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Pipeline Decontracting to Lead to New Ventures

Philip M. Marston

ompetition has an unnerving habit of rewrit- C ing the basic assumptions on which business is built. Decisions that seemed perfectly sensible at the time can appear ludicrous in hindsight, after competition has changed some fundamental ground rule that everyone took for granted.

Nowhere is this phenomenon more pronounced than where competition is introduced in a regulated industry. Here regulation has a tendency to write these basic assumptions into law, making them all the more powerful and resistant to change. This institutionalization of business assumptions may come formally, as where the Federal Power Com- mission wrote regulations decades ago that gener- ally required a new pipeline to show 12 years of ready supply behind it. More often, however, the process is more informal, as where businesses understand that departures from the “accepted wis- dom” may be viewed as imprudent management. It takes great clarity of vision, and not a little courage, for company managements to ignore the accepted wisdom under these circumstances.

In the gas industry, deregulation and competi- tion in the field markets caused wholesale changes in the way that buyers viewed gas reserves. Thus, as the field markets became effectively deregulated in the early 1980s, buyers began to reduce the level of

product they were willing to pay suppliers to keep in inventory. “Just-in-time” inventory management had come to the natural gas field markets well before it became a buzzword in the popular business press. Translated into the jargon of the industry, what this

Philip M. Marston is an attorney specializing in business and regulatory issues affecthg the natural gas and elec- tricity industries.

Printed on recycled paper. @ 0 1996 John Wiley 8 Sons, Inc.

INATURAL Q A S

1 EDITORIAL ADVISORY BOARD

Dough F. John, Esq. John, HenpmrB Esposito

J.nm C. Lengdon Jr., Esq. AMn, G m p , Stmuss, Hew& Fekl

Wlllkm R. Luthun, Vice Pmident ~roducdlon end Bastonoes

Ekcky McGoe, chlef counsel Merketing and GoVemmenr Athairs O w Enetgy Co.

Rlchud Q. Morgan, Esq. LeneBMntendorf

Fmdmlck Morlng, Esq. CIVndi & Wng

Thomu J. Norrlr, Senior yke PresMent T e n m Gas

John E. Olrorr, First Vioe Pmsident Menlll Lynch Piem Fenner 8 Smith Inc.

Brian b. ONolll, Esq. L e W , Lemb, G m e 81 MacRae

Notman A. Pederun, Esq, Jones, m y , Reevis & PogtJe

Carl v. sw0naan, President Swanson Energy Gmp# Ire.

Arlon R. Turdng, Pmsmnt ARTA Inc.

May Ann Wall#, Esq. WinU~w, stlmson, pulnam& Roberts

2 NATURAL G A S MAY 1996 Q 1996 John Wiley & Sons. Inc.

Pipeline Decontracting to Lead to New Ventures (Continued from page 1)

meant is that Reserve/Production (RIP) ratios fell sharply from historical levels, as customers were unwilling to pay for the capital locked up “down hole.”

By 1985, those industry observers who were intellectual prisoners of the ancien regime saw this rapid decline in RIP ratios as heralding the imminent onset of gas shortages and renewed curtailments. But those who understood the logic of markets saw the same decline in RIP ratios. These analysts worried that excess inven- tory was still too high, promising a continuation of the gas surplus “bubble” for years to come, together with increasing take-or-pay woes.

Ten years into the revolution wrought by FERC Order 436, the same kind of reevaluation of needed inventory is well underway with regard to pipeline transmission capacity. Whether called “decontracting,” “recontracting,” or “ca- pacity turnbacks,” this reevaluation of capacity contracting will have a profound effect on the structure of the regulated industry and, ulti- mately, on the structure of regulation itself.

Result of a Number of Factors Decontracting is not the result of just a single

change in circumstances, but rather the inevi- table result of a confluence of factors, including changes in prices, options-and risks. For a variety of reasons, shippers are discovering that they no longer need to reserve the same level of pipeline transmission capacity today as was appropriate in the past. Competition and the spur of competitive prices and alternatives are the major reasons for the change. But changes in information technology and business pro- cesses play a role as well.

