
    UNITED STATES of America, Plaintiff, v. EXXON CORPORATION, Defendant.
    Civ. A. No. 78-1035.
    United States District Court, District of Columbia.
    March 25, 1983.
    
      Larry P. Ellsworth, Frank W. Krogh, Daniel F. Shea, Arthur S. Weissbrodt, Ellen Rosenberg-Blatt, Gary A. Gegenheimer, Dennis M. Moore, Office of Gen. Counsel, Dept, of Energy, C. Max Vassanelli, Richard A. Levie, Dept, of Justice, George Kielman, Dean S. Cooper, Joseph L. Gibson, Gilbert T. Renaut, Office of Solicitor, Economic Regulatory Adm., Dept, of Energy, Washington, D.C., for plaintiff.
    Rene P. Lavenant, Jr., Ronald D. Secrest, Houston, Tex., David R. Johnson, John M. Simpson, Maury S. Epner, Washington, D.C., Barbara Finney, Houston, Tex., for defendant Exxon Corp.
   MEMORANDUM OPINION

FLANNERY, District Judge.

This matter is before the court on cross-motions for summary judgment. Plaintiff Department of Energy (“DOE”) alleges that defendant Exxon Corporation (“Exxon”) from January 1975 to January 1981 violated federal two-tier oil price-control regulations by selling as higher-priced “new” oil what should properly have been sold as lower-priced “old” oil. DOE alleges Exxon overcharged crude oil purchasers by failing properly to establish a unit-wide base production control level — the basis for calculations of “new” and “old” oil — for the Hawkins Field Unit, which it operates near Hawkins, Texas. DOE asks that Exxon be ordered to pay into the United States Treasury the alleged amount of overcharges— some $895 million — with interest from the date of overcharge, and that Exxon be assessed civil penalties of about $38 million.

In support of its cross-motion for summary judgment, Exxon argues that it is guilty of no overcharge because the rule DOE seeks to enforce against it is invalid as beyond the agency’s statutory authority, arbitrarily and capriciously applied; issued without proper procedure, and finally, in any event, not applicable before September 1, 1976. In opposition to DOE’s motion, Exxon argues that the regulations at issue, if valid, require the establishment of a unit base production control level only upon the occurrence of a “significant alteration in producing patterns”, which occurred at the Hawkins Field no earlier than March 1977 and which, in any event, presents a disputed question of fact which may not be resolved on a motion for summary judgment.

For the reasons expressed below, plaintiff’s motion for summary judgment is granted in part and denied in part. Defendant’s motion is denied.

I. Background

A. The Regulatory Framework

In 1970 Congress passed the Economic Stabilization Act, Pub.L. No. 91-379, 84 Stat. 799, as amended 12 U.S.C. § 1904 note, authorizing the President to issue such orders as he felt appropriate in order to stabilize prices. In the summer of 1971 the President imposed wage and price controls and delegated their enforcement to the newly-created Cost of Living Council (“CLC”). During the next few years these controls were gradually phased out, but because prices of petroleum products continued to climb, the CLC in August 1973 promulgated regulations applicable only to the oil industry. 6 C.F.R. Part 150, Subpart L (1974) ; 38 Fed.Reg. 22,536 (1973).

Just a few months later, after the Arab oil embargo had caused oil prices to jump sharply, Congress in November 1973 passed the Emergency Petroleum Allocation Act (“EPAA”), Pub.L. No. 93-159, 87 Stat. 628, 15 U.S.C. § 751 et seq. (1976), requiring the promulgation of regulations within 15 days. EPAA § 4(a). In January 1974, the new Federal Energy Office (“FEO”) reissued the CLC price regulations, with only minor changes, at 10 C.F.R. Part 212, Subpart D (1975) , 39 Fed.Reg. 1924,1952 (1974) where they remained until the decontrol of petroleum prices in January 1981.

The heart of the petroleum price regulations was the application to domestically produced crude oil of a two-tier pricing structure designed to further the twin goals of combatting inflation while encouraging new domestic oil production. Cities Services Co. v. FEA, 529 F.2d 1016, 1020 (Em. App.1975). Producers were required to sell “old” crude oil at the lower-tier price and were allowed to sell “new” crude oil at a higher price. 10 C.F.R. §§ 272.73, 212.74 (1975). Amounts of “old” and “new” oil were calculated by comparing current production at a given property to that property’s production in an earlier corresponding base period, its “base production control level” (“BPCL”). Any excess of current production above the BPCL could be sold as higher-priced new oil. All current production up to the BPCL, however, had to be sold as lower-priced old oil.

While the regulations appear conceptually to be relatively straightforward, their application in some instances proved to be problematic. For example, the regulations required that a BPCL be established for every oil-producing “property.” 10 C.F.R. § 212.72 (1975). “Property” was defined as “the right which arises from a lease or from a fee interest to produce domestic crude petroleum.” Id. The question arose, which is now at the heart of this lawsuit, as to the proper method of calculating a BPCL for large, multilease tracts which during the base year had operated as independent, competing properties but which subsequent to 1972 had embarked upon the cooperative production process known as unitization. Did the regulations require that the BPCL for fields unitized after 1972 be established field-wide, by totalling the 1972 production of all properties which made up the unit, or could the BPCL be calculated on an individual, lease-by-lease basis?

To address this issue, the Federal Energy Administration (“FEA”) in August 1975 issued Ruling 1975-15 interpreting the existing regulations. 40 Fed.Reg. 40,832 (1975). In Ruling 1975-15 the FEA emphasized that the property concept in the regulations was based on the right to produce crude oil, however arising, and on the need to ensure a meaningful comparison between current and base year production. Id. Accordingly, the FEA ruled that in the case of properties unitized after 1972, the producer was required to calculate a unit-wide BPCL by totalling the individual 1972 monthly production for each of the leases constituting the unit. Id. Lease-by-lease calculations were not allowed.

Ruling 1975-15 sparked criticism from the oil industry that the unit BPCL requirement would discourage unitization and hence retard efforts to increase domestic production. See 41 Fed.Reg. 1564, 1569 (1976). Furthermore, in December 1975 Congress passed the Energy Policy and Conservation Act (“EPCA”), Pub.L. No. 94-163, Title IV, 89 Stat. 871, 941 (1975), 15 U.S.C. §§ 757 et seq, which among other things directed the FEA to promulgate amendments to the oil price regulations which would stimulate domestic production while at the same time combatting inflation in the prices of petroleum products. EPCA § 401(a); S.Rep. No. 516, 94th Cong., 1st Sess. 116-17, 120-21 (1975); U.S.Code Cong. & Admin.News p. 1762. To achieve these sometimes conflicting goals, Congress directed the FEA to create different classifications of crude oil which would bear different prices. 15 U.S.C. § 757(a). The weighted average price per barrel was not to exceed $7.66. Id. To ensure that higher prices would reward only real increases in production, Congress provided specifically in Section 401(a) of the EPCA that no amendment to the regulation could allow the price of any old oil to increase above the existing ceiling, unless the President specifically found that such an amendment would give positive incentives for enhanced recovery techniques, or was necessary to take into account declining production at a property, and would likely result in production greater than what would have occurred in the absence of the amendment. EPCA § 401(a); 15 U.S.C. § 757(b)(2). “Old oil production” was defined in the EPCA as the average production of old oil, as defined in Section 212.72, at a particular property in the months of September, October, and November of 1975. 15 U.S.C. § 757(b)(3).

In reaction to the industry criticism, and pursuant to the Congressional directives in the EPCA, the FEA in February 1976 amended the oil price regulations. 41 Fed. Reg. 4931 (1976). In response to the Congressional desire for increased production, the amendments addressed three different but overlapping objectives: to provide production incentives generally, to provide incentives for the maintenance of existing units, and to remove disincentives to prospective unitization.

The FEA noted in the preamble to the amendments that production had so declined at older properties that producers could no longer realistically expect to boost volume above 1972 levels, thereby rendering ineffective the lure of higher new oil prices. Id. at 4932. Accordingly, the FEA first amended Section 212.72 to provide producers at all properties the option of choosing a more recent, and presumably lower, BPCL based on average old oil production in 1975, rather than 1972. Id. at 4933; see n. 3, supra. In the same spirit, the FEA eliminated all deficiencies which had accumulated prior to February 1, 1976. 41 Fed.Reg. at 4933. In effect, all properties could begin afresh with a new BPCL and a more realistic chance of producing new oil. Id.

In addition, the FEA provided other incentives specifically for unitized properties. The first, applicable to both existing units and those to be formed on or after February 1, 1976, provided that Ruling 1975-15 was rescinded ab initio insofar as it required the unit operator to calculate a unit-wide BPCL as of the date of unitization. Id. at 4937. Instead, operators could continue to account for production on a lease-by-lease basis until enhanced recovery operations had begun or a significant alteration in producing patterns occurred within the unit. Id.

The agency defined “enhanced recovery” as “any method of recovering crude oil in which part of the energy employed to move the crude oil through the reservoir is applied from extraneous sources by the injection of liquids or gases into the reservoir.” Id. at 4941. A definition of “significant alteration” proved more elusive. The FEA hinted that a significant alteration might occur before an enhanced recovery project had begun operating when “production from certain leases is reduced or discontinued in preparation for enhanced recovery operations.” Id. at 4937. Although the agency used the term “substantially altered” in its unit BPCL rule, it did not then formally define the term, choosing instead to issue a later Ruling to clarify its meaning. Id.

Finally, to further encourage prospective unitization, the FEA enacted a new regulation applicable only to properties unitized after February 1, 1976. Id. at 4938. Such units could benefit, first, from a special rule allowing the BPCL to be calculated not on the basis of 1972 or 1975 production, but on the basis of average production in the twelve months preceding the calculation of a unit BPCL, i.e., preceding the date on which a significant alteration in producing patterns occurred or enhanced recovery operations were implemented. Id. In addition, the new regulation allowed a modified carryover of the stripper well lease exemption. See n. 4, supra. Producers at new units could sell at upper-tier prices a volume of crude oil equal to the average volume of stripper well lease production in the twelve months preceding the establishment of a unit BPCL. 41 Fed.Reg. at 4941.

In August 1976 the FEA furnished the promised clarification of “significant alteration in producing patterns,” defining it as “the occurrence of either (1) the application of extraneous energy sources by the injection of liquids or gases into the reservoir, or (2) the increase of production allowables for any property that constitutes the unitized property.” 41 Fed.Reg. 36,172, 36,184 (1976). At the same time, to eliminate any remaining disincentives to prospective unitization, the FEA adopted a special rule, applicable to units formed after September 1, 1976, to ensure that once a unit BPCL was established there could be no decrease in the absolute volumes of new oil. Producers at such units would be allowed to sell at upper-tier prices a volume of oil equal to the average volume of new oil produced from the constituent properties in the twelve months preceding establishment of a unit BPCL. Id. at 36,182, 36,184.

Finally, to dispel any remaining confusion as to the effect of the 1976 amendments to the regulations, the FEA in January 1977 issued Ruling 1977-2. 42 Fed.Reg. 4409 (1977) . In that Ruling the FEA made clear that the partial rescission in February 1976 of Ruling 1975-15 allowed operators of units formed before February 1, 1976 to wait, before establishing a unit BPCL, until a significant alteration in producing patterns occurred. Accounting for volumes of new and old oil after the 1976 amendments depended on when the unit was formed and when a significant alteration occurred or enhanced recovery operations were implemented. Section 212.72 applied to units formed before February 1, 1976, and those units received none of the incentives of Section 212.75. Units formed after February 1, 1976 received those benefits of Section 212.75 in effect at the time the operator had to calculate a unit BPCL — the special unit BPCL rule and imputed stripper oil provisions after February 1, 1976, and the provisions for imputed new oil after September 1, 1976. Id. at 4415; see n. 33, infra.

B. Facts

1. Hawkins Field

In December 1940, oil was discovered at the Hawkins Field, a ten thousand acre field twenty miles north of the town of Tyler in Wood County, Texas. By the late 1940’s, more than 200 individuals and companies produced oil from the Hawkins'field on more than 300 leases or tracts within the field. To promote rational exploitation of the field, the Texas Railroad’ Commission (“TRRC”) regulated the number of oil wells within the field, as well as the number of' barrels of Oil’ each well could produced termed production “allowables.” PX 5. In addition, the TRRC established a Maximum Efficient Rate (“MER”) of production for the field, a limit on the number of barrels which daily could be pumped from the field as a whole. Id. Still, by the mid-1960’s years of competitive exploitation had so drained the field that natural reservoir pressure declined, allowing the invasion of the crude oil bearing formations by water and the irrevocable loss of oil into the field’s original gas cap. Def.Mem. at 14-17. The Hawkins Field interest owners, led by Exxon, owner of two-thirds of the field’s production, concluded that this declining trend could be reversed, and the life of the field prolonged, only by means of a cooperative enhanced recovery project. Def.Mem. at 19.

Based on engineering studies conducted at that time, the owners concluded that their enhanced recovery efforts would require the construction of a plant for the production of inert gas to be injected underground in order to increase reservoir pressure. Id. Before the program could be implemented, however, the field had to be unitized, in part so that the costs of the ipert gas plant could be spread among the owners, but also because the injection of gas would cause crude oil to flow underground across lease, lines. Id. at 20; see n. 6, supra. Accordingly, as early as 1969 Exxon began promoting unitization. Def. Opp. at. 6. Its efforts began in earnest in the summer of 1971. when it first met with the more than 300 other working interest owners of the field. Id. Negotiations with thpse owners, as well as the more than 2200 royalty interest owners; continued for the next few years and culminated in the signing of a Unit Agreement in 1974. DX Intro-4. The agreement named Exxon as unit operator, and provided for the sharing of costs of the inert gas enhanced recovery project. Id. art. 11.1. Production, too, was to be shared, according to a formula by which the imputed share attributed to each tract was based on estimates of the recoverable reserves under each tract. Id. arts. 5, 6. The TRRC approved the agreement on November 26, 1974, permitting Exxon to take the steps necessary to implement the enhanced recovery project, and providing Exxon with a unit production allowable as of the effective date of unitization, January 1, 1975. DX Intro. 2. Under prior TRRC orders, the production allowables of a shut-in well could be transferred only pro rata among the other wells at the Hawkins Field. The unit allowable, equal to the then existing MER of approximately 112,-000 barrels per day, would allow Exxon to transfer production among wells in the unit at will.

