THE FERC TAKES SUGGESTIONS ON THE FUTURE OF THE GAS INDUSTRY.

Earlier this year, the Federal Energy Regulatory Commission opened a discussion of issues facing the natural gas industry. Its aim? To set "regulatory goals and priorities" for the era following from Order 636, issued in 1992. %n1%n

To gather input, the FERC scheduled a two-day public conference. It asked for comments on a myriad of topics, ranging from cost-of-service rates to hourly gas pricing and services. %n2%n

The conference followed in late May, attended by industry reps and trade-press "gasarazzi." At one point, sensing a lack of creative energy, Commissioner James Hoecker (not yet named the FERC's new chair) implored a witness to push the envelope: "Let's do some thinking outside the box. I'm not hearing much 'big picture' here."

The problem, however, may rest not so much with a lack of will as a lack of reward. Even as the FERC has unleashed upstream markets, it has done little to encourage downstream growth, leaving the pipelines and competitors locked in a zero-sum game.

The point was driven home by Claire A. Burum, v.p. for rates and regulatory affairs, signing off on comments for Koch Gateway Pipeline. She noted that progress is best achieved if the FERC "narrows its focus to the real issues," and "is not distracted by irrelevant arguments regarding division of the economic pie, especially since the size of the interstate pipelines' slice can only get smaller and never larger."

That said, here is a look at some of the issues, gleaned from hundreds of pages of initial comments filed by pipelines, local distribution companies, marketers, vendors, consumers, shippers, associations and regulators.

Of course, these issues serve only as an appetizer for the main course: How will electric restructuring alter the gas industry?

VIRTUAL CAPACITY

(How are pipelines "natural monopolies" when customers compete against them?)

Congress enacted the Natural Gas Policy Act of 1978 partly to integrate what then were two distinct gas markets: Interstate (regulated under the Natural Gas Act, with wellhead price control) and intrastate (largely unregulated).

Today, that effort is touched with irony. Some say that the commission, no matter how well-intentioned, has again created a bifurcated market (em one regulated and one deregulated, but both in interstate commerce. This dual market, the theory goes, pits traditional pipelines (still regulated) against producers, marketers, LDCs, intrastate and "Hinshaw" pipelines, who can now trade in pipeline capacity as "virtual pipelines" and compete more efficiently than interstate pipelines. (See, Comments of the Coastal Companies, pp. 4-5.)

The comments generally agree that the FERC's pricing policies for gas pipelines have failed to keep up, adding to risk for those buying pipeline capacity. Pipeline tariffs for firm capacity remain tied to cost. However, capacity value now appears more dependent on commodity prices (the "basis" differential), especially in areas where pipelines face significant competition. Marketers, aggregators, and off-system LDCs can take advantage, trading in pipeline capacity to capture value in short-term market swings.

Concerns about "turnbacks" and unsubscribed firm capacity appear fairly typical:

[T]here is now a seemingly unbridgeable gap between the length of contract term customers are willing to accept and what pipelines need in order to recover costs.

Customers want [contracts] as short as possible and simply will not sign up for long-term capacity. Pipelines, denied the use of variable pricing ... have only the variable of a contract term. ... If the price was right, pipelines would be able to accept shorter-term contracts. (Pacific Gas Transmission Co., p. 2.)

Some say the traditional pipes have lost control of their product:

Instead of controlling virtually all their own capacity, pipelines today control almost none. Any 'capacity rights' discussion should include the question: 'Do pipelines have any capacity rights?' (The Williams Cos. Inc., p. 14.)

Meanwhile, control over pipeline capacity has migrated to marketers, aggregators, and off-system LDCs. Ironically, they appear to be in a better position to compete than the pipeline itself. %n3%n

SECONDARY MARKETS

(Why a price cap or right of first refusal?)

If any gas policy has proved a thorn in the side of federal regulators, surely it must be the price cap (at the interstate pipeline's tariff rate) on pipeline capacity released and then resold separately in the secondary market.