To understand where this process is taking the industry, we need to analyze the factors responsible for the change. As detailed below, the change can be explained in three phrases: the price went up, the need went down, and the risks got out of hand.

The Price Went Up The price of capacity remains highly regu-

lated under the Natural Gas Act of 1938, which requires that the price be both “just and reason- able” as well as not “unduly discriminatory or preferential.” In loose practical terms, these standards have been interpreted to mean that

the price must be neither too high (unjust and unreasonable) nor too low (unduly discrimina- tory or preferential). In applying this “Goldilocks” standard over the decades, the Commission attempted to balance the interests of the resi- dential and industrial gas consumers by trying to force the industrial consumer to pay a changing share of the pipeline’s fixed costs.

In the price-fixing exercise known to aficio- nados as “pipeline rate design,” many decades ago the Commission began to require pipelines to recover a significant portion of their fixed, capital costs on the basis of actual usage, rather than as part of fixed demand charges to be paid irrespective of the customer’s actual use. The variable charge set the floor down to which LDCs could (and did) go in establishing prices for industrial consumers. Thus a federal pricing policy that increased pipeline usage charges tended to force up the price of gas service to industry in the hope of lowering the price to residential consumers.

- - - the price-fixing exercise known to aficionados as “pipeline rate design” . . .

From 1952 to the early 1990s, the level of fixed costs required to be recovered on the basis of variable usage has varied from 50 percent (the Atlantic Seaboard formula adopted in 19521, to around 30 percent (“tilted” Atlantic Seaboard on some pipes in the early 1960s), to 75 percent (the United formula during the curtailment years), and back to perhaps 25 to 30 percent under so- called modified fixed variable (MFV) rate design in the latter part of the 1980s. All of these formulas, adopted for a variety of articulated policy reasons, had the effect of lowering the price of reserving service during the peak pe- riod as compared to the alternative of not including any fixed costs in the variable charges.

That changed in the 1990s, when, as part of Order 636, the Commission required pipelines to set their prices for reserving capacity to recover all of their fixed costs. This new pricing approach, dubbed “straight fixed-variable’’ (SFV) rate design, had the immediate effect of increas- ing the price for reserving capacity to use during

MAY 1996 NATURAL GAS 0 1996 John Wiley 8 Sons, Inc.

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the peak periods. The articulated goal of the shift in pricing policy was primarily to allow U.S. domestic production to compete against Cana- dian production that arrived at the international border under such a pricing approach. How- ever, the primary effect of the change was to raise the price of holding less-than-fully used capacity quite significantly.

. - - primary effect of the change was to raise the price

of holding less-than-fully used capacity - . .

The Need Went Down While the price of holding blocks of capac-

ity was increasing, the need to contract for capacity--especially for large blocks of long- line, long-term capacity-was decreasing. This ongoing decline in the need for large blocks of long-line firm capacity results from a variety of developments. Changes in the storage market have been one major factor. Over the last decade, there has been a virtual explosion of new storage projects, offering customers a sub- stitute for meeting peak day loads. According to an Energy Information Administration study of several years ago, more than 80 new storage projects had been announced for completion by the end of the 1990s. These projects would increase daily deliverability by about 26 percent over year-end 1992 levels.

Moreover, under open-access the manage- ment of storage has shifted from the pipelines to the customers, resulting in sharply different patterns of storage use. The bottom line is that customers are using the existing storage assets more efficiently than was possible under the earlier regime. This trend further reduced the need for pipeline transmission to meet a given level of market-area demand. For example, in- field transfers of gas in a storage field from one customer to another were generally not allowed before Order 636. However, in the various im- plementation proceedings, customers were fre- quently able to win the right to transfer owner- ship of gas in a pipeline’s storage field without having to physically withdraw and reinject the gas. This ability to engage in in-field transfers significantly enhanced the flexibility, and hence reliability, of a given level of storage assets.