At the same time that Exxon began its unitization efforts in 1969, it sought and received permission from the TRRC for an interim conservation project designed to curb the loss of crude oil at the field during the years needed to unitize the field and to implement the inert gas recovery project. The interim project called for the injection of up to 20 million cubic feet of natural gas per day, extraction of water, and increasing crude oil production. See PX 4 at 4. Accordingly, in its order approving the interim project, the TRRC authorized the increase of the Hawkins Field MER from 87,000 barrels per day to 112,000 barrels per day. PX 5. Shortly thereafter the rate of production was boosted up to the new, higher MER, and Exxon began injecting natural gas. It continued the natural gas injections throughout the succeeding years, beyond the effective date of unitization, until the completion of the inert gas plant. The inert gas plant, completed at a cost of some $57 million, commenced operations in March 1977. Def.Mem. at 4.

2. Exxon’s Application of the Oil Pnce Regulations at Hawkins Field

As noted above, the CLC in August 1973 promulgated the initial oil price regulations. Those regulations required the calculations of a BPCL for each “property.” “Property” was defined as “the right which arises from a lease or from a fee interest to produce domestic crude petroleum.” At the time the CLC regulations were promulgated, Exxon already operated several multilease units. Consequently, Exxon had to determine how the regulations would apply to those units. In the fall of 1973 Exxon issued instructions to its employees to treat each unit as a single “property” under the regulations with a single, unit BPCL. PX 46. Indeed, Exxon provided specific instructions for units which, as would be the case of Hawkins Field, were formed after 1972, the base year designated in the regulations for the calculation of the BPCL. For such units, Exxon instructed its employees that:

To arrive at the base production control level for the unit, sum by individual months the determined ... base production control level for each accounting lease ... contributed to the unit.

Id. at 7. In accordance with those instructions, Exxon applied an aggregated, unit BPCL at units it operated in Texas, California, Alabama and Florida. PX 76.

Exxon departed from its prior practice, however, at the Hawkins Field unit. In February 1974, Mr. Sidney J. Reso, Production Manager of Exxon’s East Texas Division and supervisor of the effort to unitize Hawkins Field, suggested in a memorandum to his superiors that old and new oil at the Hawkins Field unit be calculated on a lease-by-lease, rather than a unit basis. PX 56. To do otherwise, Mr. Reso warned, would result upon unitization in an 80% reduction in the amount of new, released and stripper oil to be claimed by prospective unit participants. Id. In the spring of 1974 a task force was formed at Exxon to study Mr. Reso’s suggestion. Def.Opp. at 17. That task force solicited the views of Exxon’s in-house counsel as to the legality of Mr. Reso’s suggestion under the regulations. On August 8,1974, Mr. Fred W. File, an attorney in Exxon’s legal department, issued a three-page opinion concluding that Mr. Reso’s proposal would be acceptable under then applicable FEA regulations. PX 77. Mr. File identified the purpose of the regulations' two-tier pricing system as being to promote additional recovery of crude oil. Id. at 2. The application of a unit BPCL to the Hawkins Field unit would result, as Mr. Reso had noted, in a reduction in the amount of new and released oil which unit participants would be able to claim. Such a result, Mr. File concluded, was inconsistent with the regulations’ purpose and therefore was “clearly not within [their] intent.” Id. Mr. File qualified his opinion, however, by noting that “FEA regulations are subject to frequent interpretations and revisions” and that sale of oil from the unit would be controlled by regulations in effect on the date of sale. Id. at 3. Nevertheless, he concluded, it would be appropriate to advise other Hawkins Field interest owners that lease-by-lease calculations would be acceptable under the regulations then in effect. Id.

Within a few weeks of the issuance of Mr. File’s opinion, Exxon so notified the prospective Hawkins Field unit participants. When Hawkins Field was formally unitized on January 1, 1975, and in the many months thereafter, Exxon did in fact apply individual, lease-by-lease BPCL calculations.

Recognizing that the restructuring of fields after 1972, such as by unitization, raised certain questions under the regulations, the FEA in August 1975 issued Ruling 1975-15, which made explicit the regulations’ requirement that a unit BPCL, equal to the sum of the BPCL’s of the constituent properties, be calculated and applied to every unit as of the date of unitization. Exxon representatives joined in the chorus of industry criticism of Ruling 1975-15 and met on several occasions in the fall of 1975 with various FEA officials. On November 24, 1975, Mr. File, the author of the August 1974 legal opinion to Mr. Reso, met with FEA General Counsel Michael Butler and presented him with written comments criticizing Ruling 1975-15 as creating insurmountable disincentives to unitization, and asking for its modification or clarification. DX 1-3. Three weeks later Mr. Butler informed Mr. File that the FEA was not then considering modification or rescission of Ruling 1975-15, but that the FEA intended shortly to initiate a rule making proceeding to address the special problems associated with enhanced recovery projects at unitized fields. DX Opp. CS-44.

On January 6,1976, the FEA published a notice of such a rule making, advancing the proposals which were eventually embodied in the February 1976 amendments to the oil price regulations. In its comments on the proposed regulations, Exxon embraced several of the FEA proposals, but suggested that the provision for lease-by-lease calculation of exempt oil should be extended for two years after formation of the unit or until implementation of the injection operations of an enhanced recovery project. PX 188 at 9. Moreover, to prevent the dissolution of existing units, Exxon requested that the same rules be applied to units formed before February 1, 1976. Id. Instead, the FEA in the February amendments chose to apply only some of the newly created incentives to preexisting units, and provided that new Section 212.75 would apply only prospectively. The “significant alterations” test, applicable to both, was not defined.

Although heartened by the rescission of Ruling 1975-15, Exxon remained uncertain as to the proper method of accounting for oil at the Hawkins Field Unit, due to the absence of any definition of “significant alteration in producing patterns.” After meeting again in mid-February with FEA officials, DX Opp. CS-61, Exxon concluded that until the FEA clarified the meaning of the new regulations, it would be proper to continue its lease-by-lease calculations at the Hawkins Field, and so advised the other Hawkins interest owners. DX Opp. CS-62.

In April 1976, the FEA sought comments as to how best to determine when there occurred “a significant alteration in producing patterns.” Exxon responded as it had earlier, namely, suggesting that “significant alteration” be defined as “the initiation of the major injection or other programs contemplated by the unit, provided however that the date will be no longer than two years from the formation of the unit.” DX Opp. CS-68 at Appendix 3, p. 2. In August the FEA finally published the long-promised clarification defining “significant alteration in producing patterns,” effective September 1, 1976, as either the injection of liquids or gases into the reservoir or the increase of production allowables for any property constituting the unit. Although still puzzled by this definition as it applied to the Hawkins Field Unit, Exxon attorney Fred File concluded that it did require the calculation of an aggregated, unit BPCL. DX Opp. CS-75. Accordingly, Exxon did calculate such a unit BPCL for the Hawkins Field Unit, but, noting that no definition had existed before that time, did so only as of September 1, 1976, and then under the more generous provisions of Section 212.75. Exxon continued to account for oil production at the Hawkins Field Unit in this manner until the repeal of the oil price regulations in January 1981.

From January 1975 through August 1976 production at the Hawkins Field remained relatively stable at about 112,000 barrels per day. See PX 288. Thereafter, despite the implementation of the inert gas enhanced recovery project in March 1977, production began to decline, to about 90,000 barrels per day in July 1977, and finally dropping to about 45,000 barrels per day in January 1981 at the time oil prices were decontrolled. Id. Despite the steady decline in production, an increasing percentage of oil was accounted for by Exxon as upper-tier, higher-priced oil, until beginning June 1, 1979, almost all of the then 62,000 barrels per day was classified as new oil. Id.; see Plaintiff’s Appendix of Charts and Graphs, F.

In January of 1978 the DOE issued to Exxon a Notice of Probable Violation, charging it with violating the oil price regulations in its sale of crude oil produced at the Hawkins Field Unit. On June 8, 1978, the DOE brought this enforcement action.

II. The Unit Property Rule

DOE maintains that the Hawkins Field Unit, because it was formed before February 1976, has always been subject solely to the requirement of 10 C.F.R. § 212.72 that a unit BPCL be established as of the date of unitization. DOE asserts further that the validity of this requirement, referred to herein as the unit property rule, has been definitively resolved by the Temporary Emergency Court of Appeals (“TECA”) in Pennzoil Co. v. DOE, 680 F.2d 156 (Em.App. 1982), cert. dismissed, - U.S. -, 103 S.Ct. 841, 74 L.Ed.2d 1032 (1983) and that . the test of significant alteration in producing patterns, first announced in the preamble to the February 1976 regulations, is relevant to pre-existing units only as guidance in its relaxed enforcement policy.

Exxon denies any controlling effect to the Pennzoil case and launches a wide-ranging attack on both the procedural and substantive validity of the unit property rule. The February 1976 amendments to the regulation, Exxon maintains, were not before the Pennzoil court. The significant alterations test constituted an entirely new regulation, Exxon continues, which cannot be given retroactive effect and which, as applied by DOE, arbitrarily discriminates between units formed before and after February 1976.

A. Procedural Validity

Exxon properly notes that the TECA in Pennzoil did not have before it the question of the procedural regularity of the issuance of the original CLC regulations in 1973. Exxon argues that the issuance of those regulations was fatally flawed because the notice of proposed rulemaking gave no hint that a unit would be considered a single “property.”

Section 207(c) of the Economic Stabilization Act of 1970, 12 U.S.C. § 1904 note, applied to the CLC the informal rulemaking requirements of Section 4 of the Administrative Procedure Act (“APA”), 5 U.S.C. § 553. Section 4(a) of the APA requires that “notice of proposed rule-making ... shall include ... either the terms or substance of the proposed rule or a description of the subjects and issues involved.” 5 U.S.C. § 553(b)(3). The purpose of the notice requirement is to afford interested parties a meaningful opportunity to participate in the rulemaking process. McCulloch Gas Processing v. DOE, 650 F.2d 1216, 1221 (Em.App.1981). Notice is sufficient if it “fairly apprise[s] the interested persons of the ‘subjects and issues’ before the agency.” Id. at 1222, quoting American Iron and Steel Institute v. EPA, 568 F.2d 284, 291 (3d Cir.1977).

Under the two-tier pricing structure proposed by the CLC on July 20, 1973, increased or “new” oil production was to be measured for each “property” on which the producer “has leased” or “owns production rights.” 38 Fed.Reg. 19,464; 19,482 (1973). Any amount by which current production exceeded 1972 production in a given month could be sold free of price controls. Id.

Exxon first complains that the “right to produce” concept underlying the unit property rule was absent from the July 20th notice. Plainly, the proposed regulations did not state in so many words that a unit would be considered a single property. Such precision is not required, however, in order to “fairly apprise” interested parties of the issues before the agency, and reaction to the notice here shows that interested parties were in fact properly alerted. Nine industry commenters specifically addressed the need for a precise definition of the term “property”. Pennzoil Co. v. DOE, supra, 680 F.2d at 161. Of these, seven suggested that a unit would or should be considered a single property.

Nor was Exxon as befuddled as it now claims to have been. An internal Exxon memorandum written only days after publication of the proposed rules interpreted them to require that a “ ‘base production control level’ [be] calculated for each property (Lease or Unit) each month .... ” PX 21. Mr. M.A. Wright, Chief Executive Officer of Exxon U.S.A., evinced his understanding of the unit property rule when he complained to CLC Director John Dunlop that secondary recovery operations might “substantially extend the producing life of older fields without producing ‘new’ oil under the Phase IY rules.” PX 29 at 11; PX 32 at 8-10. Two weeks after Mr. Wright’s comments an Exxon representative attended a mid-August CLC conference at which he learned that a unit of oil leases would be considered a single property under the proposed regulations and that “production levels from the combined properties would have to exceed 1972 levels before they were considered to be producing new oil.” PX 37. Finally, and most significant, Exxon belied its claimed incomprehension when it applied a unit BPCL without hesitation at its Webster Unit on September 1,1973, just days after the final regulation was published. PX76.

But Exxon’s complaint goes further. The final regulations, it claims, differed so substantially from their proposed form as to render the opportunity to comment meaningless and hence the regulation invalid. The court notes at the outset that the fact that a final rule differs, even substantially, from the published proposal, is not fatal; modification of proposed rules does not automatically generate a new round of notice and comment. BASF Wyandotte Corp. v. Costle, 598 F.2d 637, 642 (1st Cir.1979); International Harvester Co. v. Ruckleshaus, 478 F.2d 615, 632 (D.C.Cir.1973). As the court wrote in Trans-Pacific Freight v. Federal Maritime Commission, 650 F.2d 1235, 1249 (D.C.Cir.1980), “[t]he whole rationale of notice and comment rests on the expectation that the final rules will be somewhat different — and improved — from the rules originally proposed by the agency.”

Yet such explanations are unnecessary here, where that portion of the rule sub judice, as finally promulgated, differs hardly at all from its proposed form. Admittedly, the CLC noted in the preamble to the final rule that “Subpart L in its final form has been changed extensively from the proposal that was published on July 19, 1973.” 38 Fed.Reg. 22,536. Comparison of the proposed and final forms reveals, however, that the changes were made primarily in those parts of Subpart L dealing with refiners and retailers, and not in that part dealing with crude oil production. Compare 6 C.F.R. §§ 150.355 — 150.363 (1974), 38 Fed. Reg. 22,539 — 22,543, with proposed rules 6 C.F.R. §§ 150.355 — 150.362, 38 Fed.Reg. 19,482 — 19,483. To be sure, the word property was separately defined in final form, as “the right which arises from a lease or from a fee interest to produce domestic crude petroleum.” 6 C.F.R. § 150.354(b) (1974), 38 Fed.Reg. at 22,538. But the proposed formula for calculation of new and old oil referred to the property at which a producer “has leased” or “owns production rights.” 38 Fed.Reg. at 19,482. This court perceives no real difference, much less a substantial one, between the two forms.

Contrary to Exxon’s contentions, the notice and comment provisions of the APA “d[o] not require every aspect of the proposed order to be explained in the general notice.” Common Carrier Conference v. United States, 534 F.2d 981, 982-83 (D.C. Cir.1976), cert. denied 429 U.S. 921, 97 S.Ct. 317, 50 L.Ed.2d 288 (1976). Industry reaction to the CLC proposal, including that of Exxon, indicates that “[t]he industry was generally on notice” as to the workings of the two-tier pricing structure, id, thereby satisfying the notice and comment requirements of the APA.

