Justice Stevens
delivered the opinion of the Court.
By enacting the Natural Gas Policy Act of 1978 (NGPA), 92 Stat. 3350, 15 U. S. C. §3301 et seq. (1976 ed., Supp. V), Congress comprehensively and dramatically changed the method of pricing natural gas produced in the United States. In Title I of that Act, Congress defined eight categories of natural gas production, specified the maximum lawful price that may be charged for “first sales” in each category, and prescribed rules for increasing first sale prices each month and passing them on to downstream purchasers. The question presented in these cases is whether the Federal Energy Regulatory Commission has the authority to exclude from this scheme most of the gas produced from wells owned by interstate pipelines and to prescribe a different method of setting prices for that gas. The answer is provided by the Act’s definition of a “first sale” and by the scheme of the entire NGPA.
Respondents are interstate pipeline companies that transport natural gas from the wellhead to consumers. They purchase most of their gas from independent producers. In addition, they acquire a significant amount of gas from wells that they own themselves or that their affiliates own. Gas from all three sources is usually commingled in the pipelines before being delivered to their customers downstream. Thus, at the time of delivery it is often impossible to identify the producer of a particular volume of gas.
On November 14, 1979, the Commission entered Order No. 58, promulgating final regulations to implement the definition of “first sale” under the NGPA. The first category of producers — independent producers — is assigned a “first sale” for all natural gas transferred to interstate pipelines. The second category of producers — pipeline affiliates that are not themselves pipelines or distributors — is also assigned a “first sale” for all natural gas transferred to interstate pipelines, unless the Commission specifically rules to the contrary. In contrast, the third category of producers — pipelines themselves — is not automatically assigned a “first sale” for its production. A pipeline does enjoy a “first sale” for any gas it sells at the wellhead. Similarly, it enjoys a “first sale” for any gas it sells downstream that consists solely of its own production. It also enjoys a “first sale” for any downstream sales of commingled independent-producer and pipeline-producer gas, as long as it dedicated an equivalent volume of its own production to that purchaser by contract. Finally, it enjoys a “first sale” for any downstream sales of commingled gas in an otherwise unregulated intrastate market. However, if a pipeline producer sells commingled gas in an interstate market without having dedicated a particular volume of its production to that particular sale, it does not enjoy first sale treatment.
On August 4,1980, the Commission entered Order No. 98. The Commission noted that its construction of the NGPA in Order No. 58 had left most interstate pipeline production outside the Act’s coverage, since so much of it is commingled with purchased gas. It announced that such production and its downstream sale remain subject to the Commission’s regulatory jurisdiction under the Natural Gas Act (NGA), 52 Stat. 821, 15 U. S. C. §717 et seq. (1976 ed. and Supp. V). In order to provide pipelines with an incentive to compete with independent producers in acquiring new leases and drilling new wells, the Commission decided that pipeline production should receive treatment under the NGA that is comparable to the treatment given independent production under the NGPA. It therefore promulgated regulations under the NGA providing that the NGPA’s first sale pricing should apply to all pipeline production on leases acquired after October 8, 1969, and to all pipeline production from wells drilled after January 1, 1973, regardless of when the underlying lease had been acquired. All other pipeline production would be priced for ratemaking purposes just as it had been before the NGPA was enacted.
Respondents petitioned for review of both Commission orders, contending that Order No. 58 was based on a misreading of the NGPA and that in Order No. 98 the Commission had acted arbitrarily in refusing to authorize NGPA pricing for all pipeline production. The Court of Appeals held that the NGPA was intended to provide the same incentives to pipeline production as to independent production, that there were no practical obstacles to treating the transfer of gas from a pipeline’s production division to its transportation division as a first sale, and that the Commission’s reading of the NGPA was inconsistent with the goals of Congress. 664 F. 2d 530 (CA5 1981). It held Order No. 58 invalid and therefore did not review Order No. 98 separately.
We granted petitions for certiorari filed by the Commission and by state regulatory Commissions, which contend that the Court of Appeals’ holding will provide the pipelines with windfall profits that Congress did not intend. 459 U. S. 820 (1982). In explaining why we are in general agreement with the Court of Appeals, we first review the statutory definition of “first sale,” then consider the history and structure of the NGPA, and finally examine the specific arguments on behalf of the Commission’s position.
The respondents seek first sale treatment for one of two transfers of natural gas: the intracorporate transfer from a pipeline-owned production system to the pipeline, or the downstream transfer of commingled gas from the pipeline to a customer. If either transfer is treated as a first sale, respondents would be able to include an NGPA rate for production among their costs of service, just as they do when they acquire natural gas from independent producers. They contend initially that Congress has authorized the Commission, in the exercise of its sound discretion, to treat either transfer as a first sale. They contend further that Congress has not authorized the Commission to reject both possibilities.
