Source: https://www.federalregister.gov/documents/2000/08/02/00-19453/regulation-of-short-term-natural-gas-transportation-services-and-regulation-of-interstate-natural
Timestamp: 2020-02-22 14:04:02
Document Index: 144744721

Matched Legal Cases: ['§\u2009284', '§\u2009284', 'art 284', '§\u20093', 'art 284', 'art 284', '§\u2009284']

Docket Nos. RM98-10-005 and RM98-12-005
Order No. 637-B
I. Exemption from the Posting and Bidding Requirements for Pre-Arranged Capacity Release Transactions at the Previous Maximum Rate
A. Compliance Filing Requirement
B. Segmentation on Reticulated Pipelines
C. Allocation of Point Rights and Point Priority
1. Segmentation at Paper Pooling Points
2. Forwardhaul-Backhaul Overlaps at a Point
3. Primary Point Rights
4. Discount Provisions
5. Mainline Priority at Secondary Points Within the Capacity Path
III. Imbalance Services, Operational Flow Orders, and Penalties
IV. Reporting Requirements for Interstate Pipelines
Appendix—Requests for Rehearing Docket Nos. RM98-10-005 and RM98-12-005
https://www.federalregister.gov/d/00-19453 https://www.federalregister.gov/d/00-19453
Start Preamble Issued July 26, 2000.
The Federal Energy Regulatory Commission (Commission) is issuing an order denying requests for rehearing and providing clarification of Order No. 637-A [65 FR 35705, Jun. 5, 2000]. Order No. 637 revised Commission regulations to enhance the competitiveness and efficiency of the interstate pipeline grid. The rehearing and clarification requests addressed in the order principally relate to posting and bidding requirements for pre-arranged capacity release transactions and segmentation. The order also addresses requests related to penalties, reporting requirements, and the right of first refusal (ROFR).
Robert A. Flanders, Office of Markets, Tariffs, and Rates Federal Energy Regulatory Commission, 888 First Start Printed Page 47285Street, NE., Washington, DC 20426, (202) 208-2084.
In Order No. 637-A,[1] issued on May 19, 2000, the Commission denied in part and granted in part rehearing of Order No. 637,[2] and clarified its policies as they relate to the regulatory changes made in Order No. 637. Order Nos. 637 and 637-A revised the Commission's open access regulations to improve the efficiency of the market and to provide captive customers with the opportunity to reduce their cost of holding long-term pipeline capacity, while continuing to protect against the exercise of market power. Specifically, Order Nos. 637 and 637-A granted a waiver for a limited period of the price ceilings for short-term released capacity; revised the Commission's regulatory approach to pipeline pricing in order to enhance the efficient allocation of capacity; revised regulations relating to scheduling procedures, capacity segmentation, and pipeline penalties to improve the efficiency and competitiveness of the pipeline grid; revised pipeline reporting requirements to provide greater transparency; and revised the right of first refusal (ROFR) to remove economic biases.
In Order No. 637-A, the Commission upheld the regulations adopted in Order No. 637, making only minor adjustments relating to penalties, reporting requirements, and the ROFR. The Commission also responded to requests for clarification and explained its policies relating to implementation of the regulations adopted in Order No. 637.
Twenty-one requests for rehearing or clarification of Order No. 637-A were filed.[3] The principal requests relate to the issues of posting and bidding requirements for pre-arranged capacity release transactions at the maximum tariff rate and the requirement that pipelines permit shippers to segment capacity as well as Commission policies as they relate to segmentation. There also are a few requests for rehearing or clarification relating to the penalty provisions, reporting requirements, and the ROFR.
As discussed below, this order denies the requests for rehearing. The order does not address rehearing or clarification requests that were fully discussed in Order No. 637-A or that are not generic, but relate to particular pipelines or potential issues that may arise in filings. These issues include requests by the Pa. Office of Consumer Advocate about pipeline filings to implement capacity auctions, by AGA, El Paso, and DTI relating to the mechanics of the ROFR pricing policy, and by National Fuel regarding the receipt and delivery points available to a shipper exercising its ROFR for a volumetric portion of its capacity. These concerns can be addressed in specific cases, if they arise.
In Order No. 637, the Commission granted a waiver of the maximum rate ceiling applicable to short-term capacity release transactions until September 30, 2002. The Commission, however, retained the pre-existing posting and bidding requirements for capacity release transactions.[4] Under the Commission regulations issued in Order No. 636 and continued in Order No. 637, the Commission requires all capacity release transactions, including prearranged deals, to be posted for bidding with two exceptions. First, pre-arranged deals for 31 days or less are not subject to posting and bidding, but any rollover or continuation of such transactions is subject to bidding. Second, transactions at the “maximum rate applicable to the release” are exempt from posting and bidding.[5]
On rehearing of Order No. 637, a number of shippers sought rehearing or clarification regarding the continued applicability to short-term capacity release transactions of the prior exemption from posting and bidding for prearranged capacity release transactions at the maximum tariff rate. They contended local distribution companies should be permitted to enter into pre-arranged transactions at the maximum tariff rate without having those transactions subject to the posting and bidding requirements. They argued that maintaining pre-arranged transactions at the maximum rate would facilitate state retail unbundling programs.
In Order No. 637-A, the Commission denied the rehearing and clarification requests. The Commission explained that the current regulation exempted transactions at the “maximum rate applicable to the release,” so that once the maximum rate ceiling was removed, all transactions (except for transactions qualifying for the 31 days or less exemption) would be subject to the posting and bidding requirements. In order to ensure that the regulations are clear, the Commission amended 284.8 (i) to specify that the exemption from the posting and bidding requirements for transactions at the maximum rate would not apply to short-term capacity release transactions as long as the waiver of the maximum rate ceiling is in effect.
In denying rehearing, the Commission found that requiring posting and bidding is necessary to ensure that capacity is equally available to all shippers and to protect against undue discrimination and the exercise of market power.[6] The Commission also explained that in individual cases where an LDC considers an exemption from the posting and bidding requirement essential to further a state retail unbundling program, it, together with the appropriate state regulatory agency, may request the Commission to waive the regulation. If the LDC seeks such a waiver, the Commission stated the LDC should be prepared to have all of its capacity release transactions and any re-releases of that capacity limited to the applicable maximum rate for pipeline capacity.
