Texas Eastern Transmission Corp. v. Federal Energy Regulatory Commission

GARZA, Circuit Judge:

I.

These consolidated appeals¹ involve the Federal Energy Regulatory Commission’s (“Commission”) handling of three rather distinct issues under the Natural Gas Policy Act of 1978, 15 U.S.C. Section 3301 et seq. (“NGPA”). First, the Commission issued a number of regulations outlining when a first seller of natural gas can recover certain production-related costs under Section 110(a)(2) over and above the Congressionally established maximum lawful price. The Commission’s regulations on this subject are challenged for varying reasons by several groups of parties. The Indicated Producers² (“Producers”) generally support the Commission’s approach to the Section 110 issues, but they disagree with regard to a few specifics. The Pipeline Petitioners and Intervenors³ (“Pipelines”), the Associated Gas Distributors⁴ and the. Public Service Commission of New York⁵ take broader exception to the Commission’s approach. With only minor modifications, we affirm the Commission’s disposition of this question as a reasonable accommodation of the varying policies at issue.

The second major issue presented involves the Commission’s Title I Declaratory Order. In that order, the Commission approved a contracting practice whereby a seller-producer receives from a pipeline-purchaser the free or below-cost transportation of the seller-producer’s own hydrocarbons (liquids and liquefiables) in addition to the maximum lawful price. The Producers generally support the Commission on this issue. The Pipelines, as well as the Associated Gas Producers, challenge the order as an unacceptable loophole in the price structure Congress created in Title I of the NGPA. As explained below, we affirm the Commission on this issue.

The third issue raised involves a number of conditions which the Commission placed on various pipelines’ certificates of public convenience and necessity pursuant to its jurisdiction under the Natural Gas Act (“Gas Act”), 15 U.S.C. § 717 et seq. These conditions generally prohibit a pipeline-purchaser from recovering in its rate proceedings those costs that it incurs in transporting producer-owned liquids and liquefiables. Certain Pipeline Petitioners⁶ challenge these conditions. The Commission and two pipelines⁷ note that the case has been settled for a period of years and is therefore not ripe. We agree and decline to review that decision.

Each of these issues is developed more fully below.

II.

The first set of issues presented in this case arises under Section 110(a)(2) of the Natural Gas Policy Act of 1978, 15 U.S.C. § 3320(a)(2) (1982). Section 110(a)(2) allows a first seller of natural gas to charge an amount exceeding the applicable maximum lawful price “to the extent necessary to recover ... any costs of compressing, gathering, processing, treating, liquefying, or transporting such natural gas, or other similar costs, borne by the seller and allowed for, by rule or order, by the Commission.” In an attempt to carry out the requirements of Section 110(a)(2), the Commission issued a series of orders.⁸

In essence, these orders created a scheme of generic allowances that permit sellers of gas (other than Section 105 and 106(b) gas)⁹ to recover much of these production-related costs at a predetermined level¹⁰ and, in most cases, without the Commission’s involvement. The different parties (other than the Commission) take issue with these orders in varying degrees. The Associated Gas Distributors and the Pipelines fundamentally disagree with the notion of an across-the-board generic allowanee for these production-related costs. Moreover, even assuming the viability of the generic approach, the Pipelines point to a number of specific effects and requirements of the generic allowances promulgated as being especially arbitrary. The Producers on the other hand, strongly concur in the generic approach generally, but point to a few areas where the proposed allowances are inadequate, either because of time frame or subject matter. Finally, the Commission maintains that the orders are rational in all respects.

A.

We find no merit in the Associated Gas Distributors and the Pipelines’ contention in their briefs that a generic approach to allowances is not contemplated under Section 110(a)(2).¹¹ This argument against generic allowances necessarily depends on their assertion that allowances of whatever type under Section 110 were intended to be rather exceptional. This is so, because a case-by-case assessment of the propriety of Section 110 allowances in the many contracts for Section 104 and 106(a) gas would be plainly infeasible as an administrative matter.¹²

By its terms, Section 110 authorized allowances “to the extent necessary” to enable the seller to recover production-related costs; whether the allowances were intended to be widely applicable turns largely on the appropriate reading of “necessary.” The Associated Gas Distributors and the Pipelines maintain that “necessary” means something more than “incurred;” for if Congress meant to authorize reimbursement to a seller of all production-related costs, they argue, it would have chosen far simpler language. The Congress therefore, according to the Pipelines and the Associated Gas Distributors, must have intended an elaborate regulatory scheme to enable the Commission to distinguish the usual case, where the maximum lawful price adequately compensates a first seller, from the extraordinary case, where an additional allowance is required to defray the seller’s production-related costs. The Commission responds that its order gives “necessary” a more reasonable reading. The Commission notes that it based the allowances on industry cost averages, thereby assuring that they would accurately reflect the costs “necessarily” associated with these production-related activities. As an added assurance that only necessary costs would be recovered, the Commission notes that its order limited the amount recoverable to the amount provided by the generic allowance or the amount provided by contract, whichever is less. Thus, according to the Commission, the course of bargaining between a producer and a pipeline will assure that unnecessary costs will not be recovered in any given case.