Exxon contends, however, that CLC failed to satisfy the second requirement of APA procedures for informal rulemaking, namely, that the agency publish, along with the final rules, “a concise general statement of their basis and purpose.” 5 U.S.C. § 553(c). The CLC, says Exxon, failed to do so, rendering the oil price regulation invalid.

The primary purpose of requiring a contemporaneous statement of basis and purpose is to enable a reviewing court to judge the reasonableness of a rule in light of its stated aims. American Standard, Inc. v. United States, 602 F.2d 256, 269, 220 Ct.Cl. 411 (Ct.Cl.1979). But informal rulemaking does not demand an exhaustive listing of factual findings, nor a full reasoned analysis, but instead a “concise general statement.” Citizens to Save Spencer County v. EPA, 600 F.2d 844, 883-84 (D.C.Cir.1979); see 1 K. Davis, Administrative Law Treatise § 6:12 (2d ed. 1978). And where the agency’s aims are obvious and unmistakable, courts have upheld rules with no statement of basis and purpose. See Tabor v. Joint Board for Enrollment of Actuaries, 566 F.2d 705, 710 (D.C.Cir.1977); Alabama Ass’n of Insurance Agents v. Board of Governors of the Federal Reserve System, 533 F.2d 224, 236 (5th Cir.1976); Hoving Corp. v. FTC, 290 F.2d 803, 807 (2d Cir.1961); American Standard, Inc. v. United States, supra, 602 F.2d at 269. Examination of the preamble to the final oil price regulation, along with contemporaneous agency statements cited therein, when viewed in the surrounding regulatory context, provides ample evidence from which a reviewing court may discern the basis and purpose not only of the regulation generally, but also of that part of it about which Exxon complains, the unit property rule.

The preamble to the final rules stated: A 2-tier price system has been adopted, providing for a ceiling on domestic crude petroleum prices but allowing new crude and an equivalent amount of old crude to be sold at prices above the ceiling.

38 Fed.Reg. 22,536. Implicit in a structure which rewards only additional production with higher prices, and obvious even to those less sophisticated than Exxon, is a goal of inducing increased domestic crude oil production while keeping average prices down. But if Exxon could not glean that meaning from the regulation alone, the preamble referred to an August 10th press release from CLC Director John Dunlop which unequivocally stated:

The Council has been very concerned that the final regulations strike a delicate balance between constraining prices while at the same time encouraging the necessary increase in supplies which the country must have.
The “2-tier” pricing system ... is expected to stimulate domestic crude oil production while maintaining price controls on oil presently being produced. The “2-tier” system will encourage increased investment in domestic exploration and will provide an economic incentive to allow the recovery of a larger percentage of oil in existing reservoirs.

PX 36.

Not only were the CLC’s twin goals implicit in the regulation, but the unit property rule itself, requiring that each unit be treated as a single property, inhered as well in the regulations when viewed in the context of the surrounding statutory scheme. The 1973 CLC oil price regulations were but a small part of the fourth phase of the economy-wide federal program of price con-, trols to which the oil industry, including Exxon, had long been subject. As such, the CLC regulations carried forth the primary statutory mandate to hold down prices of crude oil by putting a ceiling price on much of domestic production. The CLC’s attempt to boost domestic oil production while keeping prices down could succeed only if production increases were real and not the result of gerrymandering. Even Exxon perceptively noted in its comments to the proposed regulations that one possible result of the two-tier price system could be that a producer’s “strongest incentive would be to obtain higher prices by arranging production in such a way as to shift oil into the ‘new’ category to the maximum extent possible.” PX 32 at 9. The unit property rule was implicit in the regulation because, as the TECA has already found, it was dictated by the CLC’s “duty to reasonably inhibit gerrymandering of boundaries undertaken to avoid price controls.” Pennzoil Co. v. DOE, supra, 680 F.2d at 169.

The explicit agency pronouncements as to the basis and purpose of the August 1973 oil price regulations not only satisfy the requirements of a concise, general statement, but surpass that requirement insofar as the regulations’ basis and purpose were clear from the regulations themselves and hence in need of little further explication.

Accordingly, the court finds that the August 1973 CLC oil price regulations were issued in accordance with all the applicable procedural requirements of the APA.

B. Substantive validity

1. Stripper well exemption

In the first of several attacks on the substantive validity of the unit property rule, Exxon argues that to require a unit containing stripper well leases to be treated as a single property is unlawful because to do so would contravene the intent of Congress when it exempted stripper well oil from price controls. In support of its argument Exxon first traces the evolution of the stripper well exemption through its several manifestations, from its original enactment in the mid-November 1973 Trans-Alaska Pipeline Authorization Act (“TA-PAA”), Pub.L. No. 93-153, § 406, 87 Stat. 576, 590, its virtually identical reenactment only days thereafter in the EPAA in late November 1973, the brief subjection of stripper well oil to upper-tier ceiling prices as mandated by the EPCA in December 1975, and the final return of stripper well production to exemption in August 1976 under the Energy Conservation and Production Act (“ECPA”), Pub.L. No. 94-385, § 121, 90 Stat. 1125, 1132-33, 15 U.S.C. § 757(i). Exempt production was originally defined in Section 406 of the TAPAA as crude oil “produced from any lease whose average daily production of such substances for the preceding calendar month does not exceed ten barrels per well.” The original CLC regulation in November 1973 implementing the exemption defined “stripper well lease” as

a “property” whose average daily production of crude oil petroleum, and petroleum condensates, including natural gas liquids, per well did not exceed 10 barrels per day during the preceding calendar month.

38 Fed.Reg. 32,494, 32,495 (1973); 6 C.F.R. § 150.54(s)(2). “Property” was in turn defined as

the right which arises from a lease in existence in 1972 or from a fee interest to produce domestic crude petroleum in existence in 1972 and is coextensive with that property used in § 150.354(b) [later § 212.72] for purposes of determining “base production control level.”

38 Fed.Reg. at 32,495 (1973); 6 C.F.R. § 150.54(s)(2).

The issue before the court is to determine the proper method to account for production from individual stripper well leases which, prior to February 1976, joined with other non-stripper tracts to form an enhanced recovery unit such as the Hawkins Field Unit. The DOE maintains that upon unitization individual stripper well leases lost their exempt status and that the “property” for purposes of applying the stripper well exemption becomes the unit rather than the individual lease. In other words, according to the DOE, the stripper well exemption applies to production from units formed prior to February 1976 only if average production per well for the unit as a whole is under ten barrels per day.

Exxon disputes DOE’s interpretation and argues that even if a unit BPCL is applied for the purposes of calculating amounts of new and old oil, those particular constituent properties which before unitization qualified as stripper well leases must continue after unitization to enjoy their exempt status. The DOE interpretation, says Exxon, is contrary to the plain language and underlying purpose of the several federal statutes providing special treatment to stripper well production, as well as inconsistent with the DOE’s own implementing regulations.

In support of its own interpretation, Exxon first points to the language in Section 406 of the TAPAA, reiterated in Section 4(e)(2) of the EPAA, which exempted production “from any lease whose average daily production ... does not exceed ten barrels per well . .. . ” (emphasis added). The original implementing regulations defined “stripper well lease” in terms of “property” which was in turn defined as “the right which arises from a lease in existence in 1972 or from a fee interest ... in existence in 1972.” 38 Fed.Reg. at 32,495 (1973) (emphasis added). The FEA later gave added protection to strippers when it promulgated the “Gypsy Rose Lee Rule,” a “once-a-stripper-always-a-stripper” policy under which a stripper well property, once qualified, would always retain its exempt status even if average daily production thereafter exceeded ten barrels. 10 C.F.R. § 210.32; 40 Fed.Reg. 22,123, 22,124 (1975). The intent of Congress, argues Exxon, made explicit in the regulations, was to accord special treatment to stripper well leases, to be preserved through lease-by-lease accounting after unitization, so that production would be maintained at these marginal properties. To allow the stripper well exemption to be swallowed up and lost upon unitization, Exxon contends, would contravene that Congressional intent.

To accept Exxon’s interpretation of the stripper well exemption would greatly overstate its reach and would accord it an importance, above all other competing Congressional purposes, far beyond Congress’s intent. The limited purpose of the exemption was, as Exxon correctly states, to maintain production at marginal properties, operation of which would not otherwise be economically feasible. See Francis Oil & Gas Co. v. Exxon Corp., 687 F.2d 484, 485 (Em.App.1982). Still, Congress recognized the enormous potential for abuse of the exemption and consequently gave the FEA broad powers to make rules to limit such abuse. As the TECA wrote in the leading case interpreting the stripper well exemption, “[t]he exemption benefits to well operators to have their leases declared ‘stripper well’ was an enormous incentive for manipulation of the exemption. The President and Congress vested with the FEA broad authority to prevent such abuses.” In re DOE Stripper Well Exemption Litigation, 690 F.2d 1375, 1386 (Em.App.1982). That court quoted extensively from the Conference Report accompanying the TAPAA:

The Congress intends that the provisions of this section will be strictly enforced and regulated by the administering agency to insure that the limited exemption of this class of wells for the express purposes described above is not in any way broadened.... The Conferees expect the administering agency ... to provide by regulation safeguards against the manipulation of gerrymandering of lease units in a manner that evades the price control and allocation programs.
These regulations shall be so designed as to provide safeguards against any abuse, over-reaching or altering of normal patterns of operations to achieve a benefit under this section which would not otherwise be available.... The sole purpose and objective of this Section 406 is to keep stripper wells — those producing less than ten barrels per day — in production. ... It is not intended to confer any benefit on the owners and operators of wells producing in excess of ten barrels per day.

Id. at 1387 quoting H.R.Rep. No. 624, 93d Cong., 1st Sess. 30 (1973), (emphasis added), U.S.Code Cong. & Admin.News, p. 2417.

The legislative history of the TAPAA makes unmistakably clear the very narrow scope of the stripper well exemption and the broad authority vested in the FEA to prevent its abuse. To allow individual stripper well leases to keep their exempt status after unitization, after enhanced recovery efforts could shift oil production across lease lines and distort production patterns, would result in “an exemption which would have an impact far in excess of that ever contemplated by Congress.” In re DOE Stripper Well Exemption Litigation, supra, at 1388. To be sure, a primary concern of Congress expressed in the TA-PAA Conference Report was that existing lease lines would be gerrymandered “to average down high production wells with a number of low production stripper wells to remove the high production wells from price ceilings.” H.R.Rep. No. 624, 93d Cong., 1st Sess. 30 (1973), U.S.Code Cong. & Admin.News, p. 2532. Congress’s underlying purpose of preventing any “altering of normal patterns of operations to achieve a benefit under this section which would not otherwise be available”, id., applies equally, however, to shifts of production across lease lines underground after unitization as it does to shifts of the lease lines themselves. Were the FEA to have adopted Exxon’s interpretation, it would have ignored its statutory duty “to prevent manipulation of lease units in a manner that evades the price control and allocation programs.” In re DOE Stripper Well Exemption Litigation, supra at 1381. Application of the unit property rule to the stripper well lease exemption is a proper balancing of Congressional aims, see Pennzoil Co. v. DOE, supra, 680 F.2d at 169, and is consistent with “the prevailing view that a unit forms a single property for the purposes of calculating the various regulatory classifications in the federal petroleum pricing schemes”, Francis Oil & Gas Co. v. Exxon Corp., supra, 687 F.2d at 488, including the classification of stripper well oil.

2. The production incentive objective of the two-tier pricing structure

In several different ways Exxon argues that DOE, in its singleminded pursuit of the objective of controlling prices, ignored or even frustrated Congressional desires to spur increased production. Citing contemporaneous statements by various agency employees, Exxon maintains that the overriding purpose of the two-tier oil 'pricing structure, from its inception in August 1973 pursuant to the ESA, through its successive rebirths pursuant to the EPAA and the EPCA, was. to provide incentives to the oil industry to increase domestic crude oil production. The unit property rule, Exxon contends, is arbitrary and cápricious, without rational basis, and in excess of statutory authority, because it contravenes Congressional intent in two ways.

First, and in particular, Exxon claims that the effect of the unit property rule in discouraging unitization is contrary to several of the objectives of the EPAA specifically enumerated by Congress, including protection of public health and national security, preservation of an economically sound and competitive petroleum industry, economic efficiency, and minimization of economic distortion. See EPAA § 4(b)(1); 15 U.S.C. § 753(b)(l)._ Second, and more generally, Exxon maintains that the effect of the unit property rule, in erecting insurmountable barriers to unitization and enhanced recovery projects, defeats the purpose of encouraging increased production. Application of the unit property rule to the Hawkins Field Unit, Exxon asserts, would result in the loss, upon unitization, of virtually all of the new and stripper well oil which was being produced from particular constituent properties prior to unitization. As the FEA itself recognized, see n. 8 supra, and as Exxon attempts to show by deposition testimony of Hawkins Field interest owners, see Def.Mem. at 169-175, prospective unit participants who were producers of new and stripper well oil might be reluctant to join the unit if, when their production was averaged with that of other unit participants, it would lose its exempt or upper-tier status.

The court may strike down the unit property rule only if it is arbitrary or capricious. That standard of review requires this court to uphold the unit property rule “if upon consideration of relevant factors, there was no clear error of judgment and there is a rational basis for the conclusions reached by the administrative body.” Grigsby v. DOE, 585 F.2d 1069, 1074 (Em.App.1978). Moreover, it is well-settled that deference is due the interpretations of statutes and implementing regulations by the agency charged with their enforcement. Pasco, Inc. v. FEA, 525 F.2d 1391, 1400 (Em.App.1975). Deference is particularly appropriate when the agency is confronted with the “gargantuan task” of achieving the equitable allocation of crude oil at equitable prices under “recognized emergency conditions.” Id. at 1394. As the TECA has written in Consumers Union of the United States, Inc. v. Sawhill, 525 F.2d 1068 (Em.App.1975):

“[T]he width of administrative authority must be measured in part by the purposes for which it was.conferred.” Nowhere could this oft-repeated rubric be more relevant than where Congress acts in a crisis situation. The Emergency Petroleum Allocation Act is Congress’ response to precisely such a situation.