AGA, UGI, Florida Cities, Dominion LDCs, New England Local Distribution Cos., Pa. Office of Consumer Advocate, and National Fuel seek rehearing of the Commission's determination to require posting and bidding for transactions at the previous maximum tariff rate for release transactions. They also request that local distribution companies not be required to relinquish their ability to sell above the maximum rate as condition of a waiver exempting maximum rate transactions from the posting and bidding requirements. They contend that failing to provide an exemption from posting and bidding for prearranged capacity release transactions at the previous maximum rate impedes state retail unbundling efforts where LDCs are required to release capacity to marketers serving in-state customers at maximum rates. Start Printed Page 47286
The Commission denies the requests for rehearing of its requirement for posting and bidding for capacity release transactions at the previous maximum tariff rate. As the Commission explained in Order No. 637-A, Order No. 636 generally required posting and bidding for capacity release transactions to ensure that capacity is equally available to all shippers and to protect against undue discrimination and the exercise of market power. The only reason that prearranged deals at the maximum rate were exempt from the posting and bidding requirements was that, as long as a rate ceiling was in effect, no other shipper could beat the pre-arranged deal and bidding and posting requirements would be superfluous.[7] With the removal of the rate ceiling during the waiver period, pre-arranged transactions always can be beaten by a higher bid, and posting and bidding for transactions at the previous (and now non-existent) maximum rate is necessary to ensure that capacity is available to all shippers and to protect against undue discrimination and the exercise of market power.
Order No. 637 proceeded from the premise that lifting the price ceiling for short-term capacity release transactions would create a more efficient and competitive national market for gas and transportation in which shippers seeking short-term capacity would pay the market price. Providing certain customers with a preferential rate for short-term capacity runs counter to that premise. It would make the overall gas market less efficient because capacity could be allocated to those shippers who do not place the greatest value on obtaining it. Indeed, providing preferential rates to certain customers is inconsistent with the basic premise of Order No. 637, because such preferences can lead to other customers having to pay higher than market rates for capacity. Reserving capacity at preferential rates for certain customers will remove that capacity from the market, with the likely effect of increasing prices for the capacity remaining to be sold to other customers.[8]
The rehearing requests also address potential conditions the Commission may impose in considering requests for waiver of the posting and bidding requirements. The Commission has yet to receive a waiver request or determine whether to grant such a waiver. Each waiver request, together with any associated conditions, will be considered on an individual basis based on the facts presented in the waiver request.
In Order No. 636, the Commission adopted a policy of requiring pipelines to permit shippers to divide their capacity into segments and use each segment for different purposes. In Order No. 637, the Commission responded to the inconsistent application of segmentation rights by adopting a regulation requiring pipelines to enable each shipper “to make use of the firm capacity for which it has contracted by segmenting that capacity into separate parts for its own use or for the purpose of releasing that capacity to replacement shippers to the extent such segmentation is operationally feasible.” [9] The Commission required pipelines to submit pro forma tariff filings to comply with this regulation. In Order No. 637-A, the Commission made no changes in the regulation, but explained some of its policies regarding the implementation of the segmentation requirement in the pipeline compliance filings.
Columbia Gas seeks rehearing of the requirement that pipelines make pro forma compliance filings. Other requests relate to policies involved in implementing the requirement, particularly those relating to segmentation on reticulated pipelines and policies relating to the use of primary receipt points, discounting, backhauls, and priority for transactions at secondary points.
Columbia Gas contends that under section 5 of the Natural Gas Act, the Commission must show that an existing pipeline tariff is unjust and unreasonable and that its proposed change is just and reasonable. Columbia Gas maintains the Commission has not explained whether it is acting under section 5 in the rulemaking or in the individual compliance filings and, accordingly, has not demonstrated that it has the authority to direct pipelines to make filings to change their tariffs to permit segmentation or to demonstrate that they should not have to comply with the new requirement.
The Commission exercised its section 5 authority in this case by making the generic determination that pipeline tariffs that do not permit segmentation, where segmentation is feasible, are unjust and unreasonable, because the pipeline is denying shippers the ability to use their firm capacity as flexibly as the pipelines did when they were merchants.[10] Because pipelines may have to implement segmentation in different ways depending on the operational characteristics of their systems, the Commission established pro forma compliance filings, just as it did in Order No. 636, as the means for determining how pipelines can best comply with the regulation. Any final determination on whether a particular pipeline tariff is unjust and unreasonable will be made in the individual compliance filing.
The Commission has the authority under section 5 of the NGA to establish a hearing to determine whether a pipeline's tariff is unjust and unreasonable and to determine the proper just and reasonable tariff provision.[11] The NGA gives the Commission the authority to require pipelines to provide information necessary to make those determinations,[12] which is the information required by the pro forma compliance filings. Indeed, Columbia Gas concedes the Commission “may have sufficient authority to direct a pipeline to show cause why a specific alleged conduct should not be found to be in violation of its tariff or the Commission's regulations.” [13] In this case, the Commission has directed the filing of pro forma tariffs to determine whether pipelines are in compliance Start Printed Page 47287with its regulation requiring them to permit segmentation.
Columbia Gas and DTI seek clarification or rehearing relating to the requirement for segmentation on reticulated pipelines. Columbia Gas seeks clarification that a pipeline is permitted to demonstrate that capacity segmentation is not operationally feasible on its system. DTI argues that in requiring segmentation for reticulated pipelines the Commission ignored the detrimental effect that requiring segmentation for one zone pipelines with postage stamp rate designs can have on the development of market centers.
DTI asserts that the Commission erred by not providing greater guidance on how segmentation on reticulated pipelines should be accomplished.
The determination as to whether and how to implement segmentation on particular pipelines will be determined in the pro forma compliance filing proceedings. As the Commission stated in Order No. 637-A, the Commission expects all pipelines, including reticulated pipelines, to implement segmentation to the maximum extent feasible and that factors such as current rate design should not be an obstacle to permitting segmentation. The Commission expects pipelines and their customers to work together to propose methods of segmentation that will work given the operational characteristics of the pipeline. On reticulated pipelines, this may include allowing segmentation on straight-line portions of the pipeline where capacity paths can be constructed, using different methods for allocating storage capacity so that customers will have capacity paths from storage to delivery points, or permitting shippers authority to segment subject to operational limitations when needed to protect system integrity or other shippers rights. The details of segmentation need to be worked out in the first instance between the pipelines and their customers who have the greatest knowledge of the physical operations of the system.
In Order No. 637-A, the Commission discussed its policies on how segmentation should be implemented, including policies relating to overlapping capacity segments, allocation of primary point rights, point discounts, and mainline priority at secondary points within a contract path. Rehearing or clarification requests were received on several of these policies.
In Order No. 637-A, the Commission clarified that shippers can divide their capacity through segmentation at any transaction point on the pipeline system, including virtual transaction points, such as paper pooling points, as well as at physical interconnect points, such as market centers.[14] Columbia Gas and El Paso contend that the Commission has not explained how segmentation at paper points will work. Columbia contends that permitting segmentation at paper points will permit shippers to multiply their capacity beyond their contract demand.