We find the Commission’s position on this issue the more persuasive. The Pipelines and the Associated Gas Distributors have failed to demonstrate that the Commission’s approach is unfaithful to the purpose of Section 110. Significantly, the very language of the statute provides for reimbursement of these production-related costs by “rule or order.” The drafters’ choice of the words “rule or order” in this context clearly contemplates the establishment of an industry-wide scheme of reimbursement. The generic scheme which was developed is further consistent with Section 110’s requirement of necessity. “Necessity” in this context requires only that an allowance be a reasonable approximation of costs actually incurred by a seller in a production-related activity. These generic allowances clearly comport with that statutory requirement.

The Associated Gas Distributors and the Pipelines next argue that, even assuming generic allowances are permissible under Section 110, the Commission erred in acting as though they are mandated by that provision. In particular, they argue that the Commission should have carefully considered the impact that these allowances would have on the natural gas market, especially given the tumultuous circumstances facing the gas market at that time. The Commission responds that it took care to minimize the impact of the allowances on the market, both by allowing for the establishment of a lower rate by contract and by basing the allowances themselves on a comprehensive cost study. Other than these attempts to minimize the market impact of the allowances, the Commission felt bound by the statutory mandate that it grant allowances where “necessary.”

The Commission did not behave irrationally in deferring to Congress’s market evaluation as reflected in Section 110 itself. The Commission’s duty in this situation is to effectuate Section 110’s directives in a reasonable way. We are, moreover, not persuaded that the Commission acted irresponsibly in the face of the gas market conditions. Accordingly, we find no merit to the Pipelines’ attack on the generic allowance scheme as a whole.

B.

The Pipelines and the Associated Gas Distributors next take issue with a number of specific applications of the generic delivery allowances. Our inquiry with respect to each of the situations is limited to evaluating “the effort the Commission has made and whether the Commission has ‘given reasoned consideration to each of the pertinent factors.’” Tenneco Inc., v. F.E.R.C., 571 F.2d 834, 839 (5th Cir.1978), cert. dismissed, 439 U.S. 801, 99 S.Ct. 43, 58 L.Ed.2d 94 (1978) (quoting Permian Basin Area Rate Cases, 390 U.S. 747, 792, 88 S.Ct. 1344, 1373, 20 L.Ed.2d 312 (1968)).

The Pipeline Petitioners and the Associated Gas Distributors note that the Commission’s regulation with respect to new (post-NGPA) delivery systems provides for an allowance of seven cents per MMBtu for the first mile or less and two cents per MMBtu for each mile thereafter.¹³ 18 C.F.R. § 271.1104(d)(l)(i)(B). The delivery allowance for a pre-NGPA system is five cents per MMBtu, regardless of the system’s length. Id. at § 271.-1104(d)(l)(i)(A). In the case of a combined new and old system, the regulation provides for the collection of both allowances, a result which the Pipelines and the Associated Gas Distributors find especially arbitrary.

We find no merit whatever to these attacks on either the old or new system allowance standing alone. The Commission’s choice of cut-off lengths is amply supported by the record. The fact that a new delivery system of even very short length could receive the full seven cents per MMBtu is simply a function of this administrative necessity. Moreover, the Pipelines and the Associated Gas Distributors have failed to demonstrate any real prejudice that results from this approach.¹⁴

The result reached with respect to a combined system (composed of both new and old systems) is, in certain situations, more problematic. A combined system composed of a very short old system and a new system might receive a greater allowance than an entirely new system.¹⁵ The Commission argues that this result is merely an aberration in an otherwise fair scheme, and that we should limit our consideration to the fairness of the scheme as a whole. The Commission further argues that the record shows that the hypothetical case posed by the Pipelines and the Associated Gas Distributors will be very unusual in the real world. R. at B1560-61. Accordingly, the Commission concluded that the cost of ascertaining the length of old systems, unnecessary under the present system, would greatly outweigh the slight benefits of a more exact means of calculating the appropriate allowance for a combined system. We find support for this conclusion in the record and sustain it.¹⁶ R. at B1561.

The Pipelines and the Associated Gas Distributors challenge the application of the generic delivery allowance in yet another context: offshore drilling rigs. They note that, typically, delivery systems offshore are quite short, often only a few feet, but that the producer nonetheless receives the same minimum allowance received on shore. 18 C.F.R. § 271.-1104(d)(ii). Accordingly, they argue that the Commission erred first, in providing for any allowance in the offshore situation and, second, in failing to consider the offshore sites separately from those onshore. The record, however, demonstrates that allowances have long been provided for in the case of offshore delivery. See R. at B1554. Nothing in the history or language of the NGPA compels a different result. As for their amount, the Commission recognizes that the delivery systems offshore are frequently quite short. Nonetheless, the Commission found that this was- offset by the fact that the producer bears the cost of the platform, thereby greatly increasing the effective cost of the system.¹⁷ Accordingly, the Commission’s disposition of this issue is supported by the evidence and will be sustained.