Id. at 1077 (citations omitted).

Congress knew when it enacted the EPAA that the nine objectives listed therein were not all mutually attainable. In fact, Congress recognized that “in some instances, it may be impossible to satisfy one objective without sacrificing the accomplishment of another.” H.R.Rep. No. 628, 93d Cong., 1st Sess. 12 (1973), U.S.Code Cong. & Admin.News, pp. 2582, 2688. Congress directed only that the EPAA objectives be sought “to the maximum extent practicable”, 15 U.S.C. § 753(b)(1), indicating the need for the agency to balance competing considerations. Consumers Union of the United States v. Sawhill, supra, 525 F.2d at 1073.' The most important balance to be struck, Congress recognized, was the “equitable balance between the sometimes conflicting needs of providing adequate inducement for the production of adequate supply of product and of holding down spiraling consumer costs.” H.R.Rep. No. 628, 93d Cong., 1st Sess. 26 (1973), U.S. Code Cong. & Admin.News, p. 2703.

The particular balance struck by the agency when it promulgated the unit property rule has already been approved by the TECA in Pennzoil Co. v. DOE, supra, 680 F.2d 156 (Em.App.1982). Although the court’s express holding was limited to upholding Ruling 1975-15 as a valid interpretation of the property definition in 10 C.F.R. § 212.72, the court made unmistakably clear its conclusion that the regulation itself was consistent with Congressional intent as expressed in the underlying statutes.

That result, the court found, was dictated by its prior holding in Grigsby v. DOE, supra, 585 F.2d 1069 (Em.App.1979). In Grigsby plaintiff operated a unit, consisting of five previously independent tracts, with one unit well. When that unit well began producing excessive salt water, Grigsby drilled a substitute well in 1974 on another of the constituent tracts. Grigsby’s treatment of all oil from the substitute well as new oil was challenged by the FEA, which applied the unit property rule to insist that prior production from the first well had to be included in the calculation of a unit BPCL from which amounts of new and old oil production at the second well could be determined. The Grigsby court upheld the FEA, stating that “[t]o allow the unit to define the property ... is consistent with both the language of .the definition and the purposes of the Act.” Id. at 1075 (emphasis added).

The facts in the Pennzoil case, involving a field in production in 1972 but which was unitized after 1972 and before February 1976, are more directly on point. On May 1, 1974 the thirty-nine separate tracts of the Walker Creek Field were combined to form a unit and Pennzoil was designated as unit operator. Prior thereto each tract produced separately and had been assigned a separate BPCL. Ten months after unitization Pennzoil began gas injection, but continued nevertheless for another five months, until the issuance of Rule 1975-15, to account for production on a lease-by-lease basis, as it had since the field was unitized. Pennzoil brought suit to challenge the validity of Ruling 1975-15. The TECA held that Ruling 1975-15, which embodied the unit property rule, would, “[ejven in the absence of our prior decisions ... be sustainable as a reasonable interpretation. It is consistent with the language of the property definition. It rationally balanced the objectives of the two-tier pricing structure.” 680 F.2d at 179 (emphasis added).

Exxon’s challenge to the validity of the unit property rule is without merit, fundamentally flawed by the myopia of which it accuses the DOE. Exxon chooses to see only one purpose to the two-tier pricing structure, that of providing production incentives, while ignoring the numerous other objectives which the agency had to consider, including the most fundamental, that of price control. Admittedly, as the agency itself recognized, the unit property rule does create some disincentives to unitization and hence in some measure discourages the extra production which might come from enhanced recovery projects. But as the TECA has repeatedly recognized, the DOE was entrusted by Congress with the task of balancing multiple, conflicting objectives. Pennzoil Co. v. DOE, supra, 680 F.2d at 169. The two-tier price system was set up originally primarily “to halt the inflationary spiral in domestic oil prices.” In re DOE Stripper Well Exemption Litigation, supra, 690 F.2d at 1380. Exxon, in its singleminded emphasis on production incentives, ignores the teaching of the Pennzoil court when it wrote that “Pennzoil’s reading of the definition would disregard the agency’s primary responsibility of balancing objectives and ignore its duty to reasonably inhibit gerrymandering of boundaries undertaken to avoid price controls.” 680 F.2d at 169.

In In re DOE Stripper Well Exemption Litigation, supra, 690 F.2d 1375, the district court invalidated the FEA rule excluding injection wells from the calculation of “average daily production” for the purposes of identifying exempt stripper well properties. The district court found the rule arbitrary and capricious because it was a disincentive to enhanced recovery projects which rely on such injection wells. The TECA reversed. Although the TECA’s holding is not directly applicable to Exxon’s challenge to the unit rule, the language the court used is particularly telling and bears repeating here. The error of the district court, wrote the TECA, and the error of Exxon here, this court would add, was

its total reliance on production incentives. It fails to adequately weigh the other side of the coin. Price controls on oil was the fundamental purpose of the legislation. It is obvious that Congress in no way intended to create an opportunity for mass evasion of those controls.

690 F.2d at 1392.

Similarly here, as the TECA has already found, application of the unit property rule requiring that a unit be considered a single property with a single, aggregated BPCL for the purposes of calculating quantities of new, released, stripper and old oil, is a reasonable balancing of competing Congressional purposes which must be upheld by this court.

C. The February 1976 amendments to the regulations

Although the Pennzoil court clearly upheld the unit property rule of 10 C.F.R. § 212.72, that court expressly declined to consider the effects of later amendments to the oil price regulation on the application of that rule. Effective February 1, 1976, however, the FEA rescinded Ruling 1975-15 ab initio, and declared that operators of units formed both before and after that date need not calculate a unit BPCL until there occurred a “significant alteration in producing patterns.” Moreover, units formed after February 1,1976 could benefit from the newly-created Section 212.75, providing for a more liberal unit BPCL rule, imputed stripper well oil, and, as of September 1, 1976, imputed new oil.

The DOE contends that the Hawkins Field Unit has always been subject to the strict requirements of Section 212.72 alone, namely, that a unit BPCL be established as of the date of unitization. DOE maintains that the rescission of Ruling 1975-15 as to pre-existing units was only a relaxation of enforcement policy, and that with respect to such units the “significant alteration” test serves only as guidance in compliance audits. See Ruling 1977-2, 42 Fed.Reg. 4409, 4415 (1977). Exxon argues that the “significant alterations in producing patterns” test constituted an entirely new regulation, not applicable before September 1, 1976, the effective date of the formal definition of the term. Any attempt to apply it before that date, says Exxon, would constitute unlawful retroactive rulemaking. Exxon further asserts that to deny to preexisting units the benefits of Section 212.75 given to units formed after February 1, 1976 is arbitrary and capricious discrimination.

1. Retroactivity

The DOE’s attempt to characterize its rescission of Ruling 1975-15 as a mere relaxation in enforcement policy cannot withstand scrutiny. The agency’s pronouncements in February 1976 amounted to a completely new, although less strict, interpretation of the property definition in Section 212.72.

That definition of “property” as “the right to produce domestic crude oil from a lease or from a fee interest” had generated some confusion as to its proper application to unitized properties. The FEA eliminated that confusion when, in Ruling 1975-15, it made explicit what was implicit in the regulation itself — the requirement that a unit be treated as a single property. In that Ruling the FEA stated:

[T]he need for comparison of like quantities requires the producer in computing the BPCL to measure and total the individual 1972 monthly production levels for each of the leases that now comprise the unit.

40 Fed.Reg. 40,832 (1975).

Only five months later, however, the agency, in equally clear terms, rescinded that interpretation ab initio. In the preamble to the February 1976 amendments, the agency explained:

Ruling 1975-15 is rescinded ab initio insofar as it requires producers of unitized properties to total all the BPCL’s of the participating leases and to treat the unit as a single property, before such time as there has been a significant alteration in pre-unitized producing patterns of the individual leases.

41 Fed.Reg. at 4937. Nowhere in the preamble is there any hint that the agency intended the rescission of the strict unit property rule embodied in Ruling 1975-15 to be merely a relaxation of enforcement policy as applied to pre-existing units. Indeed, when the agency intended such a discriminatory result, it stated its aim clearly. For example, it established the special unit BPCL rule of Section 212.75 “[f]or units established later in 1976, or thereafter.” 41 Fed.Reg. at 4938 (1976). However, it rescinded Ruling 1975-15 not prospectively alone, but ab initio. In other words, it was as if that interpretation had never existed.

To conclude, however, that the significant alterations test, finally defined effective September 1, 1976, constituted a new interpretation of Section 212.72 does not preclude its application before that date. The fundamental criterion for determining whether a statute, regulation or interpretation may be applied retroactively is one of reasonableness. Pennzoil Co. v. DOE, supra, 680 F.2d at 175. Generally speaking, “ ‘retroactive rules are valid if they are reasonable, but are invalid if their retroactivity is unreasonable in the circumstances.’ ” Id., quoting 2 K. Davis, Administrative Law Treatise § 7.23, at 109 (2d ed. 1979). The court must weigh the mischief which might follow if the rule is denied retroactive effect, thereby producing a result contrary to statutory design or legal and equitable principles, against the ill effect of retroactive application of the new rule. Pennzoil Co. v. DOE, supra, 680 F.2d at 175. Among the factors weighing in the balance are the extent to which a party has relied on previously settled law and the burden which the retroactive rule would impose on a party. Id.

Brief reflection on the factors cited reveals the fatal flaw of Exxon’s argument that the significant alterations test cannot be applied retroactively. Courts need concern themselves with possible injury to a party, and might hesitate to apply a rule retroactively, only if the new rule is stricter than the standard on which the party relied in the past. Exxon, however, suffered no injury from retroactive application of the new interpretation, because the significant alterations test was less stringent than the rule it replaced. Under Ruling 1975-15, the unit property rule required that a unit BPCL be established as of the legally effective date of the unitization agreement. The new interpretation, adopted in February 1976, allowed a producer to postpone establishing a unit BPCL and to continue lease-by-lease accounting until production patterns had been significantly altered, perhaps months or even years later. In Pennzoil Co. v. DOE, supra, the TECA found that retroactive application of Ruling 1975-15 involved no unfairness because it simply clarified uncertain law, making explicit what was implicit in the underlying property regulation. 680 F.2d at 176. If the retroactive application of that strict requirement, that a unit BPCL be calculated as of the date of unitization, involved no unfairness, then surely the retroactive relaxation of that standard cannot be unfair.

2. Discrimination between units formed before and after February 1, 1976

Exxon argues that, fairly read, Section 212.75, including its beneficial provisions for a special unit BPCL rule and imputed stripper well and new oil, applies generally to all units regardless of the date on which they were formed. In the alternative, Exxon argues that DOE’s denial of the benefits of Section 212.75 to units formed before February 1, 1976 arbitrarily discriminates between similarly situated parties without explanation.

Exxon’s first argument is mistaken. Exxon apparently would like this court to interpret the regulations to conform with Exxon’s practices: that Section 212.75 applies in its entirety to all units, including pre-existing units such as the Hawkins Field Unit, but it applies only after September 1,1976. That, of course, is not what the agency intended. As the FEA spelled out in the preamble to the February 1976 amendments, describing Section 212.75, “[f]or units established later in 1976 or thereafter ... a special rule for unitized properties was proposed for comment and is adopted today.” 41 Fed.Reg. at 4938. In the same preamble the agency spoke of problems faced by a “potential unit”, id., and of eliminating “any significant disincentive to the prospective unitization of properties.” Id. (emphasis added). The TECA in Pennzoil recognized the solely prospective character of Section 212.75 when it described its “special provisions for units formed after the effective date of the regulations, including definitions of a unit and a unit BPCL, new rules concerning stripper well production and imputed crude oil.” 680 F.2d at 164 n. 13 (emphasis added). Exxon itself properly understood Section 212.75 at the time it was issued to apply only to units formed after February 1,1976. In its comments to the proposed rule which would become Section 212.75, Exxon wrote:

Although most disincentives for units formed after February 1, 1976 have been removed by the new regulations, it is still necessary to remove the penalties and disincentives imposed by Ruling 1975-15 examples on units formed between 1973 and January 31, 1976 in order to ensure that these units are maintained in existence. These disincentives [to] past units could be removed by an addition to the proposed new regulations. This addition would apply to units formed from January 1,1973 to January 31,1976 and would make available to them the same measure of relief that the regulation provides for units formed on or after February 1, 1976.

PX 188, Appendix 11 at 2-3.

In sum, as the agency made clear and as Exxon understood, Section 212.75 applied prospectively only. The issue before the court, therefore, is not whether the court will heed Exxon’s plea to rewrite Section 212.75, but whether that rule, with its avowed discriminatory effect of providing certain incentives for the creation of new units, while denying those benefits to existing units, should be struck down.

As the court has already noted, deference is due the FEA as “the agency entrusted by Congress to balance multiple objectives in the administration of relevant statutes,” Pennzoil Co. v. DOE, supra, 680 F.2d at 169, and its rules must be upheld unless they are arbitrary or capricious. The FEA promulgated the February 1976 amendments to the oil price regulation, including Section 212.75, pursuant to the direction of Congress in the EPCA that it amend the regulation to • provide incentives for increased domestic crude oil production while at the same time maintaining firm control of crude oil prices. EPCA § 401(a). Although Congress explicitly mandated measures to spur domestic production, it underscored its concern with price control by directing that the agency could allow no increase in the price of old oil above the existing ceiling unless it expressly found that the increase would encourage enhanced recovery projects and would likely result in production greater than would have otherwise occurred. EPCA § 401(a), 15 U.S.C. § 757(b)(2); see also n. 9, supra.

Working within the narrow constraints imposed by Congress, the FEA reasonably balanced the competing aims of increased production and price control by extending the most favorable incentives to new units. Indeed, the FEA could not have treated all units alike, whenever formed. Had the FEA allowed all units, including the Hawkins Field, to benefit from the favorable provisions of Section 212.75, it would have violated the EPCA directive that no old oil be reclassified as higher-price oil unless it would not have otherwise been produced. The owners of the properties comprising pre-existing units such as the Hawkins Field Unit made their economic decision to unitize and to pursue enhanced recovery efforts long before February 1976. Any further inducement to them would have produced no additional oil that they had not already decided was worth producing. They could not be encouraged to do what they had already done. As Exxon admits, “of course, since pre-February 1976 units had already been established when the imputed new and imputed stripper lease rules were promulgated, the new rules could have had no incentive effect on the formation of these projects.” Def.Mem. at 137 (emphasis added).

