and gas producers explored for gas; it was discovered in the search for oil - either "associated" gas dissolved in oil or "nonassociated" gas in a gas-only reservoir. Oil and gas producers were gas producers only by default. Gas was routinely flared as a waste byproduct of oil production (as is still the case in many oil-producing countries today that have no market for all their gas production). U.S. gas markets were so underdeveloped that newly discovered gas reserves routinely exceeded annual production until the late 1960s. Only then did the supply impact of wellhead price controls begin to be taken seriously.
As gas markets matured, demand grew more rapidly and gas's supply reputation changed from one of surplus to one of shortage. Price controls encouraged gas consumption, which rose from 12 trillion cubic feet (Tcf) in 1960 to a peak of 22 Tcf in 1972. Price controls began to inhibit supply: reserves peaked in 1967 at 293 Tcf and declined steadily until 1993, when they totaled 162 Tcf. Annual reserve additions, which had regularly exceeded production, failed to do so in 1968. From 1971-79, annual reserve additions averaged only 48 percent of annual production.
The 1970s were a decade focused on energy supply concerns. The Arab oil embargo of 1973-74, the resulting increases in world oil prices, and restrictions on natural gas use (including curtailments and moratoria on new hook-ups) all fed the perception that many energy resources were in fixed supply and near depletion. Natural gas was the poster child for this point of view:
.... [I]n the view of [many] analysts ... the gas shortage of the 1970s was America's first serious brush with terminal resource depletion, and the paradigm for an impending global energy crisis.(8)
Never mind that supplies were ample in intrastate gas markets in Texas, Louisiana and other producing states, where federal price controls did not apply.
Ultimately, however, the hope that higher prices might elicit some new gas supplies resulted in passage of the Natural Gas Policy Act of 1978, with the results described above, culminating in a competitive wellhead market for gas. By most indicators, the deregulation of wellhead prices has had beneficial supply effects. Reserve replacements, for example, have stabilized above 85 percent since 1989, and exceeded production in 1990, 1994 and (by preliminary estimates) 1995. Production has increased by 15 percent since 1986, while annual average wellhead prices have exceeded $2 (nominal) per thousand cubic feet (mcf) in only one year between 1986 and 1995. (That was in 1993 when the price was $2.04/mcf.) In other words, the postderegulation experience has been one of greater supply and lower prices.
Today, with energy regulation giving way to market forces, the resource exhaustion mindset has been discredited. Technological, institutional and financial innovations have reduced the cost and increased the efficiency of finding, producing, marketing and consuming natural gas. The U.S. Energy Information Administration cites such innovations as horizontal drilling and three-dimensional seismic analysis, drill bit improvements, horizontal drilling and advanced fracturing techniques as factors in increasing the rig productivity rate, doubling the success rates of exploratory wells and cutting finding and producing costs in half since the early 1980s.(9) Interstate pipeline expansions, new storage facilities, and more operational and regulatory flexibility in the transmission of natural gas have helped create a more widely integrated natural gas market while reducing transmission costs at the same time. The rise of the multi fuel marketing industry will provide even greater efficiencies in fuel use down the road. These trends are reinforced by new financial products that allow industry participants to limit their financial risks.
The very fact that oil, gas and now electricity are being traded as commodities, rather than hoarded against a hypothetical exhaustion date, signals a basic confidence in future supply and in the ability of markets and prices to assure a balance between supply and demand. This growing confidence in competitive forces to govern energy markets may be the defining feature of energy in the next century.
GLOSSARY OF NATURAL GAS ACRONYMS
Btu British thermal unit, a measure of the energy content of natural gas and other fuels
FERC Federal Energy Regulatory Commission
IT Interruptible transportation service
LDC Local natural gas distribution company
LTFT Long-term (a year or more) firm transportation service
Mcf Thousand cubic feet, a measure of natural gas volume
STFT Short-term (less than a year) firm transportation service
Tcf Trillion cubic feet, a measure of natural gas volume