Another factor reducing the need to reserve large blocks of long-line capacity is the arrival of in-line transfer points on pipelines. In the oil pipeline industry, such in-line transfers have been common for decades. However, in the gas pipeline industry, pipeline tariffs generally pre- cluded a shipper from selling gas to another shipper except at a point where the ownership of the asset changed. As strange as it seems to us today, regulated tariffs generally prohibited a change in ownership of gas except at locations where there was a change in ownership of the steel surrounding the gas. These regulatory prohibitions tended to force shippers to engage in unnecessary physical transportation transac- tions simply to get gas delivered to a point where regulated tariffs would allow the parties to transfer title to the gas. Pipelines generally benefited from these rules (at least in the short term) because the restrictions artificially in- creased the transmission volumes.

Much more flexibility is on its way. At present the Commission defines a market center as a point where a number of different pipelines converge. This excessively restrictive definition means that the industry has not yet won the right to in-line transfer points as a general matter. Nonetheless, such points, known as pooling points, are available on many systems already. The market area shippers (primarily the LDCs) have shown themselves increasingly comfort- able shortening their contract paths to go from the pool point to market, rather than from the field to market. This tendency further decreases the demand for pipeline capacity.

Much more flexibility is on its way.

The Risks Got Out of Hand Over the last few years, the risks of contract-

ing under regulated tariffs for large, long-term blocks of capacity have also increased mark- edly. Managements at LDCs today face a plethora of risks that were unheard of a decade ago. At the federal level, LDCs face the risk that they may lose industrial customers’ throughput, as end users may increasingly hook up directly to the pipeline system. Even where physically served through an LDC, end users are increas- ingly substituting IT, short-term FT, or released

4 NATURAL GAS MAY 1996 0 1996 John Wiley & Sons, Inc.

FT acquired from third parties instead of making use of the LDC’s own pipeline contracts. This increase potentially leaves the LDC without a market for a portion of pipeline capacity rights that the LDC originally anticipated would be used by the end user.

Even more fundamentally, in state after state regulators are either studying, encouraging, or requiring the local distribution utilities to un- bundle their systems down to smaller and smaller levels, including residential customers. If the LDCs are removed, whether voluntarily or invoiuntar- ily, from the business of selling gas to residential customers, it is difficult to see why they would willingly retain the costs and risks associated with reserving upstream transmission capacity. This trend is particularly a concern where competing merchants may contract for that capacity on their own, perhaps at lower average costs due to their greater scale of operations and load diversity, leaving the LDC without customers for the re- served capacity. If this were not enough to give pause, the prospect of a restructured and competi- tive electricity industry is requiring nearly all gas utilities to carefully reexamine existing assump tions as to who serves what customers and with what assets.

The risks of being caught on the wrong side of all of these changes is further exacerbated by the prevalence of common tariff provisions that tend to shift these risks on the unwary buyer. Thus, a standard “Mobile-Sierra’’ clause means that the buyer has effectively agreed to pay any price that the regulated seller decides to charge, unless and until a third party (the federal government) decides that the price is too high. This may well mean that the buyer is subject to competitive pressures but is locked in to paying uncompetitive prices until the regulatory pro- cess catches up. A Mobile-Sierra clause is thus uncomfortably similar to the contract provisions that pipelines entered into with gas producers in the early 1980s. Then, the producers agreed to pay the maximum lawful price set by the federal government. In both cases, the buyer is relying on the action of the government to protect itself from price risk.

Yet in a world where competitive pressures demand immediate answers, relying on the formalistic protections of regulation-con- strained as regulation is by the procedural requirements of current law-means taking on a very considerable business risk.