The Pipelines and the Associated Gas Distributors also challenge two commingling requirements imposed by the Commission’s regulations. First, the Commission required that in order for a seller to collect a delivery allowance on gas hauled through a new system, the “gas hauled must be commingled with other gas at or before the point of the final first sale;” ¹⁸ nonetheless, the Commission refused to require commingling with respect to new delivery systems. Second, the Commission required that commingling of gas from other wells occur downstream from a separator of oil well gas; the Commission imposed no such requirement with respect to gas from gas wells.¹⁹ We find the Commission’s reasons for these requirements to be persuasive. With respect to the first commingling requirement, it is imposed to assure that redundant new delivery lines are not constructed merely in order to collect an additional allowance. This requirement makes no sense with regard to old systems, where the allowance is collected regardless of the length of the system. With respect to the second commingling requirement, there is simply no need for a “downstream” requirement with respect to separators for gas well gas, whereas the area “upstream” from a separator for oil well gas is primarily an oil system. R. at B1368-69. These requirements are manifestly reasonable exercises of the Commission’s discretion.

The Associated Gas Distributors argue, finally, that the Commission erred in Order 94-A in eliminating minimum gas quality standards under the new regulatory scheme. The minimum quality standard under Order 94, the previous regulation, set a benchmark quality level for marketable gas. Under that plan, processing costs incurred in bringing the gas up to minimum quality standards were not recoverable under Section 110. The Associated Gas Distributors argue that the prior plan reflected Congressional intent that the maximum lawful price adequately compensates for gas at the minimum quality level; that is, that no Section 110 allowance is appropriate when incurred in raising the quality up to merely minimum quality.

The Commission counters, persuasively in our view, that nothing in the history of the NGPA limits Section 110 allowances to gas of a certain minimum quality. The Commission concedes that the result of the Order 94-A approach is to allow a seller of gas produced at a sub-minimum quality standard but further processed up to minimum quality to receive a greater effective price²⁰ than a seller who produces gas already at the minimum quality level. The Commission takes exception with the Associated Gas Distributors’ characterization of this result as “anomalous”; however, this result leads to an important incentive for the production of the lower-quality gas. This strikes us as entirely reasonable. Moreover, the maximum lawful price is merely a ceiling. The parties are therefore free to handle this contractually. We find no abuse of the Commission’s discretion.

C.

The Producers, while in general agreement with the Commission’s approach, challenge four specific aspects of the regulations relating to interstate gas²¹ under Section 110. First, the Producers maintain that the Commission erred in holding that an area rate clause²² does not authorize collection of the compression allowance. See 271.1104(c)(4)(ii)(B). Second, the Producers challenge the Commission’s denial of a compression allowance with respect to pre-NGPA systems. See 18 C.F.R. § 271.-1104(d)(l)(iv); R. at 6212. Third, the Producers challenge the refusal of the Commission to make all production-related allowances retroactive to 1978, the year of the passage of the NGPA. Fourth, the Producers challenge the Commission’s denial of interest for the periods in which retroactive allowances were recoverable.

With respect to the first, third and fourth issues above, the Pipelines also challenge the Commission’s orders but for different reasons. With respect to the first issue, the Pipelines maintain that the Commission erred in holding that an area rate clause authorizes even a delivery allowance. As for the third and fourth issues, the Pipelines maintain that the Commission should not have permitted any retroactive recovery of either allowances or interest. These issues are discussed in turn.

The first question relates to the Commission’s decision that an area rate clause would authorize the collection of a delivery allowance, where otherwise appropriate,²³ but would not authorize the collection of a compression allowance or any other production-related costs recoverable pursuant to Section 110. The Pipelines and the Associate Gas Distributors note that the regulations generally require express contractual authorization for the collection of any allowance. See 18 C.F.R. 271.-1104(a)(3). Nonetheless, the Commission finds express authorization in the very general language of an area rate clause. See id. at § 271.1104(c)(4)(ii)(B). This second provision clearly does violence to the express authorization requirement, according to the Pipelines and the Associated Gas Distributors. In any event, area rate clauses vary widely in language and intent; the Pipelines and the Associated Gas Distributors read the 1981 Pennzoil decision to require that these clauses be evaluated on a ease-by-case basis. The Producers, on the other hand, find arbitrariness only in the limitation on the area rate clause; they argue that an area rate clause should authorize the collection of any production-related allowance permitted by the Commission pursuant to Section 110.

The Commission argues that prior experience under the Gas Act, 15 U.S.C. 717 et seq., supports the construction of area rate clauses as authorizing delivery allowances. On the other hand, the Commission urges that compression allowances were not allowed under the Gas Act and therefore could not have been foreseen by the parties to an agreement containing an area rate clause. As a general matter, these bases strike us as unassailable. It is troublesome, however, that the Commission did not clearly provide for a protest procedure to allow parties the opportunity to show that the intent of the parties with respect to certain area rate clauses is inconsistent with the general rules set out above. For the first time in this appeal, the Commission apparently does not dispute the propriety of a challenge under the general protest provisions under Section 101(b)(9) of the NGPA, 15 U.S.C. § 3311(b)(9). However, because of the paramount importance of intent under individual contracts,²⁴ the Commission should amend its Order 94-A to make clear that in a particular case, an aggrieved party is entitled to attempt to show that its area rate clause is not subject to the presumptions of Order 94-A. The procedures utilized in the former Order 23-B should serve as a model for the required procedures. With this modification, the Commission’s treatment of this issue is affirmed.