The definition of a “first sale” is found in §2(21) of the NGPA. 92 Stat. 3355, 15 U. S. C. §3301(21) (1976 ed., Supp. V). It takes the form of a general rule, qualified by an exclusion. The general rule sweeps broadly, providing:
“(A) General rule. — The term ‘first sale’ means any sale of any volume of natural gas—
“(i) to any interstate pipeline or intrastate pipeline;
“(ii) to any local distribution company;
“(iii) to any person for use by such person;
“(iv) which precedes any sale described in clauses (i),
(ii), or (iii); and
“(v) which precedes or follows any sale described in clauses (i), (ii), (iii), or (iv) and is defined by the Commission as a first sale in order to prevent circumvention of any maximum lawful price established under this Act.” 92 Stat. 3355,15 U. S. C. §3301(21)(A) (1976 ed., Supp. V) (emphasis added).
Under the terms of the general rule, a transfer that falls within any one of its five clauses is presumptively a first sale. This means that there can be many first sales of a single volume of gas between the well and the pipeline’s customers. In this case, the downstream transfer plainly satisfies the general rule. The only obstacle to including the intracorporate transfer within the general rule is the question whether it may properly be deemed a “sale.” That obstacle, however, is insubstantial. The legislative history clearly demonstrates that the statute was not intended to prohibit the Commission from deeming it a sale; the Conference Committee Report provides that the Commission may “establish rules applicable to intracorporate transactions under the first sale definition.” H. R. Conf. Rep. No. 95-1752, p. 116 (1978). Thus, if the first sale definition consisted only of the general rule, the Commission would plainly be authorized to treat either transfer as a first sale.
The exception to the general rule provides:
“(B) Certain sales not included. — Clauses (i), (ii), (iii), or (iv) of subparagraph (A) shall not include the sale of any volume of natural gas by any interstate pipeline, intrastate pipeline, or local distribution company, or any affiliate thereof, unless such sale is attributable to volumes of natural gas produced by such interstate pipeline, intrastate pipeline, or local distribution company, or any affiliate thereof.” 92 Stat. 3355, 15 U. S. C. §3301(21)(B) (1976 ed., Supp. V).
This language does not diminish the Commission’s authority to treat the intracorporate transfer as a first sale. Whether it affects the Commission’s authority to treat the downstream transfer as a first sale depends on the meaning of the words “attributable to.” Although the Commission interpreted them as meaning “solely attributable to,” it would be at least as consistent with the ordinary understanding of the words to interpret them as meaning “measurably attributable to.” Furthermore, it would have been fully consistent with the spirit of the exemption if the Commission had adopted the latter interpretation and had given “first sale” treatment to a percentage of the downstream sale — the percentage that pipeline production forms of all the gas in the pipeline.
Thus, we agree with the respondents that the Commission has the authority to treat either the intracorporate transfer or the downstream transfer as a first sale. That, however, does not dispose of this litigation. For there is a substantial difference between holding that the Commission had the authority to treat either transfer as a first sale and holding that the Commission was required so to treat one or the other.
II
In order to determine whether the Commission was obligated to treat either the intracorporate transfer or the relevant portion of the downstream transfer as a first sale, it is necessary to examine the purposes of the NGPA. Those purposes are rooted in the history of federal natural gas regulation before 1978 and in the overall structure of the statute.
A
Between 1938 and 1978, the Commission regulated sales of natural gas in interstate commerce pursuant to the NGA. The NGA was enacted in response to reports suggesting that the monopoly power of interstate pipelines was harming consumer welfare. Initially, the Commission construed the NGA to require only regulation of gas sales at the downstream end of interstate pipelines. E. g., Natural Gas Pipeline Co., 2 F. P. C. 218 (1940). It authorized rates that were “just and reasonable” within the meaning of §4(a) of the NGA, 52 Stat. 822, 15 U. S. C. § 717c(a), by examining whatever costs the pipeline had incurred in acquiring and transporting the gas to the consumer. If the pipeline itself or a pipeline affiliate had produced the gas, the actual expenses historically associated with production and gathering were included in the rate base to the extent proper and reasonable. See FPC v. Hope Natural Gas Co., 320 U. S. 591, 614-615, and n. 25 (1944); Colorado Interstate Gas Co. v. FPC, 324 U. S. 581, 604-606 (1945). However, if the pipeline had purchased the gas from an independent producer, the Commission did not take jurisdiction over the producer to evaluate the reasonableness of its rates; it only considered the broad issue of whether, from the pipeline’s perspective, the purchase price was “collusive or otherwise improperly excessive.” Phillips Petroleum Co., 10 F. P. C. 246, 280 (1951).