The Commission was merely clarifying that shippers would have the right to segment capacity at locations on a pipeline that may not be physical interconnect points, but are recognized gas transaction points, such as paper pooling points. For example, a shipper may want to release capacity upstream of a pooling point and obtain gas at the pooling point for transportation on a downstream segment of its capacity. Columbia Gas has not explained how such segmentation will permit shippers to multiply their capacity beyond their contract demand. To the extent such difficulties exist, they are more appropriately examined in the compliance filings where the operational characteristics of the pipeline can be evaluated.
In Order No. 637-A, the Commission explained its policy regarding overlap of capacity segments. As a general matter, the Commission's policy is that shippers are permitted to segment capacity and overlap those mainline segments up to the contract demand of the underlying contract. As part of this discussion, the Commission found that a shipper using a forwardhaul and a backhaul to bring gas to a delivery point in an amount that exceeds its contract demand is not overlapping mainline capacity.
INGAA, Williams, and El Paso Pipelines seek rehearing of this determination. They claim that the Commission is changing an existing policy without adequate justification and that overlaps of capacity at a point result in shippers receiving service in excess of the original shipper's contract.
In the first place, the Commission is not changing a well established policy. The only case cited by those seeking rehearing in which the Commission did not permit a forwardhaul and backhaul overlap to a single point was a Commission letter order, addressed only to the parties in the case and which did not discuss the policy issues involved.[15] More recently, in a formal order, the Commission found that a forwardhaul and a backhaul to 23 meter stations treated as a single delivery point for nomination and scheduling purposes would not be considered an overlap.[16] In making this determination, the Commission found it unnecessary to analyze whether gas may have physically overlapped at some mainline point in excess of the shipper's contract demand. Distinguishing between overlaps at a single point and those to a collection of points treated as a single point is not a useful basis for determining shippers' rights to use their capacity.
The Commission, therefore, has eliminated such artificial distinctions and moved to a policy in which forwardhauls and backhauls to the same point are not considered an overlap. Those seeking rehearing have not shown that pipelines face any operational problems in permitting such flexibility nor have they demonstrated that such flexibility adversely affects other shippers or the pipeline's ability to sell mainline capacity to other shippers. The shipper has contracted for a certain amount of mainline capacity from the pipeline and the use of that capacity to effect a forwardhaul and a backhaul does not exceed the shipper's contract demand in any mainline segment.
The Commission's policy since Order No. 636 has been that shippers should be permitted to make the full use of their firm capacity whether through a forwardhaul, backhaul, or through a combination of forwardhaul and backhaul.[17] After unbundling, shippers should have the same flexibility that pipelines had as merchants, which included the ability to forwardhaul and backhaul to the same point.
In Order No. 637, the Commission explained that in the past it had adopted different policies on the issue of whether pipelines could restrict Start Printed Page 47288replacement shippers' ability to choose new primary points depending on whether pipelines had historic tariff provisions that limited primary point rights to the same level as the shipper's mainline contract demand. Although the Commission accepted tariff filings during Order No. 636 that continued historic limitations on the number of primary receipt and delivery points, the Commission questioned in the Order No. 636 restructuring orders as well as in Order No. 637 whether allowing pipelines to limit receipt and delivery point quantities to the shipper's contract demand continued to be appropriate.
In Order No. 637, the Commission concluded that a pipeline's overly restrictive allocation of primary point rights to existing shippers could restrict the ability of shippers to use their capacity flexibly and required pipelines in their compliance filings to justify continued restrictions on primary receipt and delivery point allocation, in particular requiring pipelines to justify a proposal to deviate from the Commission policy that both releasing and replacement shippers could choose primary receipt and delivery points equal to their contract demand (Texas Eastern/El Paso policy).[18] In Order No. 637-A, the Commission stated that it could not clarify the role of primary receipt points on a generic basis, but would need to examine the issues raised in the pipelines' compliance filings.
El Paso Energy contends that the Commission has not justified its change in policy with respect to primary point rights, a justification it argues is especially necessary when the policy change affects contractual rights. El Paso argues that “first-in-time shippers and marketers will immediately seek to segment their capacity into the smallest pieces possible in order to confiscate the largest amount of primary point capacity as possible.” [19]
Rather than being a change in Commission policy, as El Paso intimates, the Commission is seeking here to apply on a uniform basis policies that it first developed in Order No. 636, in part at least, in El Paso's own restructuring proceeding.[20] In that order, the Commission found:
overly restrictive limits on the amount of primary receipt and delivery point capacity that a shipper can reserve could preclude a shipper from seeking alternative sources of gas at several primary receipt points. Thus, it may be unreasonable for a pipeline to limit primary receipt capacity to a firm transportation shipper's MDQ, particularly if the total receipt point capacity of the pipeline substantially exceeds its maximum daily transportation capacity. Furthermore, if a pipeline's consent is always required to change a primary receipt point, then the pipeline would have the ability to block a shipper's change in a primary point that might injure the commercial prospects of the pipeline's gas sales affiliate, or of favored transportation customers.[21]
In Order No. 637-A, the Commission further explained why permitting flexibility in the selection of primary points in segmented releases can be important to creating effective competition between pipeline services and released capacity. If replacement shippers are limited to the use of segmented points on a secondary basis, as El Paso suggests, the pipeline would still retain the right to sell that receipt point on a primary basis. The ability to sell points on a primary basis would provide the pipeline with a competitive advantage over segmented release transactions.
Because of the potential effects that limitations on primary point rights can have on competition, such restrictions need to be reexamined in the pipeline's compliance filings. In those filings, pipelines need to justify restrictions on shippers' abilities to use additional primary points in segmentation transactions and any deviations from the Texas Eastern/El Paso policy.
El Paso is concerned that permitting shippers to select primary points in excess of their mainline contract demand could lead to possible hoarding of capacity. But, as the Commission stated in Order No. 637-A, its policy recognizes that pipelines might need to impose some restrictions on primary point rights, as appropriate to the circumstances of their systems, to prevent hoarding of capacity by some shippers to the detriment of others.[22] While the crafting of appropriate tariff provisions to limit hoarding may be challenging, as El Paso suggests, it does not appear infeasible.
In Order No. 637-A, the Commission addressed requests with respect to the interaction of its segmentation policy and its current policy permitting pipelines to limit discounts to particular points.[23] The Commission stated that this issue needs to be reexamined in the compliance filings when segmented transactions occur within the path of the shipper's transportation contract. The Commission explained that once the pipeline has decided that a discount is needed to stimulate throughput in a section of the pipeline, it has foreclosed the possibility of selling that capacity to a shipper at an upstream point and that the discount, therefore, should apply to all transactions within the capacity path.