Recently, the FERC set up an experimental pilot program to remove the price ceiling, but met with mixed success. %n4%n Even so, hope still lives that the FERC will see fit to lift the price cap. %n5%n Any effort to lift the price cap faces a "Catch-22." When LDCs release capacity, it competes against short-term firm and interruptible capacity offered by the pipelines. Thus, the FERC does not favor lifting the cap if LDCs can exercise market power behind the city gate. (Williams Cos., p. 53-54.) Retail gas choice for all customers would mitigate such concerns, but it hasn't arrived yet. One reason for the delay stems from concern that LDCs face stranded costs from losses connected with unused pipeline capacity. (Columbia Gas Transmission Corp., pp 10-11.) And why is that? Well, because the LDCs bought firm capacity at the top of the market, but are now forced to sell unneeded capacity below value because of the price cap.

And so it goes. Any solution depends on new questions: Can the FERC craft regulatory policies for interstate pipelines designed specifically to foster competition at the state level? Will such authority conflict with state PUC prerogatives? (See below, "Retail Choice.")

Another important aspect of capacity release concerns the right of first refusal. For those capacity contracts where the term equals or exceeds one year, capacity holders own a "preferential right" to tie up that capacity simply by matching another cost-based bid for a five-year term, %n6%n even if the original bidder (a potential new pipeline customer) would have been willing to pay more or sign up for a longer term. (Williams Cos., p. 18.)

This right of first refusal appeared to draw as many negative comments as just about any other current aspect of FERC gas policy. A typical comment came from the Coastal Cos.:

While ... there may be genuine exceptions, as a general proposition, the commission should eliminate the right of first refusal requirement altogether. By permitting capacity holders to match the terms of competing offers of up to a maximum of five years, the commission places unnecessary and unwarranted bargaining power in the hands of existing capacity holders who can ... selectively retain valuable capacity and preclude a workably competitive market. (Coastal Cos., p. 24.)

STREAMLINING NEW CONSTRUCTION

(They will come, if you can build it.)

At the technical conference held on May 29 and 30, Williams Cos. CEO Keith Bailey proposed a way to streamline the process of certifying construction of new pipelines. His pipeline, he said, would willingly trade the right of eminent domain for relaxation of certification rules at the FERC. In written comments, Williams said pipelines should be allowed to begin construction on acceptance of a certificate, with a written commitment to meet environmental and other performance objectives. (Williams Cos., p. 26.)

Consolidated Natural Gas Co. urges the FERC to extend "blanket" certification to include "routine" permits under environmental and historic preservation laws. It says its pipeline affiliate, CNG Transmission Corp., has obtained generic clearance from the Fish and Wildlife office at the U.S. Department of Interior for all pipeline replacement projects of less than 500 feet in length. (CNG, p. 13.)

Another idea would combine blanket certification with de minimis exemptions, with:

• Small Projects. Simplified rules for projects with a de minimis size and environmental impacts; %n7%n

• Protest Rulings. Authority delegated to the Office of Pipeline Regulation for a quick ruling on protests, so that parties know "up front" whether ex parte rules apply;

• Shorter Notice. Protests filed in 30 days, not 45;

• Landowner Requests. Relief for "miscellaneous rearrangements," such as minor adjustments (height, relocation, etc.) at request of landowners;

• Delivery Taps. Quick handling under 18 C.F.R. sec. 157.208;

• Automatic Abandonment. Expanded criteria under 18 C.F.R. sec. 157.216 to include laterals, taps and other receipt facilities (including fuel compressors) abandoned through non-use; and

• Segment Replacements. Allow short segments to be replaced with different-sized pipe (waive "substantially similar capacity" rule), so long as overall capacity of lateral or system segment is not affected. (K N Interstate, pp. 12-14.)

The NorAm Trading and Transportation Group %n8%n also has suggested using the procedures set forth in 18 C.F.R. sec. 157.206(d) %n9%n as a model for review of pipeline construction projects otherwise certified under NGA sec. 7.

Under the NorAm idea, "[t]he staff could determine that the project would have no significant impact on the environment and would issue a 'finding of no significant impact' (FONSI). ... This procedure ... is different from ... a regulatory approach in which the pipeline gathers together all environmental materials which it believes are relevant." (NTTG, pp. 23-24.)