The second issue raised by the Producers relates to the Commission’s denial of any compression allowance vis-a-vis preNGPA systems. See 18 C.F.R. § 271.-1104(d)(l)(iv). With respect to post-NGPA systems an allowance is created to reimburse a first seller for qualified stages of compression, as well as for the cost of fuel to drive the compressor. The Commission urges a rational basis in the exclusion of old systems in that sellers were adequately compensated for these costs under Gas Act area and nationwide rates. R. at B702-03. More importantly, no specific allowance for compression was provided for under prior law; therefore, sellers with pre-NGPA systems had no expectation of specific compensation for compression. The record clearly supports this basis. R. at 842-48. Accordingly, we sustain the aspect of the Commission's decision relating to the recovery of capital costs. On the other hand, the Commission has come forward with no sound basis for the exclusion of fuel costs, which are current expenditures, with respect to pre-NGPA systems. Therefore, we instruct the Commission to modify its order to allow for the recovery of fuel and power costs with respect to'pre-NGPA systems. These costs are recoverable to the same extent and retroactive to the same date from which they have been recoverable up to now with respect to post-NGPA ■facilities.

In their third challenge, the Producers, including Phillips Petroleum,²⁵ quarrel with the Commission’s failure to make all production-related allowances recoverable retroactive to 1978, the year of the NGPA’s passage. The Pipelines and the Associated Gas Distributors, on the other hand, maintain that the allowances should be collectable only from 1983, the time provided for when the allowance was finally established in Order 94-B. Prior to that time, the Pipelines argue, no Commission authorization existed for collection of an allowance; and Commission authorization is an explicit requirement of Section 110. To this argument of the Pipelines, the Commission responds that it had promised in Order 94 that allowances eventually created with respect to interstate gas would be retroactive to that date. Contrary to the Pipeline’s characterization of this promise as “ultra vires,” we believe it was a fair balancing of the various problems involved: the sellers’ need for allowances, the purchasers’ need for notice, and the Commission’s need to make a thorough study prior to setting allowances. Similarly, we are unpersuaded by the Producers’ contention that the Commission delayed unnecessarily in establishing allowances.²⁶ The Commission’s disposition of this point is upheld. In any event, rules of this type should be made retrospective, absent adequate notice only in rare cases. See Transwestem Pipeline Co. v. FERC, 626 F.2d 1266, 1271 (5th Cir.1980), cert. denied, 451 U.S. 937, 101 S.Ct. 2017, 68 L.Ed.2d 324 (1981). We are not convinced that this is such a case.

Finally, the Producers challenge the Commission’s failure to assess interest²⁷ against the purchasers on retroactive allowances awarded. R. at 6142. The Producers argue with some force that this situation is highly analogous to a rate refund, where interest would be recoverable. See 18 C.F.R. § 154.102(c)(2). Nonetheless, the Commission is clearly empowered to stray from its general regulation in the interest of equity. Shell Oil Co. v. F.E.R.C., 664 F.2d 79, 83 (5th Cir.1981). As part of this overall scheme of retroactive allowances, the exclusion of interest results from a reasonable balancing of the equities. This is so, because while the purchasers were on notice as of 1980 that allowances would eventually be promulgated, they were not on notice as to the amount. Moreover, if the Producers had wanted to assure the collection of interest retroactively, they could have done so contractually.²⁸ Under the specific circumstances of this case and in view of the Commission’s attempt to reach a fair result with respect to the Section 110 issue as a whole, we believe that the Commission acted within its discretion.

D.

The final issues arising from the Section 110 allowances relate to the Commission’s making distinctions between interstate gas and Section 105 and 106(b) gas (intrastate gas and intrastate rollover gas, respectively; hereinafter collectively called “intrastate gas”) in its regulations regarding allowances. The Producers brand two aspects of these distinctions as “discrimination against intrastate sellers.” First, the Producers urge against the Commission’s decision making intrastate allowances collectable retroactive only to 1983 rather than 1980, the year allowed vis-a-vis interstate gas. Second, the Producers challenge the Commission’s finding that area rate clauses in intrastate gas contracts do not authorize the collection of a delivery allowance as they do with regard to interstate gas. This final contention is based, first, on the notion that the Commission lacked jurisdiction to “interpret” the intrastate contracts and, second, that even assuming Commission jurisdiction, the Commission’s “interpretation” of the area rate clauses is erroneous. These contentions are considered below.