Pipelines contend that the new rule will prevent them from selectively discounting because it will prevent them from offering selective discounts to all shippers within the capacity path.[24] INGAA states that as it reads the Commission's new rule, if long line pipelines decide to “discount transportation to New York from the Gulf of Mexico or southern Texas they are precluded from refusing discounts from the just and reasonable maximum rate for points of delivery along over 1,000 miles of pipeline into many different markets, which markets present diverse competitive conditions.” [25]
The Commission will clarify that it did not intend to change the rules regarding selective discounting. Pipelines, for example, will still be able to discount transportation to a particular customer who has competitive options to stimulate throughput without necessarily offering the same discount to other customers who are not similarly situated.
As part of the examination of restrictions on segmentation, the compliance filings need to examine whether current restrictions on a discount shipper's use of its capacity impede segmentation and competition. In Natural Gas Pipeline Company of America,[26] the Commission refused to permit the pipeline to impose a condition in discount contracts that would suspend the discount in the event the shipper released capacity, because such a provision would inhibit the competition between capacity release and pipeline capacity by requiring the discount shipper to pay the maximum rate in order to release capacity.
Once having granted a particular shipper a discount, some pipelines restrict the shipper's use of its capacity through capacity release or segmentation by requiring that shipper to pay the maximum rate for capacity in order to effectuate a segmented or release transaction. Placing such restrictions on discounted transactions could interfere with competition created through released capacity. Replacement shippers frequently need to use points different from those of the releasing shippers, and neither the releasing or replacement shipper may be willing to absorb the differential between the discounted and maximum rate. Given the increased use of discounted transportation by pipelines, it is important to explore in the compliance filings, the effect that allowing pipelines to restrict discount shippers' ability to segment and release capacity at alternative points would have on competition.
DTI asks for clarification that the policy with respect to point discounts should not necessarily be applied to reticulated pipelines which do not permit segmentation. The Commission stated in Order No. 637-A that discount policies on reticulated pipelines need to be evaluated differently than those on straight-line pipelines because a reticulated pipeline, with multiple laterals, may provide a shipper with a discount in order to stimulate throughput on a less-used lateral of its system, but not provide such discounts on more valuable laterals.[27]
In Order Nos. 637 and 637-A, the Commission addressed the question of whether shippers seeking to use mainline capacity within their path should receive a higher priority than shippers paying the same zone rate, but seeking to use capacity outside of their path. The Commission previously had found that giving priority to the shipper in the path and providing equal or pro rata rights were both just and reasonable.[28] In Order No. 637, the Commission chose not to adopt a specific policy with respect to assigning priority over mainline capacity among shippers using secondary points, leaving the status quo on individual pipelines. In Order No. 637-A, the Commission reconsidered and determined that providing priority to the shipper moving within its path would strengthen competition and promote capacity release because it would provide greater certainty as to the capacity rights of each of the shippers. Under pro rata allocation, the Commission found that neither the upstream nor downstream shipper would have definitive rights to the mainline capacity and that such uncertainty would make capacity trading difficult. The Commission provided that in the compliance filings, each pipeline must use the within-the-path allocation method unless it can demonstrate that such an approach is operationally infeasible or leads to anticompetitive outcomes on its system.
Columbia's Distribution Companies, Florida Gas, NYSEG, and FMNGA seek rehearing of the within-the-path allocation priority contending this policy reduces competition, is discriminatory, and unfairly confers competitive advantages on some shippers while disadvantaging others. They claim it contravenes the Commission's general policy that shippers receive the service for which they pay. They further assert it contravenes the Commission's recognition in Order No. 637 that one cannot tell whether the upstream or downstream shipper places the greatest value on the capacity. They contend that, as a result, there is no basis for giving preferential rights to the downstream shipper. They further argue adoption of within-the-path allocation rights will result in all shippers seeking to subscribe to capacity at the farthest downstream point in order to obtain the most valuable capacity. They also maintain that the Commission should not change its allocation priority policy without also addressing each pipeline's rate and zone design.
Enron and Florida Gas contend that the Commission should review the priority policy in individual cases. Florida Gas is concerned that the within-the-path allocation method will upset past agreements on Florida Gas Transmission Company. Enron maintains that in some situations, either within-the-path allocation or pro rata may be the most appropriate method and that the Commission should not mandate a single approach without close examination of pipeline's rate design.
The Commission affirms its determination that within-the-path allocation priority generally will best facilitate competition in the capacity release market. The issue presented is how to allocate mainline capacity to secondary points when shippers pay the same zone rate. In the following illustration, where shipper 1 (with a primary delivery point at A) and shipper 2 (with a primary delivery point downstream at C) pay the same rate in the zone, the issue would be whether the shippers should receive equal priority over mainline capacity to point B or whether shipper 2 should receive a higher priority over mainline capacity to point B than shipper 1, because point B is within shipper 2's path.
Capacity allocation is at its most efficient when capacity can be exchanged so that the shipper placing the highest value on the capacity can purchase it. As the Commission found in Order No. 637-A, competition and capacity release will be more efficient if one party has a defined right that can be exchanged, rather than two or more shippers having equal rights.[29] The problem with giving equal rights to reach secondary points is that neither the upstream (shipper 1) nor downstream shipper (shipper 2) has an alienable right to the mainstream capacity to point B. Thus, giving both shippers equal rights to the mainline capacity to point B gives neither shipper the right to make deliveries to point B and would make it difficult for either shipper to release capacity to a replacement shipper needing capacity to point B, because the replacement shipper would not be guaranteed the right to ship to point B. In addition, competition would be limited because a shipper with primary point capacity at B would have a competitive advantage in selling its capacity, since it can guarantee delivery to point B whereas neither shipper 1 nor shipper 2 can guarantee delivery to point B. In order to promote capacity trading, the right to the mainline capacity should be assigned to one shipper or the other, so that shipper has the right to release the capacity unencumbered by another shipper's claim.
