How Commodity Markets Drive Gas Pipeline Values

Deck: 

Has rate regulation become obsolete for natural gas pipelines?

Fortnightly Magazine - February 1 1998

On Jan. 30, the Federal Energy Regulatory Commission will hold a public conference to review the financial health of the pipeline industry. It will ask whether its regulatory framework still works; whether pipelines can still attract new capital for investment. %n1%n Does rate policy threaten the financial integrity of the pipeline industry? That very question may come before the Commission. %n2%n

Nevertheless, the FERC need not look far for an answer. If the pipeline industry should lie at risk, the cause may go no farther than the Commission itself. In fact, FERC ratemaking policy for gas transportation service now appears to jeopardize the ability of pipelines to recover costs.

Today's competitive markets increasingly prevent pipelines from achieving full cost recovery. During periods when the market places a lower value on pipeline services than the FERC's maximum allowed rate, cost recovery is impossible to the extent that shippers simply decline to purchase long-term firm transportation service. In the case of released capacity, and short-term firm and interruptible service, rates will be discounted to market levels. Studies by the U.S. Energy Information Administration and the Interstate Natural Gas Association of America have found that released capacity and interruptible transportation have been discounted by 60 to 65 percent less than maximum rates in the past three years. %n3%n

Similarly, during peak periods, when the market value of pipeline services exceeds the allowed rate, FERC regulation prevents the pipeline from collecting prices that will recover the full value of its services, in order to make up for losses sustained during the off-peak season. Buyers and sellers receive incorrect price signals. Shippers lack price incentives to use alternative resources, such as storage or fuel-switching. Bottlenecks ensue, creating the illusion of capacity shortages.

All this has come as the FERC has restructured the pipeline industry on the principle of unbundling (em separating pure transportation service from the sale of gas as a physical commodity. The new FERC framework has brought about two related results. First, natural gas now trades in competitive commodity markets that are consolidating into a single, unified U.S. market. Second, gas commodity markets now determine the economic value of pipeline transportation services in many parts of the country. Thus, even as the FERC has sought to isolate pipeline services from commodity sales, it is within the commodity markets that one can see revealed the true price for gas transportation.

Two examples (winter and summer) illustrate how today's gas market works and how FERC ratemaking policy has failed to recover costs in an environment that has become increasingly competitive.

A WINTER EXAMPLE. During a cold week, suppose the gas price is $2.50 in Texas, and $7.00 at the city gate in Chicago. In other words, the pipeline adds $4.50 to the value of the gas by transporting it to market from the production area. But suppose the shipper has firm capacity rights on the pipeline, for which the regulated rate is equivalent to $1.00 on a volumetric basis. The shipper pays only $1.00 for a service worth $4.50, gaining economic rent from the pipeline. Moreover, the shipper has no incentive to release the capacity in the secondary market, since the FERC's price cap limits the release price to $1.00. This shipper will hoard capacity, shutting out other potential shippers who might be willing to pay more for the resource.

A SUMMER EXAMPLE. During hot weather, suppose gas sells for $1.85 in Texas and only $2.00 at the Chicago city gate. Thus, the value of transportation from Texas to Chicago is no more than $0.15. Any shipper paying the regulated rate for transportation (again, the volumetric equivalent of $1.00) would naturally seek to release the capacity to mitigate costs, but would find other shippers unwilling to pay more than $0.15, and certainly unwilling to match the

regulated price of $1.00, whether for short-term firm or interruptible transportation.

Overall, these examples demonstrate a central feature in pipeline transportation. Gas commodity markets establish the value of pipeline services. It is the basis differential (em in this case, the difference in price between Texas and Chicago (em that measures the value of gas transportation through the interstate pipeline network (see Figure 1).

In fact, a strong case can be made for market-based rates on all pipeline routes between competitive commodity markets. Market-based rates on these routes would remove bottlenecks and improve pipeline use and efficiency.

Discovering the Transport Price

By definition, the delivered price of gas in a market area consists of the supply price and the transportation charge: Supply Price + Pipeline Markup = City-Gate Price.