The Producers’ first allegation of “discrimination” against intrastate sellers stems from the Commission’s decision to make intrastate allowances recoverable only from 1983, the effective date of Order 94-B. In the case of interstate gas, delivery and compression allowances were made collectible retroactive to 1980, the date of Order 94. The Commission defends this distinction by noting that in Order 94, the Commission promised that the generic delivery and compression allowances that it eventually promulgated would be retroactive to that order’s date. No mention was made of allowances for intrastate sellers, because at that time such sellers were expressly prohibited from receiving allowances under Order 68-A. R. at A94-98, A116. We believe that the Commission’s distinction is therefore rational. Indeed, if the intrastate allowances had been made retroactive to 1980 in spite of the fact that they were first mentioned in 1983 in Order 94-B, we would now be evaluating a case of clear retroactive ratemaking. The Commission did not err in freeing us from that evaluation.

The Producers next argue that the Commission erred in determining that area rate clauses in intrastate gas contracts do not authorize the collection of a generic delivery allowance. They base this assertion on two points: first, that the Commission lacks jurisdiction to “interpret” intrastate contracts and, second, that, even assuming jurisdiction, the Commission erred in its “interpretation” of the area rate clauses. The Commission argues that it is not interpreting these clauses but rather establishing reasonable eligibility requirements. R. at 6478.

The power of the Commission to establish eligibility standards for the collection of special rates was upheld by this Court in Pennzoil Co. v. F.E.R. C, 671 F.2d 119 (5th Cir.1982). In that case, this Court held that the Commission could require a negotiated contract term as a prerequisite to a seller’s collection of a Section 107(c)(5) incentive price. In so requiring, the court held that the Commission did not improperly interpret the contract in derogation of the parties’ right embodied in Section 101(b)(9) of the NGPA, 15 U.S.C. Section 3311(b)(9), to set gas prices by contract. 671 F.2d at 121. The 1982 Pennzoil case implies that the Commission has the corresponding power to state that particular contract language will not authorize a special rate. This is precisely what the Commission has done with respect to the area rate clause in intrastate gas contracts and the Section 110 allowances. We therefore reaffirm the Commission’s power to establish eligibility requirements in cases of this type.

We turn now to the Producers’ second attack on the Commission’s handling of area rate clauses in intrastate contracts: that is, even assuming jurisdiction, the Commission acted arbitrarily in not treating sellers under an intrastate contract like similarly situated interstate sellers. The Pipelines and the Associated Gas Distributors counter that it was unreasonable to allow any amount for delivery vis-a-vis intrastate contracts, for essentially the same reasons discussed with regard to their broad attack on generic allowances.²⁹

In 15 C.F.R. Section 271.1104(d)(2), the Commission provided that a seller of intrastate gas would receive the amount for delivery- as provided in its gas contract, unless it amends its contract to allow the collection of an amount for delivery “not to exceed an amount reasonably comparable to the Section 110 adjustments collected by similarly situated sellers” of interstate gas. No provision is made for the recovery of any other production-related cost. The Producers maintain that this approach violates the Congressional mandate in the NGPA that there be a single, uniform national gas market. The Commission does not dispute the importance of market uniformity as an NGPA objective; it does maintain, however, that uniformity is not the only policy. The Commission notes that prior to 1978, it lacked jurisdiction over sales of intrastate gas. As a result, it has no hard data on which to base a generic allowance for intrastate sellers. To this, the Producers respond that they provided data demonstrating that delivery allowances in the intrastate system should correspond exactly to the appropriate allowance for interstate gas.

Although the issue is close, we do not believe that the Commission behaved arbitrarily in this regard. The difference between the collection of a generic delivery allowance and the collection of an amount “reasonably comparable” to the generic allowance is relatively slight in this context. This is so, because in both cases the amount is merely a ceiling, subject to contractual limitation by the parties. We believe that the Commission’s varying levels of confidence in the two sets of data involved justify this rather slight difference in treatment. Moreover, the Commission’s decision to deny compression allowances to sellers under intrastate contracts similarly finds adequate support in the record. The Commission’s failure to establish a generic delivery allowance for intrastate gas and decision not to allow recovery of compression allowances via an area rate clause in an intrastate contract are therefore upheld.

III.

The second major issue in this case arises under the Declaratory Order issued pursuant to Title I of the NGPA. R. at 6852-69.³⁰ That order is directed to the applicability of the Title I maximum lawful price to a common situation in the gas industry. Very often, a producer-seller arranges contractually to have its own liquids and liquefiables³¹ transported by the pipeline-purchaser along with the newly sold gas. The pipelines typically perform this service either gratis or at a greatly reduced rate. This practice becomes somewhat problematic where a producer receives both the maximum lawful price and the free or reduced-rate transporting of its liquids and liquefiables. Nonetheless, in its Title I Declaratory Order, the Commission held that these services received by the seller are not part of the price; therefore, the maximum lawful price provisions of the NGPA are not violated by a contract of the type described above.