In 1954, this Court rejected the Commission’s approach. We held that the NGA required the Commission to take jurisdiction over independent gas producers and to scrutinize the reasonableness of the rates they charged to interstate pipelines. Phillips Petroleum Co. v. Wisconsin, 347 U. S. 672 (1954). We interpreted the purpose of the NGA as being “to give the Commission jurisdiction over the rates of all wholesales of natural gas in interstate commerce, whether by a pipeline company or not and whether occurring before, during, or after transmission by an interstate pipeline company,” id., at 682, and concluded that, for regulatory purposes, there was no essential difference between the gas a pipeline obtains from independent producers and the gas it obtains from its own affiliates, id., at 685.
The problems of regulating the natural gas industry grew steadily between Phillips and the passage of the NGPA. At first, the Commission attempted to follow the Phillips mandate by applying the same regulatory technique it had always applied to pipeline-produced natural gas. It calculated just and reasonable rates for each company — whether pipeline, pipeline affiliate, or independent producer — by studying the costs of production that had historically been incurred by that particular company. But that so-called “cost of service” approach quickly proved impractical. See Atlantic Refining Co. v. Public Service Comm’n of New York, 360 U. S. 378, 389 (1959). Whereas there were relatively few interstate pipelines, the vast number of natural gas producers threatened to overwhelm the Commission’s administrative capacity. See Permian Basin Area Rate Cases, 390 U. S. 747, 757, and n. 13 (1968).
The Commission then shifted to an “area rate” approach. See Statement of General Policy 61-1, 24 F. P. C. 818 (1960). Instead of establishing individual rates for each company on the basis of its own costs of service, it established a single rate schedule for each producing region. Two elements of the area rate method bear mention. First, the Commission continued to base its computations on historical costs, rather than on projections of future costs. And second, it established two maximum rates for each area: a “new gas” rate for gas produced independently of oil from wells drilled after a given date, and an “old gas” rate for all other gas. The two-tiered structure, which priced gas on the basis of its “vintage,” rested on the theory that for already-flowing gas “price could not serve as an incentive, and . . . any price above average historical costs, plus an appropriate return, would merely confer windfalls.” Permian Basin Area Rate Cases, supra, at 797.
The Permian Basin area rate proceeding governed only production by independent producers. The Commission undertook a separate proceeding to consider whether it remained appropriate to treat pipelines and pipeline affiliates on a company-by-company basis. On October 7, 1969, 17 months after this Court approved the use of area rates, the Commission concluded that for leases acquired from that date on, pipeline gas should receive pricing on a “parity” basis; such gas would be eligible for the same area rate as independently produced gas of the same vintage. Pipeline Production Area Rate Proceeding (Phase I), 42 P. P. C. 738, 752 (Opinion No. 568). Gas produced from already-acquired leases would continue to be priced on the old single-company cost-of-service method “in order to expedite the proceedings and to avoid complications and evidentiary problems.” Id., at 753. Significantly, gas produced by pipeline affiliates would be treated in precisely the same manner as gas produced by the pipelines themselves.
In the early 1970’s, it became apparent that the regulatory structure was not working. The Commission recognized that the historical-cost-based, two-tiered rate scheme had led to serious production shortages. See Southern Louisiana Area Rate Proceeding, 46 F. P. C. 86, 110-111 (1971). See generally Breyer & MacAvoy, The Natural Gas Shortage and the Regulation of Natural Gas Producers, 86 Harv. L. Rev. 941, 965-979 (1973). Therefore, the Commission modified its practices, shifting from an “area rate” to a “national rate” approach. National Rates for Natural Gas, 51 F. P. C. 2212 (1974) (Opinion No. 699). The national rate became effective for all wells drilled after January 1, 1973, and applied equally to production by independent producers, pipelines, and pipeline affiliates. A few months later, the Commission responded further by shifting from a pure historical-cost-based to an incentive-price-based approach, National Rates for Natural Gas, 52 F. P. C. 1604, 1615-1618 (1974) (Opinion No. 699-H), and by temporarily abandoning the practice of vintaging, id., at 1636.
These measures did not prove sufficient. The interstate rates remained substantially below the unregulated prices available for intrastate sales, and the interstate supply remained inadequate. Throughout 1977 and 1978, the 95th Congress studied the situation. During the closing hours of the Second Session, it enacted a package of five Acts, one of which was the NGPA. The NGPA is designed to preserve the Commission’s authority under the NGA to regulate natural gas sales from pipelines to their customers; however, it is designed to supplant the Commission’s authority to establish rates for the wholesale market, the market consisting of so-called “first sales” of natural gas.
B
The NGPA was the product of a Conference Committee’s careful reconciliation of two strong, but divergent, responses to the natural gas shortage.