Exxon complains, however, that the benefits of Section 212.75 should have been provided to pre-existing units as well in order to prevent their dissolution. But Exxon here seeks to wage the battle it lost when Section 212.75 was promulgated. In its comments to the proposed rule, Exxon conceded that proposed Section 212.75 removed most disincentives to prospective unitization, but urged that its reach be broadened to include units formed before February 1976 “to ensure that these units are maintained in existence.” PX 188, Appendix 11 at 2. The agency did in fact show its concern with the maintenance of existing units when, in its notice of proposed rule-making, it “requested] comments on the extent to which the establishment of a more recent BPCL will operate to maintain units in existence which were formed between 1973 and 1976.” 41 Fed.Reg. at 1571. But the agency concluded, after review of the comments, that the limited incentives it provided to pre-existing units were sufficient. The extension of the revised 1975 BPCL to existing units, combined with the retroactive rescission of Ruling 1975-15, “eliminate[d] the most significant disincentives that producers had faced under the prior regulations.” 41 Fed.Reg. at 4938 (1976). In refusing to go further and to extend greater benefits to pre-existing units the agency performed precisely the delicate weighing of competing statutory objectives with which Congress had entrusted it and to which judicial deference is due. Indeed, the agency could not have extended all the benefits of Section 212.75 to pre-existing units without violating the directives of the EPCA. Discriminatory treatment by the FEA of prospective and existing units was therefore not arbitrary or capricious; on the contrary, it was a reasonable balancing of the conflicting policy objectives of increased crude oil production and price control.

D. Significant alteration in producing patterns

Effective September 1, 1976 the FEA defined “significant alteration in producing patterns” as “the occurrence of either (1) the application of extraneous energy sources by the injection of liquids or gases into the reservoir, or (2) the increase of production allowables for any property that constitutes the unitized property.” 41 Fed.Reg. 36,172; 36,184 (1976). DOE contends that on the peculiar facts of this case, the significant alterations test affords Exxon no relief from the strict unit property rule of Ruling 1975-15, because there was both an increase in production allowables at constituent leases and gas injection at the Hawkins Field on January 1, 1975, the day the field was unitized. Exxon counters that the question of whether any alteration of producing patterns was “significant” is a question of fact, requiring expert testimony by petroleum engineers, which the court may not resolve on summary judgment. In any event, continues Exxon, no significant alteration occurred at the Hawkins Field before March 1977, when the inert gas plant began operation. In fact, according to Exxon, no truly significant alteration occurred until the injection of inert gas stabilized reservoir pressure and altered the reservoir’s underground drive mechanisms, sometime in 1979.

In effect, Exxon condemns the definition of significant alteration as too harsh and inflexible and again invites the court to rewrite the regulation in Exxon’s favor. But again Exxon miscasts the issue. Although the court may reasonably interpret any ambiguity which might arise from application of the regulation, the court is without power to substitute its own or Exxon’s ideas as to how the agency should have defined significant alteration in producing patterns. At most, the court could invalidate the rule if it were fatally inconsistent with applicable statutes.

But it is not. Rather than rely on hard to decipher underground phenomena, the agency based its definition on events readily observable by agency auditors. This clear, easily administered test was not only consistent with, but was required by, applicable statutes. In the EPCA the Congress directed the FEA, in drafting the February 1976 amendments, to establish standards that, while balancing the goals of price control and production incentives, would be readily enforceable. Congress required the agency to determine that the classifications of oil it would establish were “administratively feasible.” EPCA § 401(a); 15 U.S.C. § 757(b)(1)(A). The term “administratively feasible”, according to the Conference Committee, meant “a workable pricing program which is both fully enforceable under section 5 and compatible with achieving the policy objectives set forth in Section 4(b)(1) of the Emergency Petroleum Allocation Act.” S.Rep. No. 516, 94th Cong., 1st Sess. 191 (1975), U.S.Code Cong. & Admin.News, p. 2033.

The comments the agency considered when it devised the significant alteration test “indicated the difficulty associated with attempting to develop a workable standard for determining the point at which production patterns have been significantly altered.” 41 Fed.Reg. at 36,181. Proposals ranged broadly, including requiring a unit BPCL as of the date of unitization, allowing producers the option to continue lease-by-lease accounting until injection occurred, allowing the option for two years, or finally, allowing the option indefinitely. Id. The definition the agency finally settled on was designed to enable the agency adequately to police the oil industry to ensure effective price control, while at the same time affording “maximum flexibility to producers seeking to form and maintain unitized properties,” id. at 36,182, in order to remove the disincentives to unitization targeted by the EPCA.

Agency emphasis upon administrable standards, demanded by Congress, has consistently been upheld by the TECA. For example, in Sauder v. DOE, supra, 648 F.2d 1341, Congress directed the FEA, in drafting the stripper well exemption, to provide appropriate limitations to the definition of the exempt stripper lease “to insure that an administratively workable system is established which does not permit abuse.” Id. at 1346, quoting H.R.Rep. No. 624, 93d Cong., 1st Sess. 31 (1973), U.S.Code Cong. & Admin.News, p. 2533; see also In re DOE Stripper Well Exemption Litigation, supra, 690 F.2d at 1387. Without a formal unitization agreement, Sauder and five other working interest owners cooperatively produced oil from three separate properties overlaying a single reservoir. Alleging a de facto unitization, Sauder claimed the stripper well exemption for production from all three properties. Treating the properties separately, the DOE disallowed the claim for two of the three. The court upheld the agency’s insistence on a formal unitization agreement as “consistent with Congress’ direction that the agency devise ‘an administratively workable system’ that avoids abuse of the exemption, and does not exceed the agency’s authority.” 648 F.2d at 1346. The court explained: “Equitable pricing is one of the important objectives of the UPAA, ‘and this objective cannot be bogged down in an administrative quagmire.’ ” Id. at 1348, quoting Tenneco Oil Co. v. Federal Power Commission, 442 F.2d 489, 497 (5th Cir.1971).

Similarly here, the agency’s decision to define significant alteration in producing patterns in terms of easily observable events is consistent with the intent of Congress that administration of price controls be workable and effective. The FEA with its limited resources could not afford to satisfy Exxon’s desire that the agency send droves of petroleum engineers to the Hawkins Field to conduct elaborate tests to examine the field’s underground drive mechanism. That is precisely the “quagmire” that the agency had to avoid. The agency described its limitations in another context, when it explained its initial rejection of the proposal that separate reservoirs underlying a single tract be treated as separate “properties” for purposes of accounting for upper and lower-tier oil production.

[T]he January 8 proposal was not adopted primarily because FEA concluded that it would be infeasible to attempt to administer a program under which FEA could not require easily understandable records from which could be determined the limits of each producing property. FEA has neither the expertise nor the resources required to monitor reservoir-by-reservoir production, and FEA auditors would not have at their disposal adequate means to confirm or deny that production had in fact resulted from two or more separate and distinct producing reservoirs.

41 Fed.Reg. at 36,179. Neither did the FEA have the expertise or resources to judge significant alterations in producing patterns of unitized properties on any basis other than easily observable events.

Even Exxon recognized the value of ease of administration. Commenting on the above-mentioned proposal that separate reservoirs be considered separate properties, Exxon wrote: “We recognize the need for FEA to develop regulations that can be audited.” PX 217 at 6. More to the point, Exxon recognized the need for agency standards based on objective criteria, and not dependent for their enforcement on extensive subjective evaluation. A proposal to limit certain incentives to “bona fide” enhanced recovery units met the rebuke from Exxon that “once a definition is developed, it will present severe administrative problems in certifying and auditing upper-tier production. These problems would make the system very difficult and expensive to administer on the part of both FEA and producing companies.” PX 188, Appendix 3 at 2. Complaining that “[t]here is considerable evidence that the current regulations in total are not administratively workable,” Exxon suggested that “[regulations should rely on precise definitions rather than on a requirement for administrative judgment.” Id.., Appendix 2 at 1.

Indeed, although Exxon now invites the court to substitute just such a subjective test based on administrative judgment, Exxon obviously understood the standard as the agency intended when the test was announced, because Exxon calculated a unit BPCL at the Hawkins Field beginning September 1, 1976 — long before the changes in underground pressure or drive mechanism Exxon would like this court to rely on. As Exxon attorney Fred File then concluded unequivocally: “Inasmuch as the Hawkins unit cannot meet the new tests permitting tract-by-tract computations, it is clear that after September 1, 1976 tract-by-tract computations will no longer be permitted.... It is clear that the new regulations require computation of upper and lower tier oil at Hawkins on a unit basis after September 1, 1976.” PX 236 at 3, 4 (Memorandum from Fred W. File to Fred M. Perkins, October 1, 1976).

Ironically, in drafting the definition of significant alteration in producing patterns, the FEA heeded Exxon’s advice that it rely on precise definitions rather than administrative judgment. One might speculate about other standards, not substantially harder to administer, whose effect would have been to allow greater relief to the Hawkins Field, where interim gas injection, transfer of production allowables and unitization happened to coincide. But “[t]o be upheld, the action taken by the FEA need not be the same as the court or the appellee might have taken in correcting the problems occurring as a result of the energy crisis and the impact of earlier regulations, so long as the action taken is reasonable.” Pasco v. FEA, supra, 525 F.2d at 1400. Gas injection and transfer of production allowables among constituent properties are events commonly associated with shifts in oil production across lease lines. To allow lease-by-lease accounting to continue after such shifts would have enabled unit operators to circumvent oil price controls. To require the agency to adopt a subjective test based on complex geological phenomena would have plunged the agency into an administrative quagmire which would have had the same result. The agency definition of significant alteration was a reasonable effort by the agency to fulfill its “duty to reasonably inhibit gerrymandering of boundaries undertaken to avoid price controls.” Pennzoil Co. v. DOE, supra, 680 F.2d at 169. Accordingly, it must be upheld.

It was clear to Exxon as of September 1, 1976 that the producing patterns at the Hawkins Field had been significantly altered because it was clear as of that date that Exxon had transferred production allowables among constituent leases and that it was injecting gas. And both had in fact occurred on the day the Hawkins Field became a unit, on January 1, 1975.

Prior to unitization the Texas Railroad Commission (“TRRC”) limited the number of barrels of oil — called production “allowables” — each well within the Hawkins Field could produce. When a producer shut in an unproductive well, under TRRC orders that well’s allowables were transferred pro rata among all the other wells in the field. In its order approving the unitization of the Hawkins Field, the TRRC granted the field a unit allowable and in doing so relinquished to Exxon the control of allocating production among the properties comprising the unit. DX Intro 2. The unit allowable permitted Exxon to transfer production from lease to lease at will, without regard to prior limits on production at any lease, provided total unit production did not exceed the unit allowable. In effect, therefore, the TRRC accorded Exxon as of January 1,1975 an increase in production allowables for any property within the Hawkins Field Unit to which Exxon chose to transfer production, and thereby triggered a significant alteration in producing patterns as of January 1, 1975.

Exxon did not wait to take advantage of its new-found freedom as unit operator. In January 1975 Exxon boosted production above prior allowables by almost 320,000 barrels at 65 leases — roughly 10 percent of total unit production at one-quarter of the unit’s properties. See Plaintiff’s Appendix of Charts and Graphs, C-1a. At the same time, production declined by almost an equal amount at 137 other leases. Id at C-lb. Production shifts of increasing magnitude continued throughout the early months of 1975. By shifting production within the unit at will, with only an eye to the unit allowable limit, Exxon effectively “transfer[red] production allowables among participating leases.” See 41 Fed.Reg. at 36,182.

Meanwhile, after unitization Exxon continued — and increased — the injections of natural gas it had begun in 1970. Even if Exxon had only continued to inject natural gas at the rate it had done so before unitization — or even some lesser rate — it would have engaged in “the application of extraneous energy sources by the injection of liquids or gases into the reservoir” — itself a significant alteration in producing patterns. 41 Fed.Reg. at 36,184 But Exxon in fact substantially increased gas injection after unitization. In its 1969 approval of Exxon’s interim plan, the TRRC authorized the injection of an average of 20 million cubic feet of natural gas per day. But when it approved the unitization of the Hawkins Field, the TRRC removed that limit. Accordingly, Exxon injected 28.2 mcf per day in January 1975 — 40 percent more than a year earlier. PX 177. Indeed, Exxon increased injections thereafter until by the fall of 1975 it was injecting more than twice as much gas as a year before. Id. Over all, in the first ten months of 1975 Exxon injected an average 36.5 mcf per day — almost an eighty percent increase over the same period in 1974. Id. Comparing totals for the years 1972 through 1975 reveals the same clear jump after unitization. Although between 1972 and 1975 increases averaged only 5 percent annually, total gas injections at the Hawkins Field in Í975 leaped 82 percent, from 7,652,916 mcf in 1974 to 13,945,000 mcf in 1975, with the 1975 total more than double the amount for 1972. See PX 210 at 2, 5; PX 109 at 2.

Accordingly, under either prong of the regulatory definition — an increase in production allowables at any constituent property, or gas injection — a significant alteration in producing patterns occurred at the Hawkins Field on January 1, 1975, and on that date Exxon’s obligation to calculate a unit BPCL and to account for oil production at the Hawkins Field on a unit-wide basis accrued.

III. Estoppel

Exxon argues that the government is estopped from now challenging the legality of Exxon’s lease-by-lease accounting practices at the Hawkins Field Unit. According to Exxon, the decision by it and the other Hawkins Field interest owners to unitize, as well as the decision to establish and maintain the practice of accounting for new and old oil production on an individual lease basis, were both made in reasonable reliance on repeated agency assurances to Exxon and others that such practices were allowable under the regulations. DOE replies that as a matter of law the government may never be estopped on the basis of unauthorized statements by government officials. In any event, DOE continues, Exxon cannot prove reasonable reliance, an essential element of the estoppel defense.