The Pipelines, along with the Associated Gas Distributors, strongly object to this interpretation of the NGPA maximum lawful price provisions. They argue that the Commission’s interpretation of the statute is contrary to Congress’s intent that all valuable consideration be deemed part of the maximum lawful price. They further note that maximum lawful prices apply to first sales, Section 504(a) of the NGPA, 15 U.S.C. § 3414(a), and that sale is defined as “any sale, exchange or other transfer for value,” Section 2(20) of the NGPA, 15 U.S.C. § 3301(20) (emphasis added). It follows, in their view, that, as the transporting of the liquids and liquefiables clearly constitutes value, the literal language of the NGPA is also ignored by the Commission’s Order. The Pipelines also argue that this result is inconsistent with the history and structure of the NGPA. Finally, the Pipelines argue that prior practice under the Gas Act compels a different result.

The Commission, joined in large measure by the Producers, views the essential question somewhat differently. It maintains that regardless of the broad NGPA definition of “sale,” the term “price” simply was not intended to include services of this type. In support of this, the Commission notes that it has long directed the pipelines to allocate the cost of these services away from the consumer; but if the pipeline chooses to provide this service at a reduced rate by contract and absorb the costs, the maximum lawful price provisions will not rescue it from its improvident contract. Moreover, this scheme frees the Commission from the endless chore of assigning a value to every aspect, every covenant, every warranty in a gas contract. In any event, the Commission urges that its interpretation of Title I is not unreasonable and should be sustained.

A.

Although the courts have the ultimate power of interpreting statutes, this Court generally accords “great deference” to the Commission in its interpretation of the NGPA. See Union Texas Petroleum Corp. v. FERC, 721 F.2d 146 (5th Cir.1983). Nonetheless, in this case, the Commission’s orders below admittedly raise serious questions. The most problematic of these is the specter of opening a gaping loophole in the maximum lawful price provisions in the NGPA. As the Pipelines argue, and with some force, there is considerable frailty in a definition of price that includes money and other tangible property but excludes services of unquestioned value.

On the special facts of this case, however, the order of the Commission can be sustained. This is so, because the Commission has had a longstanding policy of requiring that the pipelines not allocate these costs to the consumer in their rate proceedings. This has been accomplished either by allowing a pipeline to collect from the producer an additional amount over the wellhead price, as in the earlier scheme, or by empowering the pipelines to contract to provide this service below cost while prohibiting the recovery of these costs by the pipeline in their rate proceedings. It therefore does not seem unreasonable or inconsistent with the purposes of the NGPA to require the pipelines to adhere to their contracts, provided adequate protection of the above-described policy is assured. Moreover, we are unpersuaded that the Congress intended to require the Commission to consider this particular service as part of the price. Accordingly, we defer to the Commission’s reading of the statute.

IV.

The third set of issues in this case arises from another aspect of the Title I liquid and liquefiables problem. The Commission, under its Gas Act jurisdiction, places conditions on the issuance of many certificates of public convenience and necessity to pipelines. See 15 U.S.C. § 717f(e). Many of those conditions provided, in general terms, that pipelines would not be allowed in their rate cases to allocate to consumers the costs incurred in transporting producer-owned liquids and liquefiables. The Commission based these conditions on its finding that consumers did not benefit from these costs.

Conditions of this type were attacked below by pipelines in Trunkline Gas Co., 14 FERC it 61,222 (1981), and, on rehearing, in Transcontinental Gas Pipeline Corp., 222 FERC 1161,029 (1983). The Commission declined to review those conditions but amended the certificates to make clear that they could be challenged later in the pipelines individual rate cases. R. at 7119-22, 7163. Other similar certificate conditions, now before this court, were also challenged. Subsequently, however, a settlement agreement between the pipelines and the Commission resolved this issue for a period of years.³²

We are persuaded by the argument of the Commission and two of the pipelines that these orders are not yet ripe for our review. As the relevant settlement agreements lapse, the pipelines may decide to yield to the Commission’s will, to reach another settlement, or to litigate the issue at that time. In any event, nothing that this Court might hold would have any immediate effect in view of the settlement agreements. Any opinion would be essentially an advisory one, dealing with what the legal rights of the pipelines would have absent the agreements. Such an opinion is plainly inappropriate.

We therefore hold that these orders are not yet ripe for review. It should be noted, however, and we explicitly hold that the pipelines should not be deemed to have waived their rights to challenge these orders by delaying their challenge to the rate case stage.³³

V.

For the reasons outlined above, we affirm in substantial part, with the relatively minor exceptions noted in the text, the judgment of the Commission regarding the Section 110 issues, affirm in full as to the judgment of the Commission with respect to the Title I Declaratory Order issues, and hold that the certificate conditions issues are not yet ripe for review.

AFFIRMED IN PART; VACATED and REMANDED IN PART; DISMISSED IN PART.

1 . Case 83-4162 was brought to challenge the Section 110 allowances at the Interim Rule stage. Those challenges were premised on various alleged procedural irregularities. Case 83-4390 concerns those same allowances at the final stage, as well as the Title I declaratory order and the certificate conditions issues.

We are urged by some parties to reach the administrative problems raised in Case 83-4162 as "capable of repetition and evading review.” We believe that in view of Case 83-4390, those contentions are simply moot and decline the invitation to review them.