The House bill had proposed “a single uniform price policy for natural gas produced in the United States.” H. R. Rep. No. 95-496, pt. 4, p. 96 (1977). A key element of that policy had been the establishment of a statutory incentive price structure that would simultaneously promote production and reduce the regulatory burden:
“[0]ther controversial aspects of current Federal regulation are not perpetuated. The uncertainties associated with lengthy judicial review of Federal Power Commission wellhead price determinations are avoided by use of a statutorily established maximum lawful price. Regulatory lag and other problems associated with reliance upon historical costs to establish just and reasonable wellhead prices are similarly avoided. Vintaging of new natural gas prices would also terminate.” Id., at 97.
The Senate bill, passed on the floor, would have maintained Natural Gas Act regulation for all gas sold or delivered in interstate commerce before January 1, 1977, and steadily cut back on Commission jurisdiction so that all natural gas sold after January 1, 1982, would have been completely deregulated. S. 2104, 95th Cong., 1st Sess., 123 Cong. Rec. 32306 (1977).
The Conference Committee’s compromise has been justly described as “a comprehensive statute to govern future natural gas regulation.” Note, Legislative History of the Natural Gas Policy Act, 59 Texas L. Rev. 101, 116 (1980). In Title I, it establishes an exhaustive categorization of natural gas production, and sets forth a methodology for calculating an appropriate ceiling price within each category: Section 102 covers “new natural gas and certain natural gas produced from the Outer Continental Shelf”; §103 covers “new, onshore production wells”; § 104 covers “natural gas committed or dedicated to interstate commerce on the day before the date of the enactment of [the NGPA]”; § 105 covers “sales under existing intrastate contracts”; § 106 covers “sales under rollover contracts”; § 107 covers “high-cost natural gas”; § 108 covers “stripper well natural gas”; and § 109 is a catchall, covering “any natural gas which is not covered by any maximum lawful price under any other section of this subtitle.” 92 Stat. 3358-3368, 15 U. S. C. §§3312-3319 (1976 ed., Supp. V).
In each category of gas, the statute explicitly establishes an incentive pricing scheme that is wholly divorced from the traditional historical-cost methods applied by the Commission in implementing the NGA. The price is established either in terms of a dollar figure per million Btu’s, or in terms of a previously existing price, and is inflated over time according to a statutory formula. See § 101. For three categories of gas, the statute recognizes that the ceiling may be too low and authorizes the Commission to raise it whenever traditional NGA principles would dictate a higher price. See §§ 104, 106, and 109. The Commission is also given a somewhat ambiguous mandate to authorize increases above the ceiling for the other five categories. See § 110(a)(2). In none of the eight categories, however, is the Commission given authority to require a rate lower than the statutory ceiling.
Several features of this comprehensive scheme bear directly on the question whether Congress intended the Commission to be able to exclude pipeline production from its coverage completely. To begin with, the categories are defined on the basis of the type of well and the past uses of its gas, not on the basis of who owns the well. And since it is drafted in a manner that is designed to be exhaustive, all natural gas production falls within at least one of the categories.
Moreover, the statute replaces the Commission’s authority to fix rates of return to gas producers according to what is “just and reasonable” with a precise schedule of price ceilings. Section 601(b)(1)(A) provides that, “[sjubject to paragraph (4), for purposes of sections 4 and 5 of the Natural Gas Act, any amount paid in any first sale of natural gas shall be deemed to be just and reasonable if. . . such amount does not exceed the applicable maximum lawful price established under Title I of this Act.” 92 Stat. 3410, 15 U. S. C. § 3431(b)(1)(A) (1976 ed., Supp. V). The new statutory rates are intended to provide investors with adequate incentives to develop new sources of supply. As the Commission itself recognized in Order No. 98: “The Congressional decision to reorder the economic regulation of natural gas prices to provide a uniform system of statutorily prescribed price incentives was based on a . . . belief that such incentives are necessary to secure continued development and additional production of natural gas.” 45 Fed. Reg. 53093 (1980).
The statute evinces careful thought about the extent to which producers of “old gas” — gas already dedicated to interstate commerce before passage of the NGPA — would be able to enjoy incentive pricing. Section 104 of the statute directly incorporates part of the “vintaging” pattern that previously existed under the NGA. Thus, most old gas continues to receive the price it received under the NGA, increased over time in accordance with the inflation formula found in § 101. However, § 101(b)(5) of the Act specifies that if a volume of gas fits into more than one category, “the provision which could result in the highest price shall be applicable.” 92 Stat. 3357, 15 U. S. C. §3311(b)(5) (1976 ed., Supp. V). Thus, old gas that would be subject to the old NGA vintaging rules may be entitled to a higher rate if it falls within one or more of the other Title I categories, in particular § 107 (high-cost natural gas) and § 108 (stripper well gas). Whether or not the old NGA rates were in fact sufficient to stimulate some production from those categories, Congress concluded that the Nation’s energy needs justified the higher, statutory rates.