These three components have, over time, been related in a variety of ways. When the gas market was completely

regulated, the city-gate price represented the sum of the regulated wellhead price and transportation charge. Later, as wellhead price deregulation proceeded and the gas bubble developed, many producers considered their prices as a netback (em computed as the difference between the regulated city-gate price and the transportation charge. Today, however, where competition exists at both ends of the pipeline, the city-gate and supply prices are market-determined; the difference between them represents the value of the transportation service.

If both commodity markets are competitive, then the supply and city-gate prices will be determined separately by conditions in their respective areas. The pipeline will be a price-taker, forced to accept a residual markup. In this case, the equation is transposed. The competitive supply and city-gate prices determine the pipeline markup: Pipeline Markup = City-Gate Price - Supply Price.

In other words, when a pipeline connects two competitive gas commodity markets, the value of the pipeline's services can be determined by competitive forces and is measured by the price differential between the two commodity markets.

In this case, shippers will be unable to buy gas at a price below market or sell gas at a price above market. They will refuse to pay more than market value for pipeline transportation services. The market value of the pipeline service will be determined on a spot basis by the difference in spot commodity prices between the two competitive markets connected by the pipeline. The pipeline will have no market power, even if it is the only pipeline between the particular markets, as shown by the following example.

Suppose there is only one pipeline running from Texas to Chicago, but gas supply is competitive both in Texas and at the city-gate in Chicago. Texas suppliers have access to many city-gate markets other than Chicago; Chicago consumers have access to many suppliers outside Texas.

Suppose the gas price in Texas is $2.50 and the city-gate in Chicago is $7.00. The value of the transportation by the pipeline is $4.50. If the pipeline charges $5.00 for its service, the delivered cost of Texas gas in Chicago will then be $7.50. But nobody will buy it, since Chicago consumers can purchase from other suppliers at a delivered price of $7.00. The only way the pipeline could charge $5.00 is if it could purchase gas in Texas for $2.00. But this scenario is unlikely since the gas market in Texas is competitive. In the end, no gas will flow from Texas to Chicago. The pipeline is unable to set an above-market price. So although only one pipeline runs between Texas and Chicago, it will not have monopoly power because it connects two competitive gas commodity markets.

If pipelines connecting competitive commodity markets are unable to exercise market power, then rates on those segments can be deregulated with no adverse impacts on competition. A first step in identifying pipeline candidates for market-based rates, therefore, is to identify workably competitive gas commodity markets.

Competition in Commodity Markets

A fundamental premise of wellhead price deregulation and pipeline open-access mandates was that gas wellhead markets were essentially competitive. The growth of regional spot markets, the popularity of gas futures contracts, and the emergence of gas trading hubs and market centers have confirmed this assumption. A large body of economic research has documented the integration of various regional gas commodity markets into an increasingly unified national (or North American) gas market over the past decade. %n4%n

EES North America

A visual examination of prices from January 1996 through August 1997 shows that price levels are not only moving in similar directions but are now actually converging across the country in both supply areas and market areas. Figures 2 and 3 show commodity prices in several market and supply areas, respectively.

The market areas in the East (see Figure 2), experienced extremely cold weather and highly volatile prices at the start of 1996. Simultaneously, prices in Los Angeles (Topock and Wheeler delivery points) were low and stable. By April, however, gas prices in the eastern market converged. Los Angeles prices followed suit in early August 1996. Since then, city-gate prices across the country appear to have moved in a single pattern.

Similar trends are observed in production areas (see Figure 3). Price patterns in production areas supplying the East were similar to those in the end-use markets. Similarly, prices in these production areas began to converge by April 1996 and have moved together ever since. Prices for the San Juan Basin and Opal Hub, which supply the California market, were much lower in early 1996, reflecting the softer western market conditions. In June, San Juan prices began to move toward those of the other production areas. Opal prices lagged; they did not begin to rise until October. Since October 1996, however, production area prices across the country have moved together.

A correlation analysis shows that both market areas and supply areas became highly correlated, with pair-wise correlations exceeding 0.96 in market areas and 0.93 in supply areas from August 1996 through August 1997.

If we stipulate that gas wellhead markets are competitive, it follows that pipelines connecting wellhead markets (e.g., a line between the Henry Hub and the Katy Hub) would have no market power. But suppose a pipeline delivering gas from the Katy Hub to the Henry Hub does possess market power and can set an above-market price for its services. Then the price of gas delivered to the Henry Hub will exceed a competitive price. If this price can be sustained at the Henry Hub (em i.e., if the pipeline can exercise market power there (em then the Henry Hub is not a competitive market, contrary to our original assumption.