PRICING NEW FACILITIES

(Rolled-in rates: a subsidy?)

Current FERC policy allows rolled-in pricing %n10%n for new pipeline facilities that are integrated with existing facilities and produce system benefits without unduly increasing rates for customers. Operational benefits include: 1) increased system or operational reliability, 2) better access to new supplies or markets or 3) greater flexibility to meet imbalances or otherwise boost efficiency. Financial benefits might include: 1) adding new demand, 2) replacing lost demand, 3) reducing customer costs, 4) economies of scale or 5) reducing the cost of future expansion. The FERC invokes a presumption before construction in favor of rolled-in pricing when benefits are realized and any rate increase to current customers totals 5 percent or less. %n11%n

The Indiana Utility Regulatory Commission opposes the FERC's policy on rolled-in pricing, which it describes as "legally subsidized competition." It believes that any project that increases system rates at all should not qualify for rolled-in pricing, unless the pipeline can show that benefits are proportional to costs and could not be obtained by an alternative strategy.

The URC cites the familiar concern that small, incremental capacity additions can qualify artificially under the 5-percent test. It adds:

Theoretically, the same pipe in the same location ought to have roughly the same benefits for all potential users in a seamless national pipeline system. (Ind. URC, p. 8.)

Not surprisingly, The Williams Cos. support current FERC policy (Williams, p. 29), while the United Distribution Companies opposes rolled-in pricing for pipeline facilities that bypass LDC transportation. %n12%n "[F]air, head-to-head competition between LDCs and pipelines is one matter, while competition ... underwritten by other pipeline customers, through rolled-in rates, is quite another." (UDC, p. 20.)

NEGOTIATED TERMS & CONDITIONS

(Impossible to police?)

FERC Order 636 stressed "comparability" of service. Today, five years later, nearly everyone agrees that gas pipelines need more flexibility in tailoring terms and conditions of service to specific customers. The comment, "One size no longer fits all," appears again and again.

Last year, the FERC inquired whether to allow pipelines to negotiate terms and conditions of service, just as it allows for rates, but said it was "not willing to permit the negotiation of individual shipper-customized terms of service at this time." %n13%n Questions remain. Would that policy place small-volume pipeline customers at a competitive disadvantage? Would it grant too much market power to pipelines in areas served by only a single long-haul pipe?

Many commenters call for negotiated terms and conditions. %n14%n One such pipeline, El Paso Energy Corp. %n15%n offers a unique angle. It sees no problem with market power as long as customers remain free to negotiate a lower rate for diminished service that hold little value for them in particular, or to pay a higher rate for enhanced service with a higher value for the individual customers. %n16%n

El Paso offers a slew of examples of diminished and enhanced services that it feels should be left open to negotiation:

• Diminished services: Customer relinquishes 1) some or all secondary receipt and delivery points, 2) capacity release rights, 3) right to segment released capacity (segments of contract path not separately marketable), 4) overrun rights (for customer with predictable daily needs), 5) intra-day nomination rights, or 6) force majeure protection (for customers with their own storage facilities or "swing supply" options).

• Enhanced services: Pipeline consents to 1) more flexibility in hourly takes, 2) redundant delivery points rather than prorating or allocating firm entitlements across all delivery points, 3) delay payment of invoices, 4) shorter notice period to exercise contract rollover rights, 5) more flexible storage withdrawal rights than provided by tariff ratchet or 6) more force majeure credits. (El Paso Energy Corp., pp. 18-22.)

Not everyone agrees. NGC Corp., better known as Natural Gas Clearinghouse, argues that if pipelines negotiate terms and conditions, "It will be impossible to police discriminatory acts." It advises the FERC to reject any pipeline proposals to "take away or reduce existing services and then add them as an extra." (NGC, pp. 5,6.)