In addition, the costs of providing these production incentives are plainly to be shouldered by downstream consumers, not by pipelines. Title II of the Act establishes a complicated structure, to be implemented by the Commission, for determining which consumers are to face the bulk of the price increases. 92 Stat. 3371-3381, 15 U. S. C. §§3341-3348 (1976 ed., Supp. V). That Title is designed to allocate the burden among categories of consumers; it is not designed to diminish in any way the incentive for producers or to force pipelines to bear any part of that burden. As the Conference Report makes plain:
“The conference agreement guarantees that interstate pipelines may pass through costs of natural gas purchases if the price of the purchased natural gas does not exceed the ceiling price levels established under the legislation .... This recovery must be consistent with the incremental pricing provisions of Title II; however, Title II is structured to permit recovery of all costs which a pipeline is entitled to recover.” H. R. Conf. Rep. No. 95-1752, p. 124 (1978).
Given such a comprehensive scheme, we conclude that Congress would have clearly identified, either in the statutory language or in the legislative history, any significant source of production that was intended to be excluded. For the usefulness of natural gas does not depend on who produces it, and there is no reason to believe that any one group of producers is less likely to respond to incentives than any other. Yet nowhere in the NGPA do we find any expression of a desire to exclude pipeline production.
Indeed, three statutory provisions combine to give a clear signal that the statute was intended to include such production. Section 203, which defines the acquisition costs subject to passthrough requirements, specifically states:
“Interstate pipeline production. — For purposes of this section, in the case of any natural gas produced by any interstate pipeline or any affiliate of such pipeline, the first sale acquisition cost of such natural gas shall be determined in accordance with rules prescribed by the Commission.” 92 Stat. 3375, 15 U. S. C. § 3343(b)(2) (1976 ed., Supp. V).
This provision expressly mentions pipeline production as a matter subject to NGPA jurisdiction. Perhaps even more significantly, it makes clear that Congress intended to continue a policy that had been in effect since 1938: a policy of drawing no distinction between wells owned by a pipeline itself and those owned by an affiliate. That point is equally apparent from the exemption half of the definition of “first sale” in Title I. That provision requires first sale treatment of a sale that is “attributable to volumes of natural gas produced by such interstate pipeline... or any affiliate thereof.” § 2(21)(B) (emphasis added). See supra, at 326. Given that pipelines are to be treated in the same manner as pipeline affiliates, and given that pipeline affiliates are explicitly covered under the NGPA, see § 601(b)(1)(E), it follows directly that pipeline production is covered.
In sum, the Court of Appeals correctly concluded that Congress intended pipeline production to receive first sale pricing. The Commission had no authority to ignore that intention absent a persuasive justification for doing so.
l ) — I
Of course, “the interpretation of an agency charged with the administration of a statute is entitled to substantial deference.” Blum v. Bacon, 457 U. S. 132, 141 (1982). It is therefore incumbent upon us to consider carefully the Commission’s arguments that Congress implicitly intended to exempt pipeline production from an otherwise comprehensive regulatory scheme. We think it important to address three of the Commission’s arguments explicitly: one is aimed at the propriety of giving first sale treatment to the intra-corporate transfer, one at the propriety of giving first sale treatment to the downstream sale, and the third at the propriety of any form of first sale treatment for pipeline production.
The Commission suggests that it would be wrong to assign the intracorporate transfer a first sale price “automatically” because not even independent producers receive such automatic treatment. It emphasizes the Conference Committee’s admonition that “maximum lawful prices are ceiling prices only. In no case may a seller receive a higher price than his contract permits.” H. R. Conf. Rep. No. 95-1752, p. 74 (1978). Since arm’s-length contractual bargaining may reduce the price for independent producers, the Commission suggests that “[i]t would be anomalous in the extreme to conclude that Congress nonetheless meant to permit pipeline producers to qualify automatically for full NGPA prices by virtue of intracorporate transfers that are not covered by contracts.” Brief for Federal Energy Regulatory Commission 31-32.
This argument refutes a position that no one advocates. We agree completely that the intracorporate transfer should not “automatically” receive the NGPA ceiling price. Congress undoubtedly intended pipeline producers to be treated in the same manner as pipeline affiliate producers. The latter group is subjected to market control, through the application of § 601(b)(1)(E), which provides that, “in the case of any first sale between any interstate pipeline and any affiliate of such pipeline, any amount paid in any first sale shall be deemed to be just and reasonable if, in addition to satisfying the requirements of [Title I], such amount does not exceed the amount paid in comparable first sales between persons not affiliated with such interstate pipeline.” 92 Stat. 3410, 15 U. S. C. §3431(b)(1)(E) (1976 ed., Supp. V).