If the Katy and Henry hubs are competitive, then no entity, not even a pipeline, can exert market power. Pipeline routes between competitive hubs are, therefore, prime candidates for market-based rates.

The competitiveness of various city-gate markets is not so well established. Often, a single large purchaser (such as an LDC) dominates a city-gate that only one or two pipelines serve. Such market configurations are hardly competitive. However, competition is evident in other areas, both from greater access to pipeline services and in the development of market centers. This analysis examines three such consuming areas: (1) New York and New Jersey, (2) Chicago and (3) Los Angeles.

Pipelines from several supply areas serve the New York-New Jersey market area. Consumers in and around New York can receive Appalachian gas on the CNG and Columbia Gas transmission systems; Louisiana gas on Columbia Gulf/Columbia Gas, Tennessee, Texas Eastern or Transco pipelines; or Canadian gas on the Iroquois and Tennessee pipeline systems.

Consumers in the Chicago area have access to Canadian gas via Northern Border Pipeline and Natural Gas Pipeline of America, or the Great Lakes/ANR system; to Permian Basin gas via NGPL and Panhandle Eastern pipelines; to Rocky Mountain gas via Colorado Interstate Gas and ANR pipelines; to Louisiana gas via ANR, NGPL, Tennessee/Midwestern and Trunkline; and to South Texas gas via NGPL, Tennessee/Midwestern and Trunkline.

Los Angeles consumers have access to Rocky Mountain gas via the Kern River Pipeline; Canadian gas via the PGT and SoCal pipelines; gas from the San Juan and Permian Basins via Transwestern and El Paso pipelines; and gas from the Anadarko Basin via El Paso Pipeline.

It is difficult to argue that any individual pipeline serving these markets can exert any market power. These pipeline routes also may be good candidates for market-based rates.

Basis Differentials

When a pipeline moves gas from Texas, where its value is $2.50, to Chicago, where its value is $7.00, the pipeline adds $4.50 to the value of the gas. Thus, the basis differential between Chicago and Texas measures the value of the pipeline's transportation service. Basis differentials therefore provide a lot of information about the markets for gas transportation services around the country (see Figures 4 and 5).

The figures show the average basis differential for the period January 1996 through August 1997 for seven supply areas and three market areas. For example, Figure 4 shows that pipeline transport services out of Opal, Monchy and San Juan are more valuable than for the other supply areas, whether gas is delivered to Los Angeles, Chicago or New York.

This information can be used to evaluate the likely profitability of capacity additions. For example, if the $1.50 average basis differential between Opal and New York is expected to persist, then a new pipeline costing more than $1.50 on a volumetric average basis would not expect to recover its costs and should not be built.

In similar fashion, Figure 5 shows that New York is the most profitable area for pipeline transportation services, followed by Chicago. The low values into Los Angeles reflect the abundance of pipeline capacity there, which has led to significant turnbacks of capacity in recent years.

The negative basis differentials into Los Angeles from the Waha and Anadarko areas require further elaboration. Since the basis differential is calculated as the city-gate price minus the supply price, a negative differential indicates that the supply price is greater than the city-gate price. During much of 1996, prices at the Waha hub and in the Anadarko basin were higher than the Los Angeles city-gate price due to high demand in the East. Most gas flowed east from Waha and Anadarko during this period. Negative differentials between Los Angeles and the Katy and Henry hubs reflect the fact that prices at these hubs are consistently higher than prices in Los Angeles. Moving gas to Los Angeles from Katy or Henry would prove highly unprofitable.

These comparisons help to explain the pattern of pipeline capacity expansions now in the planning stage. A comprehensive study by the Canadian Energy Research Institute %n5%n lists a total of 27 billion cubic-feet per day of planned capacity expansions in Canada, the United States and Mexico. None of these projects was aimed at the California market. However, 16 Bcf/day of planned capacity additions (59 percent of the total) is intended to increase access to the midwestern United States and New York market areas, consistent with the high values currently attached to pipeline services in these areas.