Case 85-4182 was consolidated with these cases after oral argument, as it raises the same issues as Case 83-4390.

2 . The Indicated Producers consist of the following individuals, corporations, and other legal entities.

Amerada Hess Corporation Aminoil Inc.

Amoco Production Co.

Arco Oil and Gas Company Ashland Exploration, Inc.

Cabot Petroleum Corporation Chevron U.S.A., Inc.

Cities Service Oil and Gas Corporation Conoco Inc.

Diamond Shamrock Corporation Elf Aquitaine, Inc.

Exxon Corporation

Getty Oil Company

Gulf Oil Corporation

J.M. Huber Corporation

Hunt Oil Company

Estate of H.L. Hunt

Hassie Hunt, Inc.

Hunt Industries

Hunt Petroleum Corporation

A.G. Hill

Caroline Hunt Schoellkopf

Lamar Hunt

N.B. Hunt

Inexco Oil Company

Kerr-Mcgee Corporation

Marathon Oil Company

Mitchell Energy Corporation

Mobil Oil Corporation

Mobil Producing Texas & New Mexico Inc.

Mobil Oil Exploration & Producing Southeast Inc.

Monsanto Oil Company

Pennzoil Company

Pennzoil Producing Company

Pennzoil Oil & Gas, Inc.

Pennzoil Louisiana and Texas Offshore, Inc.

Phillips Petroleum Company

Phillips Oil Company

Placid Oil Company

Shell Offshore Inc.

Shell Western E&P Inc.

Sohio Petroleum Company

Sun Exploration and Production Company

Tenneco Oil Company

Texaco Inc.

Texas Production Company

W.H. Hunt

Caroline Hunt Trust Estate

Lamar Hunt Trust Estate

W.H. Hunt Trust Estate

Secure Trusts

Ecee, Inc.

Pinto, Inc.

The Superior Oil Company

Union Oil Company of California

Williams Exploration Company

3 . The Pipeline Petitioners and Intervenors consist of the following companies:

Interstate Natural Gas Association of America

ANR Pipeline Company

Colorado Interstate Gas Company

Natural Gas Pipeline Company of America

Transcontinental Gas Pipe Line Corporation

Panhandle Eastern Pipeline

Company/Trunkline Gas Company

Sea Robin Pipeline Company

Southern Natural Gas Company

Tennessee Gas Pipeline Company

Texas Eastern Transmission

Corporation/Transwestern Pipeline

Company

United Gas Pipeline Company

4 . The Associated Gas Distributors is composed of the following companies:

Baltimore Gas & Electric Company

Bay State Gas Company

The Berkshire Gas Company

Boston Gas Company

The Brooklyn Union Gas Company

Central Hudson Gas & Electric Corporation

Chesapeake Utilities Corporation

City of Holyoke, Mass., Gas & Electric Department

City of Westfield Gas & Electric Light Department

Colonial Gas Company

Commonwealth Gas Co.

Concord Natural Gas Corp.

Consolidated Edison Company of New York, Inc.

Delmarva Power & Light Company

Elizabethtown Gas Company

Energy North, Inc.

Essex County Gas Company

Fitchburg Gas & Electric Light Company

Lynchburg Gas Company

New Jersey Natural Gas Company

New York State Electric & Gas Corporation

North Carolina Natural Gas Corporation

Northeast Georgia Municipal Gas Utilities

Northeast Utilities

Northern Utilities, Inc.

Pennsylvania Gas & Water Company

Pequot Gas Co.

Philadelphia Electric Company

Philadelphia Gas Works

Providence Gas Company

Public Service Company of North Carolina, Inc.

Public Service Electric & Gas Co.

South County Gas Co.

The Southern Connecticut Gas Co.

UGI Corporation

Valley Gas Co.

Washington Gas Light Co.

5 . This New York entity joins the Associated Gas Distributors on their brief on most issues. Reference to the Associated Gas Producers therefore normally suffices to identify a position as that of the New York Public Service Commission as well.

6 . Certain Pipeline Petitioners consist of the following:

Texas Eastern Transmission

Corporation/Transwestern Pipeline

Company

Sea Robin Pipeline Company

Panhandle Eastern Pipeline

Company/Trunkline Gas Company

Southern Natural Gas Company

United Gas Pipe Line Company

7 . ANR Pipeline Company and Transcontinental Gas Pipe Line Corporation join the Commission in arguing the case is not yet ripe. However, they concur with the other pipelines on the merits.

8 . Order 94, the Interim Rule, was issued July 25, 1980. In it, the Commission announced its intention to do a study to determine the appropriate level for delivery and compression allowances for interstate gas. It further announced that any amounts later determined appropriate would be made retroactive to the Order’s date.

Orders 94-A and 94-B amended these orders to provide the promised allowances. Order 94-B, promulgated January 24, 1983, also provided, for the first time, for some allowances for sellers of Section 105 and 106(b) gas (intrastate gas).

Orders 94-C and 94-D denied rehearing of these orders on May 24, 1983.

Order 334, promulgated September 27, 1983, made the Interim Rule final, leaving it intact in most respects.