The Commission also argues that adoption of the downstream sale theory would result in the application of first sale maximum lawful prices to all mixed volume retail sales by interstate pipelines, intrastate pipelines, and local distribution companies, thereby supplanting traditional state regulatory authority over the costs of intrastate pipeline transportation service. We find this argument to be exaggerated. The Commission concedes that a downstream sale of pipeline production in another State is a “first sale” if that production has not been commingled with purchased gas. It allows the pipeline to include an appropriate NGPA rate (reflecting the costs of producing the gas) in the overall downstream price (which also reflects transportation and administrative costs). Applying the same principle to commingled gas would in no way trench upon state regulatory authority. The narrow issue posed — the proper cost to be assigned a pipeline’s production efforts — is no different from the issue posed when a cost must be assigned to a pipeline’s purchase of gas from its producing affiliate. And it effects no special change in the relationship between federal and state regulatory jurisdiction.
Finally, the Commission argues that pipeline producers would enjoy an unintended windfall if they received first sale pricing. This windfall argument is obviously limited to only one particular category of gas: gas already dedicated to interstate commerce on the date of enactment of the NGPA, and subject to cost-of-service pricing. For under the Commission’s own Order No. 98, all other pipeline production receives the same price it would receive if treated as a first sale under the NGPA. The Commission argues, however, that the residual cost-of-service production should be excluded because the pipelines were guaranteed a risk-free return on their initial investments in those wells. To allow the pipelines to receive NGPA pricing on future production from those wells would allegedly be “an irrational result with . . . unfair consequences for consumers.”
This argument glosses over the full meaning of Congress’ determination that old gas qualifies for “first sale” treatment. Under § 104, such gas retains its former NGA price, subject to increases over time for inflation. Section 104 provides absolutely no opportunity for a windfall. To be sure, old gas could receive a rate higher than the inflated NGA rate if it falls within one of the special categories of gas whose production Congress saw a need to stimulate. Seizing on that fact, the Commission suggests in a footnote to its brief that much of the gas at issue here would be “stripper well” production, subject to the incentive prices of § 108. It argues that, at least for that category of gas, a windfall would exist, since the Commission believes that cost-of-service treatment would provide just as strong an incentive as the § 108 price.
That belief, however, was plainly not shared by Congress. For the statute explicitly grants the §108 rate to pipeline affiliates — entities that were previously subject to the same cost-of-service treatment as the pipelines themselves. Moreover, the Commission does not pursue its windfall argument to its logical conclusion. For it agrees that a pipeline is entitled to the NGPA price for any production it sells at the wellhead. Yet by denying the pipeline NGPA treatment if it transports the gas to another State, the Commission only creates an incentive for wellhead sales, in flat contradiction to one of the NGPA’s motivating purposes — to eliminate the dual market that distinguished between interstate and intrastate sales of natural gas.
The Commission’s position is contrary to the history, structure, and basic philosophy of the NGPA. Like the Court of Appeals, we conclude that its exclusion of pipeline production is “inconsistent with the statutory mandate [and would] frustrate the policy that Congress sought to implement.” FEC v. Democratic Senatorial Campaign Committee, 454 U. S. 27, 32 (1981). Unlike the Court of Appeals, however, we believe Congress intended to give the Commission discretion in deciding whether first sale treatment should be provided at the intracorporate transfer or at the downstream transfer. The cases should be remanded to the Commission so that it may may make that choice. The judgment of the Court of Appeals is vacated, and the cases are remanded for further proceedings consistent with this opinion.
It is so ordered.
In this opinion, we use the term “Commission” to refer to both the Federal Energy Regulatory Commission and its predecessor, the Federal Power Commission.
See 44 Fed. Reg. 66577 (1979). The final regulations are found at 18 CFR §270.203 (1983).
See 45 Fed. Reg. 53091 (1980).
The final regulations are found at 18 CFR §§2.66, 164.42 (1983).
The text of clause (v) makes it plain that the italicized word “and” at the end of clause (iv) was intended to be “or.”
One commentator has suggested that “where the producer sells to a gatherer, who in turn sells to a processor who eventually sells to a pipeline, there may be three first sales of the same gas.” Hollis, Title I and Related Producer Matters Under the NGPA, in 2 Energy Law Serv., Monograph 4D, § 4D.02 (H. Green ed. 1981). See also 18 CFR §270.202 (1983) (setting forth rules governing resales).
As defined in the statute,
“[t]he term ‘sale’ means any sale, exchange, or other transfer for value.”
92 Stat. 3355, 15 U. S. C. §3301(20) (1976 ed., Supp. V).
The latter meaning would be clear beyond debate if instead of the word “unless,” Congress had used the phrase, “except to the extent that.”
See Federal Trade Comm’n, Utility Corporations, S. Doc. No. 92, 70th Cong., 1st Sess. (1928). The reports are mentioned explicitly in § 1(a) of the NGA.