Prognosis Responding to these trends, the decontracting

phenomenon is well under way. Pipelines serv- ing California have publicly announced that customers have turned back large blocks of the capacity rights that they previously held. South- em California Gas Company has announced that it will allow contract rights for some 457,000 dekatherms a day to expire on Transwestern as well as some 300,000 dekatherms a day on El Paso Natural Gas. Pacific Gas & Electric has provided notice to El Paso that it will allow about 1.14 billion cubic feet a day of contract rights to expire at the end of 1997. In December of 1995, the bulk of Natural Gas Pipeline Company’s firm contracts expired and new contracts were for lower volumes, shorter paths, and lessened contract terms, as compared to the past. Tennessee Gas Pipeline currently faces the expiration of substantially all of its capacity contract in the year 2000.

. - . decontracting phenomenon is well under way.

The Interstate Natural Gas Association of America (INGAA) has published the results of a pipeline industry survey of decontracting. The study indicates that the amount of pipeline capacity that cannot be subscribed under long- term firm contracts will rise significantly over the next few years, from about 4 percent to about 12 percent of total capacity. Perhaps even more significantly, the definition of what constitutes a “long term” contact will change. As illustrated by Exhibit 1, INGAA’s survey indicates that con- tract terms will shrink considerably, with over two-thirds of the new contracts being for terms of five years or less. Perhaps a third may be three years or less.

This anticipated shortening of contract terms has profound implications for pipelines and customers alike. It suggests that “recontracting” will become a permanent feature of the industry landscape, with pipelines needing to enhance their marketing capabilities, striving constantly to stretch out their portfolio of firm agreements. This phenomenon may or may not have impli- cations for the appropriate level of debt lever- age a pipeline should maintain. This level de-

MAY 1996 NATURAL GAS Q 1996 John Wiley 8 Sons, Inc.

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1 Exhibit 1. Expected Term of Recontracted Capacity

10-year terms 12-yeerterms

~ 1-year terms

&year terms

5-year terms

&year terms

Soum: N G M

year terms

pends on how comfortable investors become with a pipeline’s ability to keep its system fully used regardless of the maturities in its “book” of firm agreements.

The INGAA survey also indicates substantial regional variations. Pipelines serving the West Coast and the Midwest may face the greatest challenges in keeping their systems booked (with unsubscribed capacity amounting to as much as 25 percent for the West Coast pipes). Pipelines coming out of the Rocky Mountains and those serving the East Coast may have a relatively easier contracting situation.

The decontracting phenomenon will affect

local gas utilities as well.

These developments will have significant implications for the capacity release market- place as the amount of capacity available for release in the secondary market declines. This results from two factors. First, the total amount of capacity held by firm shippers under long- term contract will diminish, decreasing the over- all level of capacity available for release. In addition, the firm shippers will be continuing to

use more efficiently the capacity rights that they retain, again dimin- ishing the supply of capacity avail- able for release. The capacity that leaves the secondary market will migrate back to the primary mar- ket as the pipelines become more aggressive in marketing interrupt- ible and various levels of short- term firm service.

The decontracting phenomenon will affect local gas utilities as well. The large changes in the way that capacity is made available will present new opportunities and new risks. Utilities whose state regula- tory frameworks allow them to benefit from the more efficient utilization of their assets (including their pipeline capacity contracts) will see their opportunities increase.

Eventual Outcome: More Combinations The bottom line is that the decontracting

phenomenon presents opportunities for indus- try participants to work together to provide capacity management services to the market. Such symbiotic relationships may take a variety of forms. The industry has already seen the creation of ventures or alliances between capac- ity holders and capacity managers and between hub owners and hub operators. The need for risk management associated with capacity com- mitments may bring financial partners to the industry to “underwrite” capacity commitments just like stock offerings. The likelihood of major corporate changes in the electricity industry creates an entire new universe of potential partners and players.

This most recent phase of the transition to a full open-access environment, like the prior phases, will again enhance the role of natural gas in the U.S. energy mix. The ability to creatively integrate pipeline capacity into a competitively rebundled portfolio of energy goods and management services can only en- hance customer choice and supplier reliability. Hence, despite the risks and the costs, decon- tracting promises to help carry a robust and profitable gas industry well into the next cen- tury.

6 NATURAL GAS MAY 1996 Q 1996 John Wiley B Sons, Inc.