The Commission agrees with the rehearing requesters that on an a priori basis, it is not possible to tell whether the upstream or downstream shipper places greater value on reaching the secondary point. But the purpose of assigning rights so as to permit capacity trading is to establish the value of the capacity and permit the allocation of that capacity to the highest valued use. In this case, the capacity cannot be allocated to the upstream shipper (shipper 1 in the example), because the downstream shipper (shipper 2) can always preempt the upstream shipper's ability to use the capacity by shipping to its primary point (point C). For instance, assume shipper 1 and shipper 2 each attempt to schedule 1000 Dth/day to delivery point B and the pipeline has only 1000 Dth/day available on the mainline between point A and point B. Once shipper 2 realizes its capacity will be cut, it will reschedule its capacity to its primary point C and thereby receive its full 1,000 Dth/day.[30] In that event, even if shipper 1 were given the higher priority to point B, it would be unable to schedule any gas to that point. If, on the other hand, the right were allocated to shipper 2, its use of the mainline to point B could not be interrupted or curtailed by shipper 1. Thus, as between the two shippers, the right to the secondary point needs to be allocated to shipper 2 in order to create a meaningful, tradable right to the capacity.
For this reason, the allocation of the priority to the downstream shipper is not unduly discriminatory, because the upstream and downstream shippers are not similarly situated. By virtue of the primary point rights in their contracts, shipper 2 already has the ability to preempt shipper 1's use of the downstream point. The Commission, therefore, is not creating discrimination, but is simply reacting to the facts as they stand to facilitate more effective capacity allocation. This determination is consistent with the conclusion reached in Order No. 636 that while upstream shippers can select downstream points in the same zone, the shipper will be using those points on an interruptible basis, subject to a higher priority to shippers using primary points.[31]
Those requesting rehearing contend that adoption of within-the-path allocation priority will lead all shippers, upon contract expiration, to seek to sign up for capacity at the end of the zone, since it is the most valuable. The Commission recognized in Order No. 637 that such an incentive could be created, but in reconsidering its decision, the Commission determined that enhancing capacity release competition was worth the difficulty of perhaps having to deal with potential conflicts in the future. It may well turn out that there is not a great incentive to move primary points to the end of the zone, because, as some of the rehearing requests point out,[32] shippers may not want to risk giving up their primary point rights at their former delivery points where they most need the gas.
Those seeking rehearing further contend that the Commission should not change policy until after it has examined pipelines' rate design and zone structures to ensure that the rates shippers pay equate with the service Start Printed Page 47291they receive. Cost-of-service rate design, however, may not perfectly represent the value of capacity, because both rates and zones may reflect considerations other than the value of reaching downstream delivery points. Indeed, the issue with respect to allocation of mainline capacity has arisen on Panhandle Eastern Pipe Line Company, a pipeline without rate zones and with rates that already are very mileage sensitive.[33] The Commission, therefore, will not generically delay implementation of within-the-path scheduling priority until after it has conducted an examination of pipeline rate structures.
ETG supports within-the-path allocation, but asks the Commission to clarify that it applies equally to receipt as well as the delivery points used in the Commission's illustration. The Commission grants the clarification. The analysis that applies to delivery points applies equally to receipt points, so that shippers seeking to move to receipt points within their path should generally have higher priority for mainline capacity than shippers moving to receipt points outside their path.[34] This means that a shipper would have a higher priority over mainline transportation to a receipt point downstream of its primary point than a shipper in the same zone seeking to use the same receipt point, which is upstream of its primary receipt point.
In Order No. 637-A, the Commission affirmed its new policy set forth in Order No. 637 that penalties may be imposed only when necessary to protect system integrity, and further explained that pipelines may not impose penalties for purposes other than system reliability, such as for enforcement of contractual obligations.[35] The Commission also held that under its definition of “penalty,” [36] a tiered cash-out program is a penalty, while a cash-out mechanism that requires that a shipper reimburse for the cost of the gas provided by the pipeline is not a penalty. DTI and El Paso seek rehearing and clarification of these rulings.
DTI and El Paso argue that the Commission erred in finding that penalties cannot be used to enforce contractual rights because this ignores the pipeline's right as a contract carrier to impose reasonable penalties to enforce its contracts, and that where a pipeline and shipper have entered into a contract to transport a specific quantity of gas, the pipeline should not be forced to exceed that quantity. DTI asserts that the consequences of the Commission's approach will be that pipelines will be unable to enforce contracts because shippers will contract for de minimis amounts of contract capacity and rely on generic contract overrun rights to meet their requirements. Further, DTI asserts that this will lead to decontracting, jeopardize the pipeline's ability to recover its cost of service, and unlawfully force pipelines to become common carriers rather than contract carriers.
As the Commission explained in the prior orders, penalties can limit the ability of shippers to use their capacity and can create market distortions.[37] Therefore, the Commission shifted its policy away from one that fosters the use of penalties to a service-oriented policy that gives shippers other options to obtain flexibility and limits penalties to their intended purpose—to protect the reliability of the system.[38] The result of this shift in policy does not eliminate the ability of pipelines to charge a penalty for contract overruns, but merely means that such penalties must be structured so that a penalty is not imposed when the system is not reasonably threatened. For example, a pipeline should not impose a penalty on a day that there is sufficient available capacity and the pipeline would have granted an authorized overrun. On a day when there is sufficient capacity to provide overrun service, a shipper that takes service above its contractual level is receiving interruptible service and should pay the maximum rate for that service, but should not be charged a penalty, since its use of interruptible service does not threaten system reliability or deliveries to other shippers.
Designing contract overrun penalty provisions so that they are imposed only when necessary to protect system integrity does not give shippers an incentive to contract for less than their required capacity and rely instead on contract overruns to meet their needs. Shippers contract for firm service in order to be guaranteed the service necessary to meet their requirements on a peak day, and they will not be guaranteed service at peak if they contract for only a portion of their capacity needs. The capacity that a shipper would obtain by means of an unauthorized overrun is not firm service, but is interruptible service that is subject to bumping and is limited by the capacity available at the time. Shippers that contract for firm service have already made a choice not to rely on interruptible service to meet their needs and therefore are unlikely to rely on an interruptible overrun service. Further, pipelines can still impose reasonable penalties when such penalties are related to system integrity. For example, on a peak day when capacity is not available, a shipper ordinarily would not be entitled to an authorized overrun because the provision of overrun or interruptible service could impede system reliability or adversely affect other shippers. Thus, a firm shipper could expect to be charged a penalty for using overrun service on a peak day and this prospect would deter the shipper from decontracting.
DTI has not explained why a contract overrun should be treated any differently than other penalties. For instance, when a shipper runs an imbalance by taking more gas than it has delivered to the pipeline, its responsibility is to make-up or pay for the gas it has taken and, under the Commission's regulations, a penalty would be imposed only when necessary to protect system reliability. Similarly, when a shipper incurs a contract overrun, it must pay for the interruptible service it has used, and a penalty should be imposed only when needed to protect the reliability of the pipeline. Thus, contrary to DTI's suggestion, the Commission's shift in policy does not affect the nature of the service provided by the pipelines or the ability of pipelines and shippers to contract for service, and does not force pipelines to become common carriers.