In 1976, the Commission decided to return to vintaging. See National Rates for Natural Gas, 56 F. P. C. 509 (1976) (Opinion No. 770).
Stripper well natural gas is defined as follows:
“(1) General Rule. — Except as provided in paragraph (2), the term ‘stripper well natural gas’ means natural gas determined ... to be nonassociated natural gas produced during any month from a well if—
“(A) during the preceding 90-day production period, such well produced nonassociated natural gas at a rate which did not exceed an average of 60 Mcf per production day during such period; and
“(B) during such period such well produced at its maximum efficient rate of flow, determined in accordance with recognized conservation practices designed to maximize the ultimate recovery of natural gas.
“(2) Production in excess of 60 Mcf. — The Commission shall, by rule, provide that if nonassociated natural gas produced from a well which previously qualified as a stripper well under paragraph (1) exceeds an average of 60 Mcf per production day during any 90-day production period, such natural gas may continue to qualify as stripper well natural gas if the increase in nonassociated natural gas produced from such well was the result of the application of recognized enhanced recovery techniques.
“(3) Definitions. — For purposes of this subsection—
“(A) Production Day. — The term ‘production day’ means—
“(i) any day during which natural gas is produced; and
“(ii) any day during which natural gas is not produced if production during such day is prohibited by a requirement of State law or a conservation practice recognized or approved by the State agency having regulatory jurisdiction over the production of natural gas.
“(B) 90-day Production Period. — The term ‘90-day production period’ means any period of 90 consecutive calendar days excluding any day during which natural gas is not produced for reasons other than voluntary action of any person with the right to control production of natural gas from such well.
“(C) Nonassociated Natural Gas. — The term ‘nonassociated natural gas’ means natural gas which is not produced in association with crude oil.” 92 Stat. 3367-3368, 15 U. S. C. § 3318(b) (1976 ed., Supp. V).
The dissent suggests that because § 104 of the NGPA preserves the old NGA price for certain first sales of “old gas,” the NGPA “did not intend to eliminate all vestiges of the Commission’s earlier pricing authority. ” Post, at 348-349; see also post, at 348, n. 6. This suggestion confuses the choice of a benchmark price with the choice of regulatory authority. For some (but not all) old gas, the NGA price is preserved as an initial ceiling price. But over time, that price moves according to a statutory formula, rather than through the exercise of Commission regulatory authority. See §§ 101, 601(b)(1)(A).
Section 104 provides:
“(a) Application. — In the case of natural gas committed or dedicated to interstate commerce on the day before the date of the enactment of this Act and for which a just and reasonable rate under the Natural Gas Act was in effect on such date for the first sale of such natural gas, the maximum lawful price computed under subsection (b) shall apply to any first sale of such natural gas delivered during any month.
“(b) Maximum Lawful Price.—
“(1) General Rule. — The maximum lawful price under this section for any month shall be the higher of—
“(A)(i) the just and reasonable rate, per million Btu’s, established by the Commission which was (or would have been) applicable to the first sale of such natural gas on April 20, 1977, in the case of April 1977; and
“(ii) in the case of any month thereafter, the maximum lawful price, per million Btu’s, prescribed under this subparagraph for the preceding month multiplied by the monthly equivalent of the annual inflation adjustment factor applicable for such month, or
“(B) any just and reasonable rate which was established by the Commission after April 27, 1977, and before the date of the enactment of this Act and which is applicable to such natural gas.
“(2) Ceiling Prices May Be Increased If Just and Reasonable. — The Commission may, by rule or order, prescribe a maximum lawful ceiling price, applicable to any first sale of any natural gas (or category thereof, as determined by the Commission) otherwise subject to the preceding provisions of this section, if such price is—
“(A) higher than the maximum lawful price which would otherwise be applicable under such provisions; and
“(B) just and reasonable within the meaning of the Natural Gas Act.” 92 Stat. 3362-3363, 15 U. S. C. §3314 (1976 ed., Supp. V).
For some categories of gas, the NGPA ceiling prices are an intermediate step on the path from a fully regulated industry to a deregulated industry. Sections 121 and 122 of the NGPA provide a mechanism for the ultimate decontrol of a number of categories of natural gas.
In Order No. 98, the Commission effectively conceded that the goals of the NGPA apply just as directly to pipeline production as to independent production:
“Having embarked under the NGA upon a course which would provide price incentives for both pipeline and independent producer production to encourage production of additional gas supplies, and having been reaffirmed in this course by evidence of a similar purpose in Congress’ enactment of a pricing scheme in the NGPA designed to encourage additional production, we believe that our mandate of coordinating the NGPA and the NPA would best be accomplished through a policy of pricing parity among independent and pipeline producers.” 45 Fed. Reg. 53093 (1980).