The American Forest and Paper Association adds that any pipeline allowed to negotiate terms and conditions ought to file triennial rate cases and abide by a "most-favored-nation" clause allowing any other shipper to request the same negotiated terms. (AF&P Asso., pp. 27-28.) By contrast, NorAm offers this idea: Pipelines should be allowed to negotiate terms and conditions with any LDC that is soliciting bids for transportation service that deviate from the pipeline's tariff. (NTTG, p. 11.)

Citing a pre-636 court decision, Tejas Power Co. v. FERC, %n17%n the Pennsylvania Office of Consumer Advocates argues that the FERC must ensure comparability of service to protect captive costumers and thus must reject negotiated terms and conditions. It admits that Tejas belongs to a different era, %n18%n but finds it analogous to today's market:

In Tejas Power, captive customers were denied access ... to the critical storage and upstream pipeline capacity services which had been part of the bundled sales service. With [such] access, customers with low load factors, such as LDCs serving largely residential and small commercial populations, could not take full advantage of lower-priced gas supply. ... To allow negotiated terms and conditions of service results in a major step backwards.

Instead, the OCA suggests filed pipeline tariffs that make service flexibility available to all customers on equal terms regardless of negotiating leverage. (Penn. OCA, pp. 10-11.)

RETAIL CHOICE

(Should FERC weigh in on state-level questions?)

A strong difference of opinion emerges from the comments regarding how far the FERC should go in "assisting" the state public utility commissions and LDCs to achieve workable retail access.

Columbia Gas Transmission Corp. and Columbia Gulf Transmission Co. (joining in one set of comments) advocate the activist view:

FERC can play a role in minimizing stranded costs associated with LDC unbundling (em as well as enabling pipelines to address capacity contracting issues (em by permitting pipelines [to exercise] flexibility in designing services required by entities serving unbundled retail customers. (Columbia Gas, p. 12.)

The key lies with stranded costs from excess pipeline capacity, which drives demand for retail choice in gas and, in a sense, is the gas equivalent of cheaper electric generation. Columbia Gas explains:

The emergence of a diverse retail customer base is coinciding to some extent with the expiration of long-term contracts between many pipelines and their LDC customers. This is requiring pipelines to examine their current contracts for firm capacity. ... Stranded costs will be created to the extent that LDCs are holding pipeline contracts which they cannot assign to those new entities [e.g., marketers and aggregators] who are stepping into the LDC's merchant shoes. ... Clearly, an effective means of addressing upstream pipeline costs must be found before retail unbundling can reach its full potential. (Columbia Gas, p. 12.)

The New York Public Service Commission raises another point. As it explains, FERC policy on storage capacity also plays an important role in speeding the transition to retail choice:

The availability of storage is a required component of moving retail access programs forward. ... [However], the pipelines have expressed their concern regarding the operational and administrative problems that would result from having individual storage accounts for perhaps thousands (to millions) of individual small customers. It is clear that such a system would be exceptionally burdensome. ... The above describes one example of how existing rules [at the FERC, presumably] may be presenting a significant obstacle to achieving meaningful open access programs. (N.Y. PSC, pp. 7-9.)

Nevertheless, many other commenters, such as the California Public Utilities Commission, strongly forbid the FERC to take too active a role in aiding or abetting retail access at the state level: "We urge the FERC to respect the jurisdiction of state commission to decide whether to unbundle the LDC's services or the extent of unbundlng which must take place." (Calif. PUC, p. 7.)

This view draws strong support from the recent case of General Motors Corp. v. Tracy, %n19%n in which the U.S. Supreme Court reaffirmed that the Natural Gas Act "was drawn with meticulous regard for the continued exercise of state power [and] not to handicap or dilute it in any way."

UNLAWFUL BUNDLING

(Impediment to market centers?)

FERC Order 636 was designed to create a transparent national market for the gas commodity and to transform the pipelines into a networked national grid, marked by regional trading hubs and market centers, rather than a collection of independent linear and one-dimensional transportation lines.

Some claim, however, that long-haul pipelines are blocking that vision.