Pipeline Rates and Values

Historically, cost-of-service rates have been set for pipelines by the FERC, with the objective of full cost recovery. On those routes where competitive commodity markets are establishing the market value of pipeline services, however, there is no reason to expect cost-based rates to reflect market valuations. Where rates and value differ, pipelines may not recover their costs of service and inefficiencies are likely to arise in the allocation of pipeline services among shippers.

Figures 6 and 7 illustrate the discrepancy between cost-of-service rates and the value of service, as reflected in basis differentials for the Henry-to-New York and Katy-to-Chicago routes, respectively. In these figures, the basis differentials reflect spot prices published in Natural Gas Week from Jan. 8, 1996, through March 10, 1997. Pipeline rates for firm transportation were calculated from the rate schedules in pipeline tariffs (maximum allowed rates) and were converted to a volumetric measurement assuming a 100-percent load factor. (For most pipelines, the maximum firm transport rate at a 100-percent load factor is equivalent to the maximum interruptible rate.) All rates were adjusted to include the value of gas retained by the pipeline, according to the fuel retention rates specified in rate schedules. Rates for pipelines serving a given corridor were combined into a single average rate.

These comparisons serve to illustrate the nature of the discrepancy between rate and value. (They are not designed to estimate the actual extent of the discrepancy. Thus, the rates shown may be greater than or less than the actual prices paid.)

On the Henry Hub-New York corridor, from January through March 1996, extremely cold weather often pushed the weekly average value of pipeline services from Louisiana (measured by the basis differential) above $3.00/MMBtu, and as high as $6.00 in late February. Since then, weekly transportation values have remained less than $1.00, except the first week of January 1997. Average pipeline rates on this corridor were much lower than their market value in the first three months of 1996. Rates exceeded value throughout the non-heating season but were roughly in line with market value for most of the 1996-97 heating season. (See Figure 6.)

As noted earlier (see Figure 5), the value of transportation services into Chicago is generally lower than it is into New York. However, as in the New York example, transportation values into Chicago show considerable seasonal variability, and pipeline rates fail to conform to value. Rates consistently exceed value in the off-peak season and may be much lower than value in the heating season. (See Figure 7.)

Up until now, long-term contracts for firm transportation have cushioned a large part of the pipeline industry from short-term market impacts. The examples shown here in large part have affected only short-term markets, such as markets for released capacity, and for interruptible and short-term firm transportation, which compose more than 30 percent of pipeline transportation volumes. %n6%n However, as long-term firm transportation contracts expire in the next few years, an even greater portion of the industry will be exposed to market forces. The conflict between competition and cost-of-service regulation could become untenable.

 

Endnotes:

1. Conference on the Financial Outlook of the Natural Gas Pipeline Industry, Docket No. pl98-2-000 (notice of public conference, issued Dec. 17, 1997).

2. The FERC has asked conference participants to address a host of questions, such as: (1) How have changes in the competitive structure of the natural gas industry affected the risks faced by pipelines? (2) How does [FERC] rate design policy affect pipeline risk? (3) Are pipelines experiencing difficulty attracting capital necessary for investment in improved jurisdictional services for their customers?

3. U.S. Energy Information Administration, Natural Gas 1996: Issues and Trends, Washington D.C. 1996; and Interstate Natural Gas Association of America, Gas Transportation Through 1994, 1995; Gas Transportation Through 1995, 1996; and Gas Transportation Through 1996, 1997.

4. See, for example, Arthur De Vany and W. David Walls, "Pipeline Access and Market Integration in the Natural Gas Industry: Evidence from Cointegration Tests," The Energy Journal, 14(4), 1993; De Vany and Walls, "Open Access and the Emergence of a Competitive Natural Gas Market," Contemporary Economic Policy, XII(2), 1994; Emile J. Brinkmann and Ramon Rabinovich, "Regional Limitations on the Hedging Effectiveness of Natural Gas Futures," The Energy Journal, 16(3) 1995; Martin King and Milan Cuc, "Price Convergence in North American Natural Gas Spot Markets," The Energy Journal, 17(2) 1996.

5. Robert Mahan and Karen Morton, Natural Gas Pipelines: New Pipelines and Expansions, Canadian Energy Research Institute, Calgary, April 1997.

6. Interstate Natural Gas Association of America, Gas Transportation Through 1996 (1997).