Exxon’s estoppel defense must fail because the undisputed facts in this case demonstrate that Exxon’s reliance, if any, on unauthorized informal statements by agency employees, was not reasonable. To begin with, Exxon can point to no agency pronouncement prior to January 1,1975, the date by which Exxon obviously had made its decision to apply lease-by-lease accounting, directed to Exxon or to the oil industry generally, which condoned such accounting practices. Instead, Exxon cites meetings held by James Langdon, Associate Assistant Administrator of the FEA, in March 1974 with Austral Oil Company and in July 1974 with Pennzoil Company, at which Langdon reportedly stated that no formal, written agency interpretations of the property regulation would be forthcoming, but that lease-by-lease accounting was acceptable. Exxon asserts both Austral and Pennzoil immediately informed it of the substance of Langdon’s remarks, which formed the basis for its decision to alter its prior practices and adopt individual lease accounting at the Hawkins Field. But the second-hand recounting of remarks by an agency employee cannot support a defense of estoppel. The party to be estopped must have intended that his assertions be acted upon by the party raising the defense, or must act so that that party coiild reasonably believe it is so intended. United States v. Ruby Co., 588 F.2d 697, 703 (9th Cir.1978), cert. denied, 442 U.S. 917, 99 S.Ct. 2838, 61 L.Ed.2d 284 (1979). Even assuming arguendo that Langdon’s views might be considered official and binding on the agency, he cannot' have intended or understood that in speaking with Austral and Pennzoil he would lead Exxon astray.

Admittedly, certain agency employees did later make statements, directly to Exxon or to the industry generally, which could be interpreted as condoning lease-by-leasé accounting. For example, in February 1975 Langdon delivered a paper at a conference in which he illustrated his explanation of the effect of the regulations • with an example plainly implying that lease-by-lease accounting was proper. But Lang-don’s paper, the earliest direct statement cited by Exxon, came only long after the decision to apply lease-by-lease accounting at the Hawkins Field had been made, and therefore cannot have been a basis for that decision. Nor could Exxon reasonably rely on that statement, or others like it, as a basis for what it describes as its ongoing decision to maintain lease-by-lease accounting, for Exxon conveniently ignored a flurry of contemporaneous agency pronouncements to the contrary. Most important of these, as noted by TECA in Pennzoil Co. v. DOE, supra, 680 F.2d at 171, were the five official Interpretations issued by the FEA Office of General Counsel in the months preceding Ruling 1975-15 which reiterated the rule that a unit be treated as a single property. And Ruling 1975-15 itself completely dispelled any confusion Exxon may have had as to the regulations’ meaning. Nevertheless, Exxon doggedly persisted, even in the face of the pellucid dictates of Ruling 1975-15, in applying individual lease accounting at the Hawkins Field Surely a regulated party as sophisticated as Exxon which ignores the only existing official pronouncements cannot be said to be reasonable when it follows instead those unauthorized views of agency employees ferretted out by Exxon which happen to coincide with Exxon’s self-interest. The expression of those views should at most have served to raise a question in the minds of Exxon managers; in no event could those managers reasonably rely thereon, given the weight of official opinion to the contrary. The unauthorized statements contrary to official agency pronouncements had neither the force nor the tenor which could give Exxon solace, but were instead, in the words of Judge Jameson in Pennzoil, “an invitation to seek advice and a warning that if it did not do so it was proceeding at its own peril.” 680 F.2d at 181 (Jameson, J., concurring). As Exxon well knew, only an official interpretation could provide it with the assurance it supposedly sought. Id. at 179. But Exxon chose never even to seek an official written interpretation. Though Exxon now insists that such a request would have been futile, its studied inaction at that critical time of its purported confusion belies any claim of reasonable reliance. Exxon, like Pennzoil, “knowingly proceeded at its own peril when it relied on conflicting informal opinions it received as to the proper interpretation of § 212.72.” Id. at 182 (Jameson, J. concurring).

Finally, even if Exxon were able to demonstrate reasonable reliance this would still not be a proper case in which to invoke estoppel of the government. DOE correctly states the longstanding principle that the courts look with extreme disfavor upon estoppel of the government on the basis of unauthorized statements by its employees. See, e.g., Goldberg v. Weinberger, 546 F.2d 477, 481 (2d Cir.1976) (“The government could scarcely function if it were bound by its employees’ unauthorized representations.’’). To be sure, that rule is no longer so hard and fast as DOE portrays it. Dicta in a few Supreme Court cases have led courts in some circuits to erode that principle somewhat and, in certain limited circumstances, to allow the government to be estopped. But even those courts which have gone furthest in limiting the traditional rule have recognized that a court should estop the government from exercising its sovereign functions with great reluctance, and only if, after proof of the requisite factual elements, the court finds that on balance the injury to the private party in the absence of estoppel would be so egregious as to outweigh the public interest in the enforcement of the law. For example, the Ninth Circuit wrote in United States v. Lazy FC Ranch, 481 F.2d 985, 989 (9th Cir.1973) that “although we may be more reluctant to estop the government when it is acting in [its sovereign] capacity,” nevertheless “estoppel is available as a defense against the government if the government’s wrongful conduct threatens to work a serious injustice and if the public’s interest would not be unduly damaged by the imposition of estoppel.” Other courts have held that, in deciding whether to estop the government, courts must consider, in addition to the five traditional elements of estoppel, the type of government activity being pursued and the danger of undermining important federal interests if estoppel were imposed, Portmann v. United States, 674 F.2d 1155, 1167 (7th Cir.1982) or, stated differently, courts must “balance the equities in each individual case.” Santiago v. Immigration and Naturalization Service, 526 F.2d 488, 494 (9th Cir.1975) (Choy, J., concurring and dissenting). Even applying these most liberal standards, the balance weighs against Exxon. The government’s case against Exxon is a major effort to enforce urgent Congressional mandates to pursue the important national policy objectives of controlling domestic crude oil prices. To estop the DOE would not only frustrate those important objectives but would allow Exxon unjustly to reap huge profits from its dubious exploration of the limits of regulatory tolerance. As the TECA described Pennzoil, Exxon was

hardly an innocent abroad interpreting in the midst of confusing babble a direction sign labeled in a foreign language. It was an experienced traveler on familiar terrain perceptively advised by its own counsel in its own interest, and deviating from the plainly indicated direction it had theretofore followed.

680 F.2d at 179. As that same court noted, in much more sympathetic cases of impoverished Social Security claimants misled by the unequivocal misstatements of government agents, and thereby deprived of essential benefits, the Supreme Court has declined to allow estoppel against the government. Id. at 176-77. A fortiori, estoppel may not lie in this case “in favor of sophisticated oil operators exploring the possibility of dubious regulatory leeway without even requesting an official interpretation” Id. at 177.

IV. Remedy

The court has held that Exxon’s obligation to establish a unit BPCL and to account on a unit-wide basis for upper and lower tier oil production at the Hawkins Field accrued on January 1, 1975. It remains for the court to determine the amount of the overcharges and to fashion an equitable remedy.

Section 209 of the Economic Stabilization Act, 12 U.S.C. § 1904 note, incorporated in Section 5(a)(1) of the EPAA, calls for violators of the oil price regulations to make restitution of overcharges. By comparing Exxon’s actual accounting practices at the Hawkins Field with those Exxon should have applied, DOE has calculated the total overcharges by Exxon between January 1, 1975 and January 27, 1981, when oil prices were decontrolled, in the amount of over $895 million. DOE insists that Exxon, which owned about two-thirds of the field’s production, was the driving force which controlled production and accounting practices at the Hawkins Field Unit and should therefore be held responsible for all the overcharges. Reimbursement of the overcharges to purchasers of Exxon’s improperly classified crude oil is impracticable, according to DOE. Due to the pervasive reach of oil price regulation at the time these overcharges occurred, DOE contends that the overcharges worked their way throughout the economy nationwide to the millions of ultimate consumers of petroleum products. Any attempt to determine actual injury to particular purchasers would be impossibly complicated. Consequently, DOE asks the court instead to order payment of the amount of overcharges, with interest, into the United States Treasury. Finally, in order to deter future regulatory violations, DOE asks the court to assess civil penalties against Exxon in the amount of $38.27 million.

A. Restitution

Exxon vigorously contests the government’s proposed remedy. Disputing its role as the animating force at the Hawkins Field, Exxon argues that under the terms of the Unit Agreement each Hawkins Field interest owner takes its share of production in kind and independently determines the price at which to sell the oil. Exxon’s description of itself as just another interest owner is disingenuous. Exxon was the prime mover and animating force behind the formation and operation of the Hawkins Field Unit and, under the rule of Sauder v. DOE, supra, 648 F.2d 1341, Exxon may be held responsible for all overcharges at the field.

In Sauder plaintiff owned a 34 percent and 41 percent interest, respectively, in two properties whose production he improperly claimed to be exempt stripper well oil. Sauder’s was by far the largest single holding of the six working interest owners. He was the sole operator of the leases and it was he who improperly certified to purchasers that the production was exempt stripper oil. The TECA found that Sauder was the “animating force” behind production from the leases and could therefore “fairly be said [to have] caused the overcharges.” Id. at 1347. The TECA held that, in those circumstances, it was within the discretion of the district court to hold Sauder liable for the full amount of the overcharges. Id. at 1347-48. To require the agency to seek refunds from each individual owner, the court reasoned, would create intolerable administrative obstacles to enforcement of price controls. Id. at 1348.

In stating its rationale of administrative workability, the Sauder court relied on Tenneco Oil Co. v. Federal Power Commission, 442 F.2d 489 (5th Cir.1971), where the Fifth Circuit upheld a Federal Power Commission order requiring Tenneco to refund all excess charges for natural gas made to Tenneco as well as to Tenneco’s six co-owners or predecessors in interest at a particular field. The TECA in Sauder explained that the '’Fifth Circuit’s reasoning, “to hold the central figure responsible for refunding the overcharges is necessary to effective enforcement,” applied equally to violations of the crude oil price regulations. 648 F.2d at 1348. The Sauder court wrote: “Equitable pricing is one of the important objectives of the Emergency Petroleum Allocation Act, ‘and this objective cannot be bogged down in an administrative quagmire.’ ” Id., quoting Tenneco Oil Co. v. Federal Power Commission, supra, 442 F.2d at 497.

Moreover, the TECA in Sauder found, shifting the burden to a central figure such as Sauder aided in the task of enforcement without working any unfairness against him. 648 F.2d at 1348. To the extent that other interest owners had shared the illegal profits, the court suggested Sauder could recover from them by applying their share of future lease revenue to repayment of the overcharges. Id. at 1349.

The factual basis for holding Exxon responsible for the full amount of the overcharges at the Hawkins Field is even stronger than in Sauder. Throughout the relevant period Exxon’s working interest at Hawkins ranged between 76 and 80 percent; its share of unit production, when including royalty interest owners, was about two-thirds. PX 92 at 1-2; PX 108 at 31. Exxon was the animating force behind formation of the Hawkins Field Unit, having begun to promote it as early as 1969. Def.Opp. at 6. Exxon sought and received permission in 1969 to inject natural gas into the field, which it began the following year. PX 4 at 4. Exxon was the animating force behind operation of the unit. The Unit Agreement named Exxon sole operator. DX Intro-4. As operator, Exxon chose the wells to shut-in, the wells where production was to go up or down, where to inject gas, and how much. PX 94; PX 121. Most important, Exxon decided how the unit would account for upper and lower tier oil, first in 1974, before the field was legally unitized, PX 85 at 11, later after Ruling 1975-15 was issued, PX 145, and finally when it switched to a unit BPCL under Section 212.75 in September 1976. PX 141. Accordingly, Exxon may “fairly be said [to have] caused the overcharges.” Sauder v. DOE, supra, 648 F.2d at 1347.

Moreover, the administrative burden of requiring the agency to recover funds from each of the Hawkins Field Unit owners would be many times the burden found intolerable in Sauder or Tenneco. In contrast to the handful of working interest owners in those two cases, there are more than 200 working interest owners at the Hawkins Field, in addition to the more than 2200 royalty interest owners. To force the agency to act against each individually would plunge the agency into an “administrative quagmire” which would effectively block enforcement of oil price controls at the Hawkins Field.

Finally, Exxon, like Sauder, is not without recourse against the other interest owners, and so imposing full responsibility on Exxon will aid in enforcement of price controls without unfairness to Exxon. When Exxon decided to continue lease-by-lease accounting at the Hawkins Field in the face of Ruling 1975-15, it sought to protect itself by including with its mailing of royalty checks the following warning:

Since FEA regulations prohibit producers from charging or purchasers from paying more than the lawful price for old oil, Exxon must advise you that royalty and other interest owners in the unit may be required to refund excess amounts received for oil heretofore classified as “new crude oil” which the FEA may rule does not qualify for exempt pricing.

PX 145 (Letter from Exxon to Hawkins Field interest owners, October 20,1975). A few months later, weighing the pros and cons of Exxon’s decision to continue lease-by-lease accounting, one Exxon manager noted reassuringly:

Potential losses via overpayments of working and royalty interest owners are minimal since most of these are financially responsible parties, and all payments are backed by reserves.

PX 172 at 2 (Memorandum from O.R. Harrison to C.M. Harrison, Dec. 15,1975). Similarly, after the DOE issued a Notice of Probable Violation in January 1978, Exxon again warned interest owners:

[I]f a remedial order ... should be received, it will probably be necessary for Exxon, pending the outcome of the controversy, to: (a) reduce payments for future production and set up an escrow account for that portion of the settlements in dispute and (b) take action with respect to alleged past overpayments as may be necessary to comply with the remedial order.

PX 246 at 2 (Letter from Exxon to Hawkins Field interest owners, January 26, 1978). Should Exxon turn to the other Hawkins Field interest owners for contribution or indemnification Exxon, like Sauder, could attempt to deduct the other interest owners’ share of the overcharges from future royalty payments.

Exxon attempts to escape liability for the overcharges by arguing first that the oil price regulations simply do not apply to the two-thirds of the Hawkins Field production owned by Exxon. By their terms, says Exxon, the regulations apply only to a “first sale” of domestic crude petroleum. 10 C.F.R. § 212.71. All Exxon-owned production was simply transferred from Exxon’s production division to its refining division. No “sale” ever occurred, therefore the regulations do not apply. In any event, if the court does deem Exxon’s intra-company transfers to be “sales”, Exxon was the first purchaser of all Exxon-owned production, along with virtually all of the remaining production, and therefore Exxon as purchaser is the victim of the overcharges to whom reimbursement is due.