El Paso asks the Commission to clarify that it is not abrogating GISB Standard Start Printed Page 472921.3.19 [39] with its statement that shippers should be given the flexibility to exceed contractual limitations unless such action jeopardizes system integrity. The Commission clarifies that the new penalty policy does not abrogate GISB Standard 1.3.19 because it does not change the process for seeking authorized overrun service.
El Paso also argues that a tiered cash-out mechanism should not be treated as a penalty because the primary purpose of a tiered cash-out mechanism is the same as a simple cash-out mechanism, i.e., to address the costs resulting from using the pipeline's system supply. If the Commission does not grant rehearing on this issue, El Paso asks the Commission to modify the requirement that pipelines must include their cash-out mechanisms in their pro forma compliance filings and make clear that the cash-out mechanism provision is included in the compliance filing for informational purposes only. El Paso also asks the Commission to clarify that any currently effective settlement will remain in effect.
A tiered cash-out mechanism is a penalty provision because, unlike a simple cash-out mechanism, it does not simply recoup the cost of gas incurred as a result of shipper conduct, but imposes a greater penalty for larger imbalances. The filing of any cash-out mechanisms in the pro forma compliance filings is not for informational purposes only, but is for the purpose of enabling the Commission to evaluate how the pipeline's system management program, including the cash-out mechanism, imbalance services, netting and trading, OFO and penalty provisions work together in light of the pipeline's characteristics and the Commission's policy. As a general matter, the Commission will not exempt pipelines from complying with this policy simply because it provides service pursuant to a settlement. However, if the parties to an individual proceeding believe that a particular settlement should govern the imposition of penalties on a specific pipeline, this issue can be addressed in the compliance proceeding.
In Order No. 637-A, the Commission granted rehearing with respect to the time at which transactional information will be posted. In Order No. 637, the Commission held that firm transactional data must be posted contemporaneously with contract execution. In Order No. 637-A, the Commission modified this requirement to provide that the transactional information for both firm and interruptible service must be posted no later than the first nomination for service under the agreement. The Commission recognized that changing the time for posting of firm contracts may result in somewhat later disclosure of some contractual commitments, but explained that the effect of such a delay on the shippers' ability to obtain information about available capacity will be mitigated by other reporting requirements. Specifically, the Commission stated that under § 284.13(d), the pipeline is required to post all available firm capacity on its system, and once the pipeline enters into a contract committing firm capacity, the pipeline must amend its posting to reflect the fact that this capacity is no longer available, even if it does not immediately disclose the identity of the purchasers.
Amoco agrees that if the pipelines contemporaneously amend their capacity posting data at the time of the execution of the new contract, as the Commission assumes will be the case, this will provide some transactional information to the public at an early enough point to be helpful in the decisionmaking process. Amoco asserts that § 284.13(d) of the regulations should be clarified, consistent with the Commission's intent, to modify the language to require pipelines to amend their capacity availability posting simultaneous with the execution of the contract. Specifically, Amoco asserts that the word “timely” should be replaced with “contemporaneously” and “whenever capacity is scheduled” should be replaced with “whenever contracts are executed.”
There is no need to modify the regulation because it already requires posting of changes to available capacity immediately after contract execution. Section 284.13(d) of the Commission's regulations require pipelines to post available capacity “whenever capacity is scheduled.” GISB currently requires pipelines to schedule capacity four times a day,[40] and therefore the pipeline must post its available capacity four times daily. This not mean, however, that capacity under contract can be posted as available up until the time it is actually scheduled. A change in available capacity must be reflected in the next capacity posting after the execution of the contract because once the contract is executed, the capacity is no longer available. The pipeline cannot post capacity as available if it is no longer available.
In Order No. 637, the Commission held that in the future, the ROFR will apply only to maximum rate contracts and, therefore will not apply to discounted contracts or negotiated rate contracts. The Commission grandfathered existing discounted contracts so that the ROFR will apply upon the expiration of those contracts, but explained that the ROFR will not apply to the re-executed contract unless it is at the maximum rate. In Order No. 637-A, the Commission affirmed these holdings and clarified that the ROFR does not apply to negotiated rate contracts regardless of whether the negotiated rate is equal to or higher than the maximum tariff rate for the service.[41] ETG, New England, and WPSC seek rehearing or clarification of these holdings.
ETG and New England argue that the Commission erred in depriving negotiated rate contracts that are at the maximum tariff rate of ROFR protection. ETG argues that a negotiated contract to pay the maximum rate is a contract at the maximum rate within the meaning of the discussion in Order No. 637 and revised section 284.221(d) of the Commission's regulations. Further, ETG asserts that this limitation on the ROFR will discourage negotiated rate contracts and discounts, contrary to the Commission's policy of favoring settlements and approving procedures for negotiated rate contracts. New England asserts that in negotiating the re-execution of existing contracts, certain pipelines insisted that captive shippers enter into negotiated rate contracts at the maximum tariff rate, and that these customers are subject to the pipeline's monopoly power. New England states that under the Commission's rationale, a captive customer willing to pay the maximum rate must forego any benefits of the negotiated rate contract in order to retain the ROFR.[42] New England argues that this is unfair and tends to limit the service options available to captive customers.
A shipper with a negotiated rate contract is not paying the tariff rate. That shipper's rate will be established Start Printed Page 47293by its contract regardless of the tariff or any changes to the tariff rate during the term of the negotiated rate contract. Because a negotiated rate is not a tariff rate, it cannot be the maximum tariff rate within the meaning of the Commission's regulations regardless of how the level of the negotiated rate compares to the level of the tariff rate.
Pipelines cannot require captive customers to enter into negotiated rate agreements rather than to take service under the maximum tariff rate. All shippers are entitled to take service pursuant to the pipeline's generally applicable tariff, and the pipeline cannot refuse to provide service under the tariff if capacity is available and the shipper agrees to pay the maximum tariff rate. This limitation does not impact the Commission's policy regarding settlements in rate cases; a negotiated rate is not a rate case settlement rate. Further, while the Commission permits negotiated rate contracts, it does not permit negotiated terms and conditions of service. The limitation on the ROFR therefore cannot limit the service options available to captive customers under negotiated contracts because customers cannot negotiate terms and conditions of service.
ETG, New England, and WPSC ask the Commission to clarify that negotiated rate contracts entered into before the issuance of Order No. 637 are, like discounted contracts, grandfathered and the ROFR will apply upon their expiration. These parties argue that negotiated rate contracts should be treated the same as discounted rate contracts with regard to grandfathering because in both cases shippers entered into the contracts in reliance on the existence of the ROFR, and the purpose of grandfathering is to protect that reliance interest.
