Deregulation of Natural Gas—Focus on Contract Carriage

Natural gas has become the most pressing energy issue of 1983. Rather than solving the problems of gas markets, deregulation of wellhead prices under the Natural Gas Policy Act of 1978 (NGPA) has introduced a whole new set of concerns. Some stem from the partial nature of deregulation under the NGPA, while others arise from contracting practices and regulation affecting pipelines and distribution companies.

Problems in natural gas markets

Shortages of natural gas were chronic before 1978. Low prices in the field constrained supply and encouraged consumption, and available supplies were rationed by regulatory curtailment mechanisms. Producers, pipelines, and distributors could sell any and all gas they could obtain, and prices were not an issue. Shifts in demand did not affect sales, because under conditions of chronic excess, demand such shifts only changed the depth of curtailments.

Rising prices—Falling demand

The NGPA has allowed wellhead price ceilings to rise sufficiently to eliminate excess demand. As a result, factors affecting demand also affect gas sales, and thus all segments of the industry—and final consumers—face new forms of uncertainty.

Regulatory and contracting practices in the gas industry developed during the era of shortage, and some are ill-suited to the new era of uncertainty. This mismatch of old institutions and new conditions currently has created three major problems. First, combined with the progress of deregulation of wellhead prices, the old institutions have caused prices charged to final consumers of gas to rise above market-clearing levels.

During 1982, deregulation allowed wellhead prices to rise, while a combination of external events depressed the underlying demand for gas. Critical in raising wellhead prices were indefinite escalators in existing contracts between producers and pipelines. In a number of contracts, these escalators set prices equal to the highest price allowed by the Federal Energy Regulatory Commission, so that when price ceilings rose above market-clearing levels, the stage was set for a gas surplus. In other cases, pipelines signed contracts for particular categories of gas at prices that could be supported in conditions of the late seventies. But as other gas costs rose in the course of deregulation, average costs were driven above levels that the market would accept in conditions of depressed demand. Some of these contracts had buyer protection clauses allowing prices to be reduced, but many did not.

Depressed demand, in turn, arose from three major factors: warm weather during several successive heating seasons, recession and reduction of activity in gas-consuming industries, and reduction in oil prices that made alternative fuels more attractive. These events would reduce gas demand at any price; the progress of deregulation raised prices and reduced demand further.

As a result, in some markets delivered prices of natural gas have risen above market-clearing levels. In the industrial market, equilibrium prices are likely to be established by competition between gas and residual fuel oil for sales to consumers with dual fuel capacity. Although estimates vary, it is clear that a substantial amount of industrial fuel consumption occurs in boilers with the capacity to switch rapidly between gas and residual fuel oil. These consumers will use gas when it is available at a price below the cost of an (Btu) equivalent amount of residual fuel oil, but will switch off gas when the price rises above it.

By the end of 1982, gas cost more than high-sulfur residual fuel oil in the Pacific, Middle Atlantic, and New England regions. In the South Atlantic, West North Central, and probably also in the East North Central regions, prices of the two fuels were approximately equal. Given the dispersion of prices within census regions, it is likely that a considerable number of industrial consumers in the last three regions faced gas prices above the cost of residual fuel oil.

These prices have caused industrial consumers to switch from gas to residual fuel oil. At the same time, recession has reduced industrial activity and fuel consumption overall, while warm weather and conservation have held down space-heating demand. Between 1981 and 1982, industrial gas consumption fell by 1.3 trillion cubic feet (tcf), electric utility consumption fell by 0.4 tcf, and residential consumption rose by 0.2 tcf, so that total gas consumption fell by 1.5 tcf. Comparing December 1982 with December 1981, demand in all categories fell: residential by 70 billion cubic feet (bcf), industrial by 270 bcf, and electric utility by 30 bcf. This loss of load means that, at current prices, the market will not absorb the quantities of gas pipelines and distributors are obligated to buy.

In a freely operating market, such shifts in final demand would cause prices to adjust back to the wellhead in order to keep supply and demand in equilibrium at all points in the system. Distributors facing lower sales would reduce their purchases in the field; competition among producers for remaining sales would reduce price, with the producers with highest short-run marginal costs reducing their output in response. Lower prices, passed through to consumers, would recapture some demand. After a shift in demand because of warm weather, recession, or declining oil prices, equilibrium would be reestablished with lower field prices and lower production.

In the natural gas industry, contracting and regulatory practices interfere with this equilibrating mechanism. Distributors encountering a drop in demand often find themselves obligated to pay pipelines for gas not taken—either through minimum bill provisions of sales contracts or demand charges in regulated tariffs. Pipelines, whether or not their revenues are guaranteed by distributors, face "take-or-pay" and pricing provisions in their contracts with producers that obligate them to take predetermined quantities of gas at prices that may bear no relation to market conditions. As a result, producers have incentives to produce gas in excess of demand.