' The orders’ provisions are described in greater detail where relevant in the text.

9 . Section 105 and 106(b) gas were treated somewhat differently. The issues relating to these categories of gas are discussed in part II D., supra.

10 . These allowances are fully explained in 18 C.F.R. § 271.1104. The specific amounts involved are discussed, where relevant, in the text of this opinion.

11 . Indeed, at oral argument the Pipelines themselves recoiled somewhat from this position, acknowledging that generic allowances might be permissible under certain narrow circumstances.

12 . Indeed, the Commission’s earlier experience prior to Order 94, which provided for a case-by-case approach, clearly confirms the impracticability of that approach. R. at 1666-78, 1840-46, 6074-75.

13 . This allowance is recoverable to a maximum of twenty miles.

14 . It is also noteworthy that the Commission has in place a Production Related Costs Board. 18 C.F.R. § 271.1105. This Board can assure that no allowance will be collected as the result of a new delivery system of very short length, built for the sole purpose of collecting an allowance.

15 . As an example, the Pipeline Petitioners proffer a system composed of one mile of new system and two miles (or any lesser length) of old system. If the system were entirely new and three miles in length, the applicable allowance would be eleven cents ($.07 + $.02 + $.02) per MMBtu. Under the current Commission regulations the allowance for a combined system of two miles old and one mile new is twelve cents ($.05 + $.07) per MMBtu. If the hypothetical system were composed of a few feet of old and three miles of new, the allowance would be sixteen cents ($.07 + $.05 + $.02 + $.02) per MMBtu.

16 . The Pipelines and the Associated Gas Distributors maintain that the argument relating the administrative inconvenience of measuring old systems is specious, in that measurement is already required for new systems. The difference of course, lies in what is gained by the measurement. In the case of new systems, it is absolutely necessary to an implementation of the fair system the Commission has conceived. In the case of old systems, measurement would provide no more than an occasional and small variation in an allowance for a combined system. The benefit, therefore, of measurement with respect to the old systems is far smaller.

17 . At oral argument, the Pipelines characterized this rationale as "post-hoc.” The record belies that assertion. R. at B1556.

18 . 18 C.F.R. § 271.1104(d)(l)(ii).

19 . R. at 1341-1412.

20 . The producer of this type of gas receives a greater effective price in that it is allowed to collect a Section 110 processing allowance in addition to the maximum lawful price.

21 . The Producers’ challenges to the Commission’s handling of intrastate gas is discussed in Section IID, infra.

22 . 18 C.F.R. Section 154.93(b)(l)(ii)(B) validates gas contract provisions that permit “a change in price to the applicable just and reasonable area ceiling rate which has been, or which may be, prescribed by the Commission for the quality of gas involved.” Provisions pursuant to that regulation are called "area rate clauses.” The actual language of the clauses varies from contract to contract. Nonetheless, this court has held that such provisions may generally be read to permit a producer to charge the NGPA’s maximum lawful price. Pennzoil Co. v. F.E.R.C., 645 F.2d 360, 389 (5th Cir.1981), cert. denied, 454 U.S. 1142, 102 S.Ct. 1000, 71 L.Ed.2d 293 (1982).

23 . 18 C.F.R. § 271.1104(c)(4)(ii)(B), by its terms, applies only to certain categories of interstate gas. The propriety of the distinction between interstate and intrastate gas is discussed below in Part IID.

24 . See Pennzoil v. FERC, supra, 645 F.2d at 388-90.

25 . Phillips further urges that the delays are so unwarranted as to justify special relief, as well as a declaration with respect to future Commission delays of this magnitude. Because of our disposition of this issue, we decline Phillips’ request for special relief.

26 . Accordingly, we do not reach the issue of whether retroactive allowances to 1978 would be the appropriate subject of judicial fiat even if undue delay by the Commission were shown.

27 . Interest is recoverable with specific contractual authority.

28 . The Producers maintain that they did not seek contractual relief because they thought it unnecessary in view of the Commission’s general policy favoring interest. Nonetheless, the Producers concede that they were aware of the Commission’s Shell Oil power to disallow interest in a specific case. Therefore, the short answer to the Producers’ argument is that their ill-founded reliance on Section 154.102(c)(2) does not bind the Commission or this Court.

29 . See Part IIA, supra. We find those contentions equally meritless here.

30 . The Commission's denial of rehearing of that order, R. at 6984-7007, as well as order in Texas Eastern Transmission Corp., 20 FERC If 61,116, reh’g denied, 21 FERC If 61,281 (1982), reh’g denied, 22 FERC f 61114 (1983), raise the identical issue and are also before this court.

31 . Liquids are hydrocarbons that are produced, with the various gasses, in liquid condensate form. Liquefiables are gaseous hydrocarbons, other than methane, which are easily converted into liquids.

32 . The expiration date of the settlement agreements vary; - however, none has yet expired.

33 . Indeed, the relevant settlement agreements make clear that no waiver is to be inferred. We emphasize this only to address the concerns of Certain Pipelines that such a waiver might later be found.