The ROFR applied to negotiated rate contracts prior to Order No. 637, and the Commission agrees that the same policy should apply to negotiated rate contracts as to discounted contracts. Thus, negotiated rate contracts entered into prior to the issuance of Order No. 637 will be grandfathered, and the ROFR will apply to the service at the expiration of the contract. However, the ROFR will not apply to future negotiated rate contracts, and will apply only to contracts for recourse service taken pursuant to the pipeline's tariff at the maximum rate.
With this order, the rulemaking process is at an end. The next step is for the industry and the Commission to focus on the issues raised in the compliance filings so as to restructure pipeline services and penalties to enhance competition throughout the industry.
Order Nos. 637 and 637-A are clarified as discussed in this order and rehearing of Order No. 637-A is denied.
By the Commission. Commissioner Breathitt dissented with a separate statement attached.
Amoco Energy Trading Corporation and Amoco Production Company Amoco.
Columbia Gas Transmission Corporation Columbia Gas.
Columbia's Distribution Companies (Columbia Gas of Kentucky, Maryland, Ohio and Pennsylvania) Columbia's Distribution Companies.
Dominion LDCs (Peoples Natural Gas Co., East Ohio Gas Company, Hope Gas, Inc., Virginia Natural Gas Co.) Dominion LDCs.
Dominion Transmission, Inc. DTI.
Duke Energy Gas Transmission (Algonquin Gas Transmission Company, East Tennessee Natural Gas Company, Texas Eastern Transmission Corporation) Duke
East Tennessee Group ETG.
El Paso Corporation Interstate Pipelines El Paso.
Enron Interstate Pipelines Enron.
Florida Cities Florida Cities.
Florida Municipal Natural Gas Association FMNGA.
National Fuel gas Distribution Corporation National Fuel.
New England Local Distribution Companies New England Distribution Companies.
New York State Electric & Gas Corp. (The Berkshire Gas Company, Connecticut Natural Gas Corp., Southern Connecticut Gas Co.) NYSEG.
Pennsylvania Office of Consumer Advocate and Ohio Office of Consumer Counsel Pa. Office of Consumer Advocate.
Reliant Energy Gas Transmission Company and Mississippi River Transmission Corporation Reliant.
The Williams Companies, Inc. Williams.
UGI Utilities, Inc. UGI.
Wisconsin Public Service Corporation WPSC.
Breathitt, Commissioner, dissenting in part:
I am dissenting in part on Order No. 637-B because of its determination that it is permissible for a shipper to use a forwardhaul and a backhaul to bring gas to a single delivery point in an amount that exceeds its contract demand. In a Tennessee Gas Pipeline Company proceeding, the Commission expressly prohibited shippers from using forwardhaul and backhaul transactions in a pipeline segment in excess of contract demand.[1] This prohibition was retained in Order No. 637-A. The rationale offered in Tennessee was that segmenting rights are not without limit. The Commission explained that the limiting factor was the shipper original entitlement or contract demand. Specifically, the Commission stated, “this means that they have no right to release and use overlapping segments, where, in the overlapped portion, the total capacity released and used exceeds their original entitlement.”
In an Iroquois Gas Transmission System, L.P. decision, the Commission applied that prohibition to overlapping transactions at a single point, finding that a shipper could not schedule forwardhaul and backhaul transactions to the same delivery point in excess of its total contract demand.[2] The justification for this prohibition was the same in both cases. That is, the overlap of forwardhaul and backhaul transactions in excess of contract demand results in shippers receiving service in excess of that for which the shipper is paying. This is so, regardless of whether the overlap is at a single point or on a segment.
Today's order does not adequately respond to this inconsistency in policy between treatment of contract rights on a segment and treatment of contract rights at a single point. Parties have argued on rehearing that overlapping transactions in excess of contract demand at a point negatively effects shippers' attempts to sell unused capacity in the secondary market. I do not believe that this order has adequately addressed this concern about the impact of this decision on the capacity release market. For these reasons, I am dissenting on the majority's decision to allow shippers to exceed there contractual entitlements by overlapping capacity at a single point.
Linda K. Breathitt,
1. Regulation of Short-Term Natural Gas Transportation Services and Regulation of Interstate Natural Gas Transportation Services, Order No. 637-A, 65 FR 35706 (Jun. 5, 2000), III FERC Stats. & Regs. Regulations Preambles ¶ 31,099 (May 19, 2000).
2. Regulation of Short-Term Natural Gas Transportation Services and Regulation of Interstate Natural Gas Transportation Services, Order No. 637, 65 FR 10156 (Feb. 25, 2000), III FERC Stats. & Regs. Regulations Preambles ¶ 31,091, at 31,308 (Feb. 9, 2000).
3. Those filing rehearing and clarification requests are listed on the Appendix.
4. Order No. 637, 65 FR at 10182, III FERC Stats. & Regs. Regulations Preambles ¶ 31,091, at 31,279.
5. 18 CFR 284.8(h)(1) (formerly 18 CFR 284.243(h)(1)).
6. Order No. 637-A, 65 FR at 35718, III FERC Stats. & Regs. Regulations Preambles ¶ 31,099, at 31,568-69.
7. Release of Firm Capacity on Interstate Natural Gas Pipelines, Order No. 577, 60 FR 16979 (Apr. 4, 1995), FERC Stats. & Regs. Regulations Preambles [Jan. 1991-June 1996] para. 31,017, at 31,316 (Mar. 29, 1995) (“when the pre-arranged deal is at the maximum rate, no other shipper can make a better bid for that capacity”).
8. For example, suppose an LDC has 10,000 Dth of available capacity with a maximum rate of $1 during a time at which the price of capacity would exceed the $1 value. Suppose that if the LDC places all 10,000 Dth for sale, the price per unit would be $1.25 given the demand characteristics of the shippers bidding for capacity. However, if the LDC sells 500 Dth to certain shippers, such as marketers who sell gas behind the LDC's city-gate, for the former maximum rate of $1.00, that leaves only 500 Dth remaining to be sold to other interstate shippers. By limiting the amount of available capacity through sales at below-market prices, the price for the remaining capacity is likely to rise above $1.25 in order to allocate the capacity to the remaining interstate shippers.
9. Order No. 637, 65 FR at 10195, III FERC Stats. & Regs. Regulations Preambles ¶ 31,091, at 31,303-304; 18 CFR 284.7(e).