For instance, NorAm warns that inadequate segmentation between production and market areas could discourage market centers for commodity and capacity trading. It charges that some long-line pipelines use rate design and cost allocation techniques to bundle their production area costs into their market area rates. Says NorAm, "[T]his restricts the customer's ability to choose another production area pipeline and restricts the customer's use of competing supplies from the basins accessed by the other pipeline." In other words, the customer will continue to use a single pipeline for both production-area and market-area services, because the customer will have already paid for production-area services in the improperly bundled rate. (NTTG, pp. 7-8. 27-28.)

Citing a discussion by Commissioner Massey in a 1996 opinion %n20%n and a more recent order %n21%n barring the practice, NorAm asks the Commission to be especially vigilant to root out any unlawful bundling by the long-line pipes.

GATHERING ON THE OCS

(Bootstrapping jurisdiction?)

Having extricated themselves from their historic merchant sales function, most interstate pipelines no longer need to be in the business of gathering produced gas. Instead, they have transferred their gathering function to other firms, either by "spin-off" or "spin-down." The FERC has applauded, noting that customers will ultimately benefit by obtaining gathering services from nonjurisdictional entities." %n22%n According to the Williams Cos., however, commission policy has come to "an abrupt halt" at the shoreline of the Gulf of Mexico, where, the argument runs, the FERC has been unwilling to extend its pro-competitive policy of deregulating the gathering function.

In particular, Williams claims that a new functional test espoused in the FERC's Outercontinental Shelf Policy Statement %n23%n will tend to reclassify gathering facilities improperly as jurisdictional, based on their proximity to existing, regulated OCS infrastructure pipelines. This new "bootstrapping" policy, says Williams, will undercut a 1989 FERC decision %n24%n to adopt a primary function test to define exempt gathering facilities. (That case, according to Williams, classified as exempt gathering facilities certain offshore pipelines of "increasing lengths and diameters, in correlation to the distance from shore and [to] the water depth of the offshore production area.")

Thus, complains Williams, "offshore systems now are simply found to be of similar scale to traditional long-line interstate pipelines and thereby jurisdictional." (Williams Cos., pp. 39-44.) %n25%n

HOURLY GAS TRADING

(Cost effective?)

As explained by one major pipeline system, the Coastal Cos., %n26%n there's a big difference between providing gas transportation service for a single hour versus providing hourly service under an annual or monthly contract. %n27%n Pipelines may be able to provide the latter service, says Coastal, but, depending on system operations, most cannot offer the former.

As the Industrial Gas Consumers %n28%n explain, hourly gas service and trading are "imaginable," but are attended by "significant practical difficulties." If fact, IGC notes that the under guidelines of the Gas Industry Standards Board, "streamlined" capacity release takes at least 2.5 hours to implement, indicating that hourly transactions could not occur. (IGC, p. 17, 18.) Gas Clearinghouse believe the cost of system-wide hourly trading would outweigh the benefits, but it urges the FERC to complete its standardization of procedures for intra-day nominations, to allow pipelines to respond to the needs of gas-fired power producers, as does Greg Lander at TransCapacity LP. (NGC, p. 8; TransCapacity, p. 4.)

Also, not all pipelines operate in the same manner. Concerns over compression and line-pack requirements may prohibit pipeline systems driven predominantly by weather conditions to schedule hourly transactions 24 hours a day. (Williston Basin Interstate Pipeline Co., pp. 6-7.)

Nevertheless, restructuring in the electric industry appears certain to increase the need for hourly pricing of pipeline capacity, as explained in these comments by from Columbia Gas Transmission Corp. and Columbia Gulf Transmission Co., outlining three likely scenarios:

• Off-Peak Power. Electric service penetration rises in off-peak end-use energy markets, with time-of-use pricing and demand applications;

• Btu Substitutes. Customers call on pipelines and LDCs to differentiate services and prices and to offer a meaningful Btu competition as a substitute for off-peak electricity; and

• Quick-Response Turbines. Quick ramp-up becomes more critical for electric generation, as electricity reserves tighten, transmission loading rises and gas-fired power producers rely increasingly on just-in-time gas supplies. (Columbia, p. 15.)

Operating Standards

(Whither GISB?)

The comments reveal a fair degree of dissatisfaction with the Gas Industry Standards Board.