Exxon’s arguments are without merit. The Subpart D regulations, it is true, have always applied only to a “first sale” of domestic crude petroleum. 10 C.F.R. § 212.71. And “first sale” was formally defined by the agency only in February 1976, as follows:

“First sale” means the first transfer for value by the producer or royalty owner. With respect to transfers between affiliated entities, the “first sale” shall be imputed to occur as if in arms-length transactions.

41 Fed.Reg. 4931, 4940 (1976); 10 C.F.R. § 212.72 (1977). Contrary to Exxon’s arguments, however, the February 1976 definition of “first sale”, which clearly brings intra-company transfers within the ambit of the regulation, was not a break from, but rather a confirmation of, past agency application of the term. Official agency Interpretations issued before the February 1976 definition referred to “intra-firm sales.” At the request of the FEA, however, the Congress in the EPCA directed promulgation of the “first sale” definition to clarify the FEA’s already existing authority. As the Conference Report explained:

It is the intention of the conferees that the term “first sale” be defined in the regulations to make clear that it applies to the first transfer of a barrel of crude oil for value in an arms-length transaction. With respect to transactions between affiliated or associated companies, FEA has the authority to impute a transfer value, which bears a reasonable relationship to transfers between unaffiliated persons in arms-length transactions. It is the conferees’ understanding that the regulation defining “first sale” could extend principles and procedures now applicable under current regulations to determine transfer prices for imports as well as the point of sale and sales price of old crude oil and stripper well oil, to all ceiling prices promulgated under the new pricing program.

S.Rep. No. 516, 94th Cong., 1st Sess. at 190 (1975) (emphasis added), U.S.Code Cong. & Admin.News, p. 2032.

That the crude oil price regulations applied to intra-company transfers even before the clarifying amendment is supported by TECA decisions interpreting similar language in analogous rules. In Johnson Oil Co. v. DOE, 690 F.2d 191 (Em.App.1982), a crude oil reseller argued that it should be allowed to charge higher New Item prices, under the Subpart F reseller pricing rules, for crude oil sold during a certain period. In order to reap the benefits of the New Item Rule, the seller could not have sold that item in the preceding year. 10 C.F.R. § 212.111(a)(1). Johnson Oil argued that all its crude oil “transactions” in the year preceding the overcharge period were intrafirm transfers, not “sales”, which it interpreted to mean only arms-length transactions between third parties. The TECA disagreed, holding that “the plain meaning of the rule does not differentiate between sales to affiliated parties . .. and transactions.” 690 F.2d at 197. Cf. Gulf Oil Corp. v. DOE, 671 F.2d 485 (Em.App.1982) (“first sale” of natural gas liquids and natural gas liquid products under Subpart K includes “transfers” by refiners and processors to their affiliated marketers). In the same manner, the plain meaning of “first sale” in 10 C.F.R. § 212.71 includes intra-company transfers of crude oil from production to refining divisions. To hold otherwise would lead to the ludicrous result of allowing integrated oil companies largely to escape crude 011 price regulation, a result plainly not contemplated by Congress.

If the transfers of Hawkins Field crude oil from Exxon as producer to Exxon as refiner are “first sales”, says Exxon, then those sales, along with Exxon’s purchases from the other interest owners of the bulk of the remaining Hawkins Field production, resulted in overcharges suffered by Exxon as refiner, and any refunds should be made to it. But Exxon’s portrayal of itself as victim ignores the workings of the mandatory Entitlements Program which, together with price controls on refiners, resellers, and retailers, allowed Exxon to spread the cost of its Hawkins Field overcharges across the land. The purpose of the Entitlements Program was to permit all refiners to share the financial benefits of the limited available quantity of relatively inexpensive price-controlled crude oil. Under the Entitlements Program, the FEA each month allotted to each refiner a certain number of entitlements, equal to that refiner’s deemed share of the old oil refined nationwide during that month. If a refiner was in fact able to obtain and refine a proportionately large amount of low-priced old oil, greater than its allotted entitlements, that refiner would have to buy entitlements from those less fortunate refiners which refined a proportionately small amount of low-priced oil. The price of an entitlement was roughly the difference between the price of controlled and uncontrolled oil. The effect of the entitlements transfers, therefore, was to equalize the average weighted crude oil costs of all refiners. Union Oil Co. of California v. DOE, 688 F.2d 797, 801-02 (Em. App.1982); Pasco, Inc. v. FEA, supra, 525 F.2d at 1395.

As a result of Exxon’s misclassification, less old oil was reported to the Entitlements Program. DOE therefore issued fewer entitlements to each refiner, and each refiner had to purchase more, or sell fewer, entitlements than it would have if Exxon had properly classified the Hawkins Field oil. Exxon, by improperly classifying old oil as new oil at the Hawkins Field, thereby increased the average cost of crude oil of all refiners. At the same time, although Exxon as refiner appeared initially to bear the burden of the overcharges of Exxon as producer, in fact Exxon was able to keep the ill-gotten gains by improving its entitlements position. It was able to buy fewer, or sell more, entitlements than it had a right to.

Exxon argues that it must be allowed to conduct further discovery to determine if the Entitlements Program in fact operated as it was designed and to trace the Hawkins Field overcharges to their ultimate victims. In effect, Exxon would like to launch a nationwide 'inquiry into the workings of more than 200 domestic refiners during a period of several years. Such an inquiry, whose purpose could only be to postpone Exxon’s day of reckoning, is unnecessary. The cost-spreading effect of the Entitlements Program has long been recognized by the TECA. The purpose of the Entitlements Program was “to spread the benefits of access to old price-controlled oil and the burden of dependence on uncontrolled oil among all sectors of the petroleum industry, all regions of the country, and among all consumers of petroleum products.” Cities Service Co. v. FEA, supra, 529 F.2d 1016, 1021. Just as the program spread the benefit of access to old oil, so too did the program spread the burden of Exxon’s overcharges among all sectors of the petroleum industry, all regions, and all consumers. The TECA faced a closely analogous situation in Union Oil Co. of California v. DOE, supra, 688 F.2d 797, where misclassification of price-controlled old oil as exempt oil

reduced the total amount of crude oil production subject to price controls each month and therefore increased the total cost of the available crude oil supply. As a result, the benefits of price-controlled crude oil which were distributed among all refiners by the Entitlements Program were reduced. Thus, to the extent that crude oil producers sold otherwise price-controlled oil as uncontrolled crude oil ... the higher cost of such uncontrolled crude oil was distributed among all domestic refiners through the operation of the Entitlements Program.

Id. at 802 (emphasis added).

Interestingly, Exxon itself, though it now feigns surprise and demands discovery, has long had the same understanding of the workings of the Entitlements Program. At a meeting of the Hawkins Field interest owners shortly after DOE issued to Exxon the January 1978 Notice of Probable Violation, one owner asked who would ultimately benefit if the Hawkins Field owners were required to make refunds to the purchasers of improperly classified Hawkins Field crude oil. Exxon attorney Barbara Finney explained “that the refunds to the purchasers would in turn require the purchasers to buy more entitlements from other refiners and that the net effect would be a decrease in the overall cost to the refining industry for domestic crude oil.” PX 247 at 8 (Minutes of meeting at Hawkins Field working interest owners, February 3,1978). Just as refunds would be spread throughout the industry to reduce the overall average cost to refiners of domestic crude oil, so did Exxon’s overcharges spread throughout the industry to increase the average cost to refiners of domestic crude oil.

At the same time, price regulations applicable to refiners allowed them to pass along the inflated costs of Hawkins Field crude oil to purchasers of refined products. Under those rules the price a refiner could charge for a refined product was generally limited to the refiner’s May 15, 1973 price plus, among other costs, the increased cost of crude oil. 10 C.F.R. § 212.83(c)(2)(iii). Similar pass-through provisions for increased costs also applied to crude oil resellers, product resellers and retailers. See 10 C.F.R. Part 212, Subparts F and L. As a result of the pervasive system of price controls which then existed, therefore, Exxon’s overcharges were not, as it simplistically asserts, borne by Exxon itself, but instead were borne by ultimate consumers of petroleum products throughout the entire country.

The broad scattering of the ill effects of Exxon’s wrongdoing renders impossible the tracing of the overcharges to their ultimate victims and the calculation of the precise damages suffered by each. Yet this court is still faced with the task of fashioning an equitable remedy. The DOE suggests that, because ultimately all consumers suffered as a result of the overcharges, it would be most appropriate for the court to order payment into the Treasury of the United States government, the representative of all citizens. Exxon argues that the statute allows only reimbursement of the first purchasers of the overpriced crude oil, and then only after the DOE identifies the victims of the overcharges and proves the specific damages suffered by each. In any event, Exxon continues, under Citronelle-Mobile Gathering, Inc. v. Edwards, 669 F.2d 717 (Em.App.1982), payment to the United States Treasury may not be considered restitution.

As noted above, Section 209 of the Economic Stabilization Act empowers the court to require restitution of funds obtained in violation of the oil price regulations. The scope of the courts power is much broader than Exxon allows. To begin with, the remedy of restitution is fundamentally different from the remedy of damages. In Sauder v. DOE, supra, 648 F.2d 1341, Sauder argued that the DOE, in seeking to impose upon him alone responsibility for all overcharges, had tried to read into the statute a damages remedy not within the common law concept of restitution. In rejecting Sauder’s argument, the TECA distinguished restitution from damages, writing: “ ‘In equity, restitution is usually thought of as a remedy by which defendant is made to disgorge illgotten gains or to restore the status quo or to accomplish both objectives.’ ” Id. at 1348, quoting 5 Moore’s Federal Practice ¶ 38.24[2], 38-195 (2d ed. 1981) (emphasis added). The agency, the court continued, “does not seek to recover Mobil’s damages, which may or may not be the amount of the overcharges.” 648 F.2d at 1348. The TECA stated the difference even more bluntly in Citronelle-Mobile Gathering, Inc. v. Edwards, supra, 669 F.2d 717:

The central purpose of restitution is to determine the amount by which the wrongdoer has been unjustly enriched and then to make him disgorge that amount. No proof is required that the plaintiff was damaged, much less the amount of any damage.

Id. at 722 (emphasis added). Accordingly, the DOE need not attempt the impossible task of proving the identity and particular damages of each victim of the Hawkins Field overcharges in order for this court to order restitution.

As explained above, prior to decontrol in January 1981 DOE controlled the price of oil at every stage of production. In those circumstances, if a court ordered restitution of overcharges to the first purchaser of crude oil, that reimbursement would eventually be passed along to the ultimate consumer of petroleum products. See Grigsby v. DOE, 4 Energy Mgt. (CCH) ¶ 26,378 at 28,841 (W.D.La.1982). Since decontrol, however, there has existed no ready method of ensuring that overcharges will be refunded to their ultimate victims, the consumer. To order a refund to the first purchaser would simply result in a windfall gain for that purchaser — ironically, in this case, Exxon itself — who would be under no obligation to pass the refund along.

Exxon maintains nevertheless that it is beyond the equitable powers of this court to order payment into the United States Treasury and bases its argument on Citronelle-Mobile Gathering, Inc. v. Edwards, supra, 669 F.2d 717. In that case two domestic crude oil resellers sold crude oil to PETCO, the wholly-owned foreign subsidiary of an American corporation, NEPCO. The oil was refined in the Bahamas by BARCO, a subsidiary of PETCO, and then shipped to NEPCO in the United States. NEPCO in turn sold the refined products to utilities and institutions on the east coast. The sellers claimed the first sales were export sales, exempt from price controls. The district court denied the sellers’ claims and held them in violation of the price ceilings. The government asked that the overcharges be paid into an escrow account for subsequent distribution to NEPCO customers. Instead, the district court sua sponte ordered restitution to the United States Treasury. The TECA affirmed, except as to remedy, holding that “payment to the United States Treasury is not restitution in the true sense of the word, or in the objectives of the statutes involved.” 669 F.2d at 722.

Careful reading of the TECA decision reveals, however, that the court’s modification of the district court’s remedy was not a blanket prohibition on the ordering of restitution to the Treasury. The district court, TECA explained, shaped its remedy under the mistaken impression that the ultimate overcharge victims were undeterminable millions of individuals along the east coast. The TECA found, however, that “the sale of the over-priced oil was made to determinable utilities and other institutions along the Atlantic seaboard.” 669 F.2d at 722. Having demonstrated injury to an identifiable class of persons, the government had a duty to try to ascertain those overcharged and to make restitution to them, with interest, from the restitution funds. Id. at 723. To accomplish that end, the TECA remanded to the district court with instructions to order the violators to make restitution to the Treasury, but under special order of the court directing the Treasury to hold the funds in an escrow account for subsequent distribution, at DOE’s direction, to NEPCO customers. Id.

The TECA’s refusal in Citronelle to allow unconditional payment into the Treasury was clearly based on the facts in that case which permitted identification of the victims of the overcharges. The four shipments which were the subject of inquiry in Citronelle all occurred within the six months ending in late May 1974, before implementation of the Entitlements Program. See Citronelle-Mobile Gathering, Inc. v. O’Leary, 499 F.Supp. 871, 874-75 (S.D.Ala.1980), aff’d sub nom. Citronelle-Mobile Gathering, Inc. v. Edwards, supra, 669 F.2d 717. Consequently NEPCO’s customers alone bore the entire burden of the overcharges. DOE could measure their losses accurately and direct appropriate payment to them from the escrow fund suggested by the TECA.

Exxon’s Hawkins Field overcharges, on the other hand, were diffused throughout the country. Creation of an escrow fund would serve no purpose. Monies in such a fund would languish there indefinitely, because DOE could never accurately determine the losses suffered by any one claimant. Thus, the facts which required the court in Citronelle to order actual reimbursement of overcharges are not present here, and this court is not precluded on the facts before it from ordering Exxon to make restitution to the Treasury.

A district court, sitting as a court of equity, unless applicable statutes provide otherwise, has “ ‘all the inherent equitable power of the District Court ... available for the proper and complete exercise of that jurisdiction’; and has power ‘to do equity and mould each decree to the necessities of the particular case.’ ” Citronelle-Mobile Gathering, Inc. v. Edwards, supra, 669 F.2d at 722, quoting Porter v. Warner Holding Co., 328 U.S. 395, 398, 66 S.Ct. 1086,1089, 90 L.Ed.2d 1332 (1946). The applicable statutes here do not limit this court’s equitable powers. Sauder v. DOE, supra, 648 F.2d at 1348. The explicit reference to restitution in Section 209 of the ESA was to settle any doubt that “ ‘there was an inherent equitable power in the court to set things right and order restitution.”’ Id., quoting S.Rep. No. 507, 92d Cong., 1st Sess. 9 (1971), U.S. Code Cong. & Admin.News, pp. 2283, 2291. Section 209 neither limits the power of the court to restitution nor to a particularly strict interpretation of restitution. 648 F.2d at 1348.