In its reply brief, the Commission argues that Congress intended to distinguish between production by pipelines and production by pipeline affiliates, on the theory that affiliate sales “are governed by sales contracts” and are therefore “subject to the realities of the marketplace.” Reply Brief for Federal Energy Regulatory Commission 4-6. Yet § 601(b)(1)(E) reveals that Congress expressly refused to rely on affiliate sales contracts as reflecting the realities of the marketplace. See infra, at 340. Congress brought affiliate production within the scope of the NGPA, fully aware that it could not rely on arm’s-length bargaining between affiliates to keep prices low.
The dissent declares that “there is nothing in the legislative hearings, Reports, or debates which expresses any congressional dissatisfaction with the existing pricing of pipeline production or which suggests that the Commission’s pricing of the oldest and lowest cost pipeline production on a cost-of-service basis. . . inhibited optimum production efforts by the pipelines.” Post, at 347-348; see also post, at 350-351 (“the very fact that NGPA prices are not necessary to spur natural gas production by the pipeline companies — as they are for independent producers — is a sufficient basis upon which to uphold the Commission’s interpretation”). The expression and suggestion are indeed present in both the statute, § 601(b)(1)(E), and the Conference Report, H. R. Conf. Rep. No. 95-1752, p. 124 (1978) — if cost-of-service pricing were adequate, Congress simply would not have included pipeline affiliate production within the scope of the NGPA.
The dissent suggests that we violate the principle of deference to the agency’s construction of the statute and improperly substitute our own reading of the statutory scheme. It is difficult, however, to argue convincingly that the Court is disregarding the agency’s expertise when the Commission itself recognized in Order No. 98 that the policies of the NGPA would be better served by granting NGPA incentive prices to pipeline-produced gas. On this point, the Commission observed:
“Having embarked under the NGA upon a course which would provide price incentives for both pipeline and independent producer production to encourage production of additional gas supplies, and having been reaffirmed in this course by evidence of a similar purpose in Congress’ enactment of a pricing scheme in the NGPA designed to encourage additional production, we believe that our mandate of coordinating the NGPA and the NGA would best be accomplished through a policy of pricing parity among independent producers and pipeline producers.” 45 Fed. Reg. 53093 (1980) (emphasis added).
See also supra, at 334.
See Brief for Federal Energy Regulatory Commission 39.
We note that there do not appear to be any technical difficulties in taking this approach, for the Commission itself has established it as the approach it will follow in the absence of other regulatory procedures. In Order No. 58, the Commission invoked its “circumvention authority” under the NGPA to provide:
“[T]he term ‘first sale’ includes any sale by a pipeline or distributor which is comprised of production volumes from identifiable wells, properties, or reservoirs if a portion of those volumes is produced from wells, properties, or reservoirs owned by such pipeline or distributor unless:
“(1) The price at which such natural gas is sold is regulated pursuant to the Natural Gas Act or is regulated by a State agency empowered by State statute to establish, modify or set aside the rate for such sale; or
“(2) the Commission, on application, has determined not to treat such sale as a first sale.” 44 Fed. Reg. 66580 (1979).
As we recently noted in Exxon Corp. v. Eagerton, 462 U. S. 176, 186 (1983), § 105(a) of the NGPA extends federal authority to control producer prices to the intrastate market, but at the same time § 602(a) allows the States to establish price ceilings for that market that are lower than the federal ceiling.
Brief for Federal Energy Regulatory Commission 35.
Id., at 34, n. 35.
Similarly, the Commission admits that a pipeline is entitled to the NGPA price for its own production, as long as the downstream contract shows that the gas was “dedicated” to it from the beginning. We perceive no reason why the absence of a “dedication” clause in the contract should turn a legitimate incentive into a “windfall.”
The dissent appears to misunderstand our holding today, since it suggests that we do not hold unreasonable either of the Commission’s actions (with regard to the downstream transfer and with regard to the intra-corporate transfer). To summarize, we have reached three conclusions in this litigation. (1) It would be reasonable for the Commission not to give first sale treatment to the intracorporate transfer, as long as such treatment is given to the downstream transfer. (2) Similarly, it would be reasonable for the Commission not to give first sale treatment to the downstream transfer, as long as such treatment is given to the intracorporate transfer. (3) Yet it was an unreasonble construction of this comprehensive and exhaustive new legislation, contrary to its structure, purposes, and history, for the Commission to chop out virtually all pipeline production and to relegate it to discretionary regulation under the NGA. Both the dissent, post, at 350-351, and the Court of Appeals, 664 P. 2d 530, 536-538 (CA5 1981), offer reasons for preferring approach (1) to approach (2). Those policy arguments are not totally without merit, but they are not so persuasive that we would reverse the Commission if it adopted approach (2), see supra, at 340-341, and they of course provide no justification for rejecting approach (1).