Rather than focus GISB's efforts on business practices or a debate over policy issues, Natural Gas Clearinghouse urges the FERC to "focus GISB on its original mission, standardizing electronic communications." (NGC, p. 42.) %n29%n

Peoples Gas Light and Coke Co. and North Shore Gas Co. see GISB only as an extension of working groups on electronic bulletin boards. They believe that the FERC has given "uncritical deference" to GISB proposals, even as the board has "delved into" areas not designated for standardization, or not shown to be cost-effective. %n30%n

"[C]onsensus has often been difficult to achieve," writes Peoples Gas, and standards are "diluted to a level of almost meaningless generality." (Peoples Gas, p. 5-6.)

As Koch pipeline puts it, GISB's time has "come and gone." It asks the FERC to "thank GISB for a job well done," and allow the market to drive further progress. (Koch, p. 56-57.)

FINANCIAL INTEGRITY

(Danger signs on Wall Street?)

Some concern emerged at the commission's two-day technical conference over the adequacy of pipeline rates of return on common equity and whether the industry was falling behind other sectors in its ability to attract and retain investment capital. The Natural Gas Supply Association, a producer group, submitted an exhibit showing mean equity returns for 28 natural gas pipelines in the years following FERC Order 636, 1992-95. %n31%n The returns each year fell short of rates of return for the S&P 400 (industrials), as presented by David N. Fleischer, v.p. for investment research at the New York office of Goldman Sachs & Co. The differentials were substantial: 6.0 percent (1992); 3.7 percent (1993); 7.8 percent (1994); and 7.4 percent (1995). (Goldman Sachs, p. 7; NGSA, p. E-4.)

Compounding the problem is the higher level of risk now assumed by the pipeline industry. As outlined by Williams, these risks include: 1) capacity turnback, 2) loss of operation control because of capacity release and segmentation, 3) increased intra-pipeline competition through the secondary market, and 4) reduced service reliability, "in light of customers making market choices on how to use a pipeline system as distinguished from the pipelines making choices on system usage based on operational needs." (Williams Cos., p. 36.)

Is the natural gas industry making enough money? It all depends on what part of the business you're looking at. %n32%n

Speaking at the first afternoon at the technical conference, Curt Launer, v.p. for research at Donaldson, Lufkin & Jenrette, presented both the good news and the bad.

"Gas earnings are very high right now, but that's primarily because of unregulated activities.

"Equities are trading at 16-times earnings, as compared with 14-times earnings only a few years ago. But capital is not going into the pipelines themselves. Unregulated activities make up 40 percent of earnings in the natural gas industry. Meanwhile, regulated pipeline earnings are growing only about 5 percent per year, at max."

Off and on during the technical conference, the FERC commissioners questioned the witnesses on whether gas pipelines are still able to attract capital in financial markets. Launer had this to say: "Earnings in pipelines are too low to attract capital. A study of 19 companies shows that capital spending in regulated activities at gas pipelines is down to 40 percent of total investment in the gas industry.

"Gas industry capital is moving away from the pipelines." t

Bruce W. Radford is editor of PUBLIC UTILITIES FORTNIGHTLY.

1Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation; Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol [Regs. Preambles Jan. 1991 - June 1996] FERC Stats. & Regs. ¶30,939 (1992).

2Issues and Priorities for the Natural Gas Industry, Supplemental Notice Organizing Public Conference, Docket No. PL97-1-000, May 21, 1997, 79 FERC ¶ 61,234.

3"[U]nlike pipelines, which have been forced [under Order 636] to unbundle and relinquish capacity on other pipelines, these competitors and their affiliates, without prior Commission authorization, can hold transportation and storage capacity on any number of pipelines, creating 'virtual pipelines.' ... [B]y aggregating transportation and storage services, [they] can provide their customers with a choice of purchasing gas at the wellhead, city gate, or at some point in between the two." (The Coastal Cos., pp. 17, 8.)

4See, Secondary Market Transactions on Interstate Nat. Gas Pipelines, Docket Nos. RM-14-001, et al., Nov. 15, 1996, 77 FERC ¶61,183.