10. Order No. 637-A, 65 FR at 35730, III FERC Stats. & Regs. Regulations Preambles ¶ 31,099, at 31,590-91; Transmission Access Policy Study Group v. FERC, No. 97-1715, at 59-61, 2000 U.S. App. LEXIS 15362 (D.C. Cir. June 30, 2000) (authority to make a generic public interest finding under Mobile-Sierra); Wisconsin Gas Co. v. FERC, 770 F.2d 144, 1166-67 (D.C. Cir. 1985) (authority to make generic finding that practices are unjust and unreasonable in rulemakings).
11. 15 U.S.C. 717d(a).
12. 15 U.S.C. 717i (Commission can require natural gas companies to file special reports and to require natural gas companies to answer questions); 717m (c) (Commission can summon witnesses and require production of documents relevant to a hearing).
13. Columbia Gas Rehearing Request, at 15.
14. Order No. 637-A, 65 FR at 35731, III FERC Stats. & Regs. Regulations Preambles ¶ 31,099, at 31,591-92.
15. Iroquois Gas Transmission System, L.P., 78 FERC ¶ 61,135 (1997).
16. Transcontinental Gas Pipe Line Corporation, 91 FERC ¶ 61,031 (2000).
17. Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission's Regulations, Order No. 636-B, 61 FERC ¶ 61,272, at 61,997 (1992) (shippers can use their capacity to release capacity through forwardhauls and backhauls).
18. Order No. 637, 65 FR at 10194, III FERC Stats. & Regs. Regulations Preambles para. 31,091, at 31,301-302; Texas Eastern Transmission Corporation, 63 FERC ¶ 61,100, at 61,452 (1993); El Paso Natural Gas Company, 62 FERC ¶ 61,311, at 62,991. See also Transwestern Pipeline Company, 61 FERC ¶ 61,332, at 62,232 (1992).
19. El Paso Rehearing Request, at 9.
20. El Paso Natural Gas Company, 62 FERC ¶ 61,311, at 62,982-83 (1993).
22. Order No. 637-A, 65 FR at 35732, III FERC Stats. & Regs. Regulations Preambles ¶ 31,099, at 31,593. See El Paso Natural Gas Company, 62 FERC ¶ 61,311, at 62,982-83 (1993) (pipelines can propose methods for limiting the potential for hoarding).
23. Order No. 637-A, 65 FR at 35733, III FERC Stats. & Regs. Regulations Preambles ¶ 31,099, at 31,595.
24. DTI, INGAA, Williams, Reliant, Columbia Gas, Duke Energy Pipelines, Enron Pipelines, El Paso.
25. Rehearing Request by INGAA, at 7.
26. 82 FERC ¶ 61,298 (1998).
27. This concern does not apply to long line pipelines, since selling capacity to a downstream point on a long line pipeline makes impossible the sale of that same capacity to an upstream point. Thus, in selling the capacity at a discount, the long line pipeline already has foregone the opportunity to collect a higher rate at the upstream point.
28. Compare Tennessee Gas Pipeline Company, 71 FERC ¶ 61,399, at 62,577 (1995) (providing equal priority) with Panhandle Eastern Pipe Line Company, 78 FERC ¶ 61,202, at pp. 61,870-71 (1997) (conditionally accepting within the path allocation); Northwest Pipeline Corporation, 67 FERC ¶ 61,095 (1994) (priority given to shippers moving within primary path).
29. Order No. 637-A, 65 FR at 35734 & n.126, III FERC Stats. & Regs. Regulations Preambles ¶ 31,099, at 31,596 & n.126 (citing R. Posner, Economic Analysis of Law, § 3.1, at 28 (2d ed. 1977)).
30. As was pointed out in Order No. 637-A, shipper 2 can often effect the full delivery of capacity to point B through the expedient of scheduling capacity to point C and then using a backhaul to reach point B. Thus, shipper 2 can preempt shipper 1's ability to deliver to point B, while preserving its ability to make the delivery itself.
31. Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission's Regulations, Order No. 636-A, 57 FR 36128 (Aug. 12, 1992), FERC Stats. & Regs. Regulations Preambles [Jan. 1991-June 1996] ¶ 30,950, at 30,585 (Aug. 3, 1992), Order No. 636-B, 61 FERC ¶ 61,272, at 62,013 (1992). In Northwest, the Commission recognized that there is no undue discrimination in giving priority to shippers using their primary path over those using capacity between secondary points. Northwest Pipeline Corporation, 67 FERC ¶ 61,095, at 61,274 (1994).
32. Rehearing Request FMNGA, at 9 (the shipper's right to use an upstream point is still secondary).
33. See Panhandle Eastern Pipe Line Company, 78 FERC ¶ 61,202 (1997) (rates based on 100 mile increments); Panhandle Eastern Pipe Line Company, 87 FERC ¶ 61,331 (1997) (issue is still under consideration).
34. Northwest Pipeline Corporation, 67 FERC ¶ 61,095 (1994) (shipper within the path receives priority over shipper outside the path).
35. Order No. 637-A, 65 FR at 35741, III FERC Stats. & Regs. Regulations Preambles ¶ 31,099, at 31,608-09.
36. The Commission stated that it considers a penalty to be any charge imposed by the pipeline on a shipper that is designed to deter shippers from engaging in certain conduct and reflects more than simply the costs incurred as a result of the conduct. Order No. 637-A , 65 FR at 35742, III FERC Stats. & Regs. Regulations Preambles ¶ 31,099, at 31,610.
37. See Order No. 637, 65 FR at 10197-98, III FERC Stats. & Regs. Regulations Preambles ¶ 31,091, at 31,307-08; Order No. 637-A, 65 FR at 35740, III FERC Stats. & Regs. ¶ 31,099, at 31,607.
38. See Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission's Regulations, Order No. 636, 57 FR 13267 (Apr. 16, 1992), FERC Stats. & Regs. Regulations Preambles [Jan. 1991-June 1996] ¶ 30,939, at 30,424 (penalties are to deter behavior inimical to the welfare of the system).
39. GISB Standard 1.3.19 provides “Overrun quantities should be requested on a separate transaction.”
40. 18 CFR § 284.12(b)(1)(i), Standard 1.3.2.
41. Order No. 637-A, 65 FR at 35756, III FERC Stats. & Regs. Regulations Preambles ¶ 31,099, at 31,634.
42. New England states that the contract may differ from the pro forma service agreement on non-rate matters, and therefore be termed a negotiated rate agreement. For example, New England states the shipper may obtain the right to reduce contract demand prior to the expiration of the contract under certain circumstances.
1. Tennessee Gas Pipeline Co., 85 FERC ¶ 61,052, at 61,135 (1998).
2. Iroquois Gas Transmission System, L.P., 78 FERC ¶ 61,135 at 61,524 (1997).
[FR Doc. 00-19453 Filed 8-1-00; 8:45 am]