Pipelines and distributors cannot long continue to take deliveries in excess of their sales. If prices were free to adjust, producers would face a falling wellhead price and choose efficient, lower production rates. Instead, prices are prevented from falling by certain provisions in longterm contracts, and cutbacks are allocated by other rules that do not equate marginal costs of production. In particular, pipelines may allocate cutbacks in order to minimize the financial penalties resulting from take-or-pay provisions of contracts.

Field market inefficiency

The result is the second major problem in current gas markets. Some producers find themselves unable to sell gas, though they would be willing to accept prices equal to or lower than those received by others who do continue to sell gas. The resulting inefficient production of gas compounds the inefficiencies created by the multiple price ceilings of the NGPA. Risk allocation also is arbitrary. Producers with stringent contracts are insulated from consequences of falling demand; other producers, pipelines, distributors, and consumers absorb the costs.

Combined with the first problem of excessive burner-tip prices and loss of load, the problem of field market inefficiency implies that there are willing sellers (shut-in producers) and willing buyers (industrial customers priced out of the gas market) who do not have access to one another. Likewise, it implies that some pipelines and distributors are likely to face large losses: the financial obligations involved in buying gas now exceed the revenues achievable when gas is sold.

Regional price differentials

Finally, a combination of factors has caused regional differentials in gas prices larger than can be explained by transportation costs. These factors include field price differentials created by NGPA, producer pipeline contracts, and downstream regulatory and market institutions that allow pipelines to pass costs through to distributors and other customers. Pipelines differ by as much as a factor of two in their costs of purchased gas, which for mid 1982 were estimated to range from $1.34 (Texas Eastern) to $2.90 per thousand cubic feet (mcf). Regional differences in industrial prices, cited above, are exceeded by differentials in residential prices, which are reported for smaller geographic areas. These ranged from approximately $10 per mcf in some communities in Connecticut to under $3 in Kansas. Such regional price disparities also cause gas to be allocated inefficiently, by preventing marginal willingness to pay for gas from being equated across customers, and concentrate loss of industrial load on particular pipelines and regions.

Time for change

The three current problems—disequilibrium in burner-tip markets, inefficient production in the field, and regional disparities in delivered prices—are symptoms of an industry unable to respond to changing market conditions. Since field price deregulation means that natural gas prices and sales will be determined in competition with other fuels, and will be sensitive to external events, these problems can be expected to recur unless fundamental changes are made in operations of the gas industry.

Carrier status

One change that has attracted considerable attention is in the carrier status of natural gas pipelines. Currently most gas moving in interstate commerce is owned by pipelines, who buy in the field and sell to large industrial consumers and electric power plants ("direct mainline sales") or to local distribution companies ("city gate sales"). Thus, they are technically classified as "private carriers"—transportation companies that move their own goods. On occasion, pipelines will transport—for a fee—gas to which title is held by others, usually producers or consumers. In these cases they operate as "contract carriers," voluntarily making space available to transport gas for others.

Fears that pipelines will attempt to suppress competition by refusing to grant access have led to proposals for a third form of pipeline regulation: "mandatory" contract or common carrier status. A number of variants on this proposal exist, but all envision a system in which a buyer or seller of gas can compel a pipeline to provide transportation services for a regulated fee. The long-run consequences of such a change in carrier status depend critically on the details of regulatory oversight of conditions for access and setting of fees. Such matters have not been studied in any detail. But a threshold question also exists of what benefits would be provided by any form of increased access to transportation facilities for parties who wish to deal directly. This question can be answered as follows: increased access offers unambiguous but limited benefits in the short run. It will not aid those locked into their current obligations to deal with one another, although, by increasing the competition that pipelines face, increased access may contribute to building a more responsive gas market in the long run.

There are two distinct groups in the gas market, each of which will be affected very differently by increased access. One, group is composed of the producers and consumers who have essentially "dropped out" of the gas market—that is, consumers who have opted to switch to an alternative fuel and producers whose production has been reduced or shut in by a lack of pipeline demand. In some cases, mutually beneficial trade could take place among these parties, if transportation between the shut-in producer and the potential gas consumer could be arranged.

The second group is composed of those who have no alternative but to remain within the system—producers, pipelines, distributors, and consumers who are bound together by contracts and regulation. These are parties whose distress has elevated natural gas policy to the status of a major national issue, and they will not in the short-run be helped substantially by changes in carrier status. The very conditions that cause their problems also lock them into continuing relationships that limit the benefits of greater access to pipeline transportation for gas purchased directly from producers.

Contractual and regulatory constraints

To see why increased access offers limited short-run benefits, it is necessary to explore further the contractual and regulatory constraints that interfere with achievement of market equilibrium. The problem begins with wellhead contracts that face gas pipelines with costs for gas greater than ultimate consumers are willing to absorb. Whether these costs are borne by pipelines, distributors, or consumers depends on the nature of contracts and rate design.