5See, e.g., comments of Williams Cos. and Koch Gateway Pipeline:

"WINGS [The Williams Interstate Natural Gas System] strongly supports the idea of removing the rate cap from the secondary market. (Williams Cos., p. 15.)

"The Commission's realization that the price caps on secondary market transactions could be removed is an important aspect of developing its competition policy." (Koch, p. 7.)

6The FERC reduced the old 20-year rule for bid matching to a five-year term this year in Order 636-C, on remand from United Distr. Cos. v. FERC, 88 F.3d 1105 (D.C.Cir.1996).

7Perhaps expand blanket authority under FERC regulations, Part 157, Subpart F, with environmental compliance conducted under 18 C.F.R. sec. 157.206(d), for projects meeting cost criteria of 18 C.F.R. sec. 157.208(d).

8NorAm Gas Transmission Co., Mississippi River Trans. Corp., NorAm Field Services Corp., NorAm Energy Services Inc., and NorAm Energy Management Inc.

9This section, applicable to projects begun under blanket certificates, requires all construction to comply with eleven specified statutes and Executive orders that address environment concerns.

10Cost of new facility are allocated across the owner's entire pipeline system, so that all system customers help fund it. The alternative, incremental pricing, assigns all costs directly to customers of the new facility.

11Pricing Policy for New and Existing Facilities Constructed by Interstate Nat. Gas Pipelines, 71 FERC ¶61,241 (1995). See also Williams, pp. 28-29.

12Recently, the FERC allowed pipelines to roll-in bypass facilities. See, Mojave Pipeline Co., 72 FERC ¶61,172 (1995), on reh'g, 74 FERC ¶61,047 (1966), reh'g denied, 74 FERC ¶61,288 (1966).

13See, Alternatives to Traditional Cost-of-Service Ratemaking for Nat. Gas Pipelines, Docket No. RM95-6-000; Regulation of Negotiated Transp. Services of Natural Gas Pipelines, Docket No. RM96-7-000, Statement of Policy and Request for Comments, Jan. 31, 1996, 74 FERC ¶61,076. In 1990, however, the FERC had ok'd a pipeline proposal to provide open-access firm transportation under different terms and conditions to different shippers. See,

Kern River Gas Trans Co., 53 FERC ¶61,172 (1990).

14A partial list would include K N Interstate Gas Transmission Co., and the Coastal Cos.

15It owns five interstate pipelines: El Paso Natural Gas Co., East Tennessee Natural Gas Co., Midwestern Gas Trans. Co., Mojave Pipeline Co. and Tennessee Gas Pipeline Co.

16El Paso quotes the U.S. Supreme Court as recognizing a need for individualized terms and conditions: "[T]he Natural Gas Act permits the relations between the parties to be established initially by contract, the protection of the public interest being afforded by supervision of the individual contracts." United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332, 339 (1956).

17908 F.2d 998 (D.C.Cir.1990).

18It required FERC to ensure comparability between transportation-only and bundled transportation and sales service before approving a gas inventory charge proposed by the pipeline to recover above-market gas supply costs in the demand charge.

19Feb. 18, 1997, 117 S.Ct. 811, 136 L.Ed.2d 761.

20Tennessee Gas Pipeline Co., 76 FERC ¶61,022 (1996).

21Williams Nat. Gas Co., April 18, 1997, 79 FERC ¶79,61,055.

22Arkla Gathering Servs. Co., 69 FERC ¶61,280 at 62,090 (1994).

23Gas Pipeline Facilities & Servs. on the OCS, 74 FERC ¶61,222 (1996).

24Amerada Hess Corp., 52 FERC ¶61,268 at 61,988 (1990).

25The Natural Gas Supply Association also urges a return to "proper application" of the modified primary function test approved in 1989. (NGSA, p. 21.)

26ANR Pipeline Co., ANR Storage Co., Colorado Interstate Gas Co., Wyoming Interstate Co. Ltd.

27The contract provides for annual or monthly service, but allows gas flow to exceed a prescribed hourly rate during any hour or during certain prescribed hours. (Coastal Co

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