Contracts between pipelines and distributors mirror in many respects those between producers and pipelines, but they also have unique features. City gate contracts typically are long term and, like their wellhead counterparts, their provisions serve to allocate risk among the signers. In this regard, the city gate analogs to the wellhead take-or-pay provisions are "minimum-take" requirements or "minimum-bill" clauses. These provisions stipulate that a distributor agrees to purchase at least a minimum quantity of gas from a pipeline at prices based on the pipeline's costs. Thus, they serve to reduce a pipeline's losses stemming from excess capacity and to enhance its ability to meet its own take-or-pay obligations at the well-head. At the same time, they assure supplies to distributors which in turn face end-use service obligations. Tariffs set by the Federal Energy Regulatory Commission for city gate sales often contain provisions with similar effects—demand charges that must be paid regardless of actual deliveries and certifications that link distributors to particular pipelines.

Two provisions are unique to city gate contracts—"sole-supp1ier” clauses, which obligate a distributor to purchase all of its gas from a particular pipeline, and "territorial restriction" clauses, which obligate a distributor to resell gas purchased from a particular pipeline within a specified geographic area. Many city gate contracts contain both of these provisions.

These provisions may make it possible for a pipeline to shift costs downstream to distributors. The distributors' ability to recover costs is determined by the demand elasticity of their customers and the willingness of regulators to tilt rate structures so that industrial prices are kept below the cost of alternative fuels while rates for residential customers (and others with limited fuel-switching possibilities) are in-creased.

Matching buyers and sellers

Increasing access could serve to match willing buyers and sellers unable to deal under current conditions, but would not solve the problems that wellhead contracts cause pipelines, distributors, and their customers. Some producers, whose contracts with pipelines contain relatively mild take-or-pay requirements and penalties, are shut in (partially or completely) though they willingly would sell gas at less than market-clearing prices. Industrial customers with dual fuel capability, facing higher prices set by pipelines and distributors, cease using gas though they would buy at prices acceptable to shut-in producers and buyers priced out by pipelines by arranging contract carriage transportation for direct sales. These transactions represent an unambiguous gain, but their benefits are limited in scope. If some contribution to pipelines' or distributors' fixed costs (including take-or-pay liabilities) is made by such transactions, they and their remaining customers will benefit. If customers who otherwise would continue buying from distributors opt for direct purchase, distributors could lose sales and their remaining customers could face higher prices.

The Industrial Sales Program initiated by Transco is an example of how contract carriage can be used to match these willing buyers and sellers. Monthly, Transco estimates how much demand would be lost if all customers faced prices based on its normal tariff. It then matches these demands with supplies from producers who otherwise would be unable to sell gas. Transco sets a price low enough to induce customers to continue to buy gas, deducts the cost of transportation, and pays the net price to producers willing to participate in the system.

However, these new arrangements do not provide for stable, long-run relationships between buyers and sellers. Long-run contracts for gas supplies provide security for the large fixed investments required to produce and transport gas, and share risks among their parties.

Distributors may find it difficult to take advantage of greater access to pipeline transportation of directly purchased gas. If minimum-bill and sole-supplier provisions are enforced, distributors will be unable to switch from high-cost pipeline deliveries to low-cost field purchases. Even if distributors are free to search for gas, pipelines' take-or-pay obligations are unlikely to be eased, because producers able to collect high prices from pipelines for their whole output will be unwilling to sell at lower, market-based prices offered by distributors. Thus, despite its clear benefits for some buyers and sellers now excluded from the market, increased access is unlikely by itself to ease problems of producers and distributors facing high contracted prices and low demand.

Possibility of long-run benefits

In the longer run, however, increased access could contribute to more efficient and flexible working of gas markets. Allowing distributors, ultimate consumers, and producers to deal directly will create new options for buying and selling gas and opportunities to match parties in a way that shares risks more acceptably and presents incentives more effectively.

Some rigidities in gas markets could well be alleviated. Contract carriage could replace the current cumbersome apparatus in which redirecting gas requires certification of entry into a new market or authorization for temporary off-system sales. These proceedings could be bypassed by a market transaction between producers and distributors or consumers. More appropriate terms and conditions also might be devised if producers and downstream parties negotiated directly. In particular, pricing flexibility, difficult to achieve under current Federal Energy Regulatory Commission regulation of pipelines, might be accomplished in direct sales.

Greater competition also could encourage pipeline companies to be more aggressive in obtaining contract terms and concessions that allow pricing flexibility in response to changing demand. To the extent that distributors and end-users must deal through pipelines, the threat of losing sales as a result of outdated practices is diminished. If their customers can deal directly with procedures, pipeline companies will have greater incentives to renegotiate and adopt more creative arrangements.

Deregulation of natural gas field prices is likely to fundamentally change how gas is bought and sold and delivered from field to burner tip. In particular, pipelines no longer may operate in their traditional fashion as private carriers, buying gas from producers and reselling it for a profit to distributors. Instead, some form of contract carriage is probable, where producers and distributors have greater access to deal directly with one another and pipelines serve simply as transporters.

Such changes in pipeline carrier status will enhance price and output flexibility in gas markets. So, too, will modification of current contractual arrangements between producers and pipelines and between pipelines and distributors. Yet it is important to emphasize that changes in pipeline carrier status and in current contractual practices are mutually reinforcing. Indeed, policymakers should treat them not as substitutes but as complements. Taken alone, changes in carrier status can provide only limited relief.