Furthermore, to order restitution to the Treasury in these circumstances is consistent with the principle underlying enforcement of the regulations that “[ajctions taken by the United States under ESA § 209 are taken to enforce public, not private rights. Thus, compensation is ‘a by-product of the agency’s effort to reestablish compliance with its regulatory scheme.’ ” Citronelle-Mobile Gathering, Inc. v. Edwards, supra, 669 F.2d at 722.

Indeed, the TECA in Citronelle did not disapprove any and all payments of restitution to the Treasury; it disapproved only the unconditional payment ordered by the district court. But the TECA itself directed payment into the Treasury, into an escrow account subject to certain conditions. In accordance with that principle, this court shall order Exxon to make restitution of the full amount of the overcharges, plus interest, to the Treasury, for deposit into an escrow account.

The task of this court in delineating the terms and conditions bf that account has been made easier by recent Congressional action. On December 21, 1982 Congress enacted Pub.L. No. 97-377, 96 Stat. 1830 (1982) providing continuing appropriations for fiscal year 1983. Section 155 of that law provides a formula for the disbursement of “designated petroleum violation escrow funds”, defined as “amounts (not in excess of $200,000,000) which are derived from settlements from alleged petroleum pricing and allocation violations .... ” The purpose of Section 155 is

to provide the Secretary of Energy the exclusive authority for the disbursement of the designated petroleum violation escrow funds for limited restitutional purposes (1) which are reasonably expected to benefit the class of persons injured by such violations, and (2) which ... are likely not to be ... otherwise refunded to injured persons because the purchasers of the refined petroleum products cannot be reasonably identified or paid or because the amount of each purchaser’s overcharge is too small to be capable of reasonable determination.

Pub.L. No. 97-377, § 155(a), 96 Stat. 1830, 1919 (1982).

Under the terms of the new law, the Secretary of Energy must distribute the escrow fund to the governors of each of the states, with the amount due each state based on that state’s share of nationwide consumption of refined petroleum products from 1973 to 1981. Id., § 155(c), (d). Each state must then use the funds under one or more of five existing federal energy conservation programs identified in the new law, including weatherization of buildings; implementing state energy conservation programs; cutting energy consumption in, or finding cheaper alternate energy sources for, schools and hospitals; promoting conservation by small businesses and individuals; and helping poor people pay home utility bills. None of the funds may be used to defray administrative expenses of the DOE or any state. Id., § 155(f).

The court shall order Exxon to make restitution to the United States Treasury of the full amount of the Hawkins Field overcharges, together with interest from the date of overcharge, the monies to be deposited into an escrow account, held in trust by the Department of Energy, to be disbursed in accordance with the procedures set forth in Section 155 of Pub.L. No. 97-377, 96 Stat. 1830, 1919 (1982).

In formulating its order, the court in no way relies on Section 155 as an express statutory grant of authority to this court, but acts instead in the exercise of its broad equitable powers to order restitution. However, Section 155 clearly bespeaks the intent of Congress that violators of the petroleum price regulations should be made to disgorge their illgotten gains even in situations, like the case before the court, where the victims of the petroleum overcharges cannot be identified. The colossal scale of Exxon’s wrongdoing, and the workings of pervasive regulations to spread the burden of that wrongdoing impossibly far and wide, must not deter this court from fashioning an appropriate equitable remedy. The purpose of the domestic petroleum price regulations was to keep oil prices down, to relieve consumers of some of the burden of towering oil costs. The five energy conservation programs identified in Section 155 operate across the nation to reduce that same burden, either by reducing overall consumption through conservation or by direct financial assistance to those most in need. Although one might speculate as to alternative remedies, this court respects the wisdom of the solution chosen by Congress and shall adopt it as the most appropriate equitable remedy in the circumstances of this case.

B. Amount of overcharges

The court has held that Exxon should have established a unit BPCL on January 1, 1975, the date a significant alteration in producing patterns occurred at the Hawkins Field Unit, and that Exxon may not claim the incentives of Section 212.75, but instead must proceed under Section 212.72. That done, calculation of Exxon’s overcharges becomes a straightforward matter of comparing Exxon’s actual accounting practices with those it should have applied. Using production, sales and price data derived from Exxon documents obtained through audits or discovery, DOE has calculated the amount of overcharges for each month from January 1975 through January 1981. For each month DOE has determined the appropriate unit BPCL and total unit production, as well as cumulative deficiency, if any. In so doing DOE has accorded Exxon the benefit of every favorable modification of the applicable regulations, even if not claimed by Exxon. Simple addition and subtraction yield the number of barrels, if any, Exxon was allowed to claim as upper-tier or exempt. Comparison with the number of barrels actually claimed by Exxon as upper-tier or exempt yields the number of barrels in violation. That number, when multiplied by the difference between the price received by Exxon and the lower-tier price, yields the amount of overcharges for that month. Finally, DOE has totalled the cumulative overcharges each month. The summary data which were the basis of DOE’s calculations are reproduced in Appendix I to this opinion.

Although Exxon contends that DOE’s overcharge calculations are “grossly inflated”, Def.Opp. at 289, Exxon has not challenged the mathematical accuracy of DOE’s calculations, nor the accuracy of the underlying data. Instead Exxon limits its attack to a reiteration of its previous arguments that it acted properly in establishing a unit BPCL on September 1, 1976 under Section 212.75. The court has rejected Exxon’s arguments.

Accordingly, there being no dispute of fact as to the validity or accuracy of DOE’s calculations, the court finds the total amount of overcharges by Exxon at the Hawkins Field Unit from January 1975 through January 1981 to be $895,501,163.85.

C. Interest

The court’s equitable powers to order restitution permit the court to deprive the wrongdoer of all enrichment obtained at the victim’s expense, Citronelle-Mobile Gathering, Inc. v. Edwards, supra, 669 F.2d at 722, and that enrichment necessarily includes the benefits Exxon obtained by having the use over the years of the money illegally obtained. Accordingly, this court shall order that restitution of Exxon’s overcharges shall be made with interest from the date of overcharge. Cf. Bonray Oil Co. v. DOE, 472 F.Supp. 899, 904 (W.D.Okl. 1978), aff’d per curiam 601 F.2d 1191 (Em. App.1979) (“[T]he requirement that sellers who violate regulations and orders promulgated under the EPAA also pay interest on the amount of the overcharge is a rational method to ‘make whole’ those who have been overcharged.”).

DOE proposes several alternative rates of interest, ranging from Exxon’s annual average rate of return, after tax, for capital deployed in domestic production activities from 1975 through 1981, 23.7 percent; the prime rate; or, finally, the schedule of interest rates it has applied in administrative enforcement actions since February 1980.

The court adopts the last formula. It is identical to the schedule long used by the Federal Energy Regulatory Commission in its enforcement actions, see 46 Fed.Reg. 21,412 (1981). It is the schedule which DOE would have applied to Exxon’s overcharges had they been assessed in a DOE Remedial Order following administrative adjudication. Most important, because the rate has since October 1979 been based on an average of prime rate values as determined by the Federal Reserve, the schedule bears a reasonable relation to the value to Exxon of the funds it unlawfully retained. The formula for calculating the applicable rate, as well as a summary of the rates determined according to that formula through July 1982, are attached hereto as Appendix II.

D. Civil Penalties

Finally, the government asks the court to assess civil penalties against Exxon. Section 208(b) of the ESA, 12 U.S.C. § 1904 note, incorporated in Section 5(a)(1) of the EPAA, 15 U.S.C. § 754, authorizes the court to assess civil penalties of not more than $2500 for each violation of the pricing regulations occurring prior to December 16, 1975. The EPCA increased the penalties to $20,000 for each violation after December 16, 1975. Agency regulations provide that “[ejach day that a violation ...- continues shall be deemed to constitute a separate violation within the meaning of the provisions of this chapter relating to . .. civil penalties.” 10 C.F.R. § 205.203(a)(2). Counting each day that overcharges occurred at the Hawkins Field as a separate violation from January 1,1975 through January 27,1981, DOE has calculated the maximum civil penalty to be $38.27 million.

Upon careful consideration of the voluminous record in this case, the court declines to assess civil penalties against Exxon. As the DOE has itself admitted, the oil price regulations are complex, and the unit property rule which is the cornerstone of DOE's case was only implicit in the original property definition of Section 212.72. See Pennzoil Co. v. DOE, supra, 680 F.2d at 176.

This is not to excuse Exxon’s behavior. Exxon pushed the agency at every turn and probed each nuance in the regulations to interpret them to Exxon’s advantage, sometimes ignoring their unequivocal dictates. Still, DOE has not proven, because it need not, that Exxon in fact gerrymandered production at the Hawkins Field in an attempt knowingly to circumvent price controls. The course of conduct which brought Exxon within the ambit of the unit property rule of Section 212.72 — unitization and gas injection — was undertaken for bona fide business reasons and indeed was traced long before any regulations on crude oil prices existed.

Nor did Exxon attempt to dissimulate its accounting practices at the Hawkins Field. On the contrary, it made repeated inquiries and comments, accurately representing its conduct to the agency, in the hope of changing agency policy. The informal replies Exxon received, though no basis for estoppel of the government, were nevertheless at times puzzling.

The court finds that the circumstances of this case do not warrant assessment of civil penalties.

Plaintiff shall submit a proposed judgment for the court’s consideration no later than 15 days from the date hereof, and defendant shall file its reply thereto no later than 10 days thereafter.

APPENDIX I

OPERATOR: Exxon Company, USA

PROPERTY NAME: Hawkins Field Unit

COUNTY AND STATE: Wood County, Texas

DATE BPCL BARRELS CUM SOLD DEF (ALLOWABLE SALES BBLS) NEW RELEASED TOTAL

2310657.00

1/75 2262898.00 3460686.80 1112868.20 0.00 0.00 0.00

2/75 2422029.00 3088253.30 446643.90 0.00 0.00 0.00

3/75 2873208.00 3476100.26 0.00 156248.36 156248.36 312496.72

4/75 3132625.00 3325164.41 0.00 192539.41 192539.41 385078.82

5/75 ■3374995.00 3437900.22 ' 0.00 62905.22 62905.22 125810.44

6/75 3210502.00 3327490.34 0.00 116988.34 116988.34 233976.68

7/75 3306766.00 3406759.40 0.00 99993.40 99993.40 199986.80

8/75 3310681.00 3426979.44 0.00 116298.44 116298.44 232596.88

9/75 3148044.00 3328544.70 0.00 180500.70 180500.70 361001.40

10/75 3400107.00 3420890.39 0.00 20783.39 20783.39 41566.78

11/75 •3211871.00 3282074.89 0.00 70703.89 70703.89 141407.78

12/75 3294406.00 3426138.29 0.00 131732.29 131732.29 263464.58

1/76 2262898.00 3411987.05 0.00 1149089.05 1149089.05 2298178.10

2/76 2927544.61 '3268644.39 0.00 341099.78 0.00 341099.78

3/76 3156445.24 3392140.02 0.00 235694.78 0.00 235694.78

4/76 3054624.43 3350070.55 0.00 295446.12 0.00 295446.12

5/76 3156445.24 3456725.59 0.00 300280.35 0.00 300280.35

6/76 3059477.23 3311341.49 0.00 251864.26 0.00 251864.26

7/76 3161459.80 3404466.24 0.00 243006.44 0.00 243006.44

8/76 3161459.80 3411372.07 0.00 249912.27 0.00 249912.27

9/76 3059477.23 3200400.82 0.00 140923.59 0.00 140923.59

10/76 3161459.80 3267286.41 0.00 105826.61 0.00 105826.61

11/76 3059477.23 3168078.89 0.00 108601.66 0.00 108601.66

12/76 3161459.80 3151089.10 ’ 10370.70 0.00 0.00 0.00

1/77 3161459.80 2825880.59 345949.91 0.00 0.00 0.00

2/77 2957494.56 2647308.40 656136.07 0.00 0.00 0.00

3/77 3161459.80 2922117.52 895478.35 0.00 0.00 0.00

4/77 3059477.23 2777140.72 1177814.86 0.00 0.00 0.00

5/77 3161459.80 2920300.05 1418974.61 0.00 0.00 0.00

6/77 3059477.23 2747579.21 1730872.62 0.00 0.00 0.00

7/77 3161459.80 2733688.10 2158644.32 0.00 0.00 0.00

8/77 3161459.80 2658730.03 2661374.10 0.00 0.00 0.00

9/77 3059477.23 2530527.16 3190324.16 0.00 0.00 0.00

10/77 3161459.80 2625265.25 3726518.71 0.00 0.00 0.00

11/77 3059477.23 2505620.20 4280375.74 0.00 0.00 0.00

12/77 3161459.80 2553364.93 4888470.61 0.00 0.00 0.00

1/78 3161459.80 2471858.78 5578071.63 0.00 0.00 0.00

2/78 2957494.56 2209923.76 6325642.43 0.00 0.00 0.00

3/78 3161459.80 2409479.91 7077622.32 0.00 0.00 0.00

4/78 3059477.23 2241673.15 7895426.40 0.00 0.00 0.00

5/78 3161459.80 2279936.58 8776949.62 0.00 0.00 0.00

6/78 3059477.23 2313557.83 9522869.01 0.00 0.00 0.00

7/78 3161459.80 2344094.63 10340234.18 0.00 0.00 0.00

8/78 3161459.80 2241264.50 11260429.48 0.00 0.00 0.00

9/78 3059477.23 2083630.89 12236275.82 0.00 0.00 0.00

10/78 3161459.80 2232892.02 13164843.60 0.00 0.00 0.00

11/78 3059477.23 2100939.43 14123381.40 0.00 0.00 0.00

12/78 3161459.80 2102996.02 15181845.18 0.00 0.00 0.00

1/79 3161459.80 2056508.20 16286796.78 0.00 0.00 0.00

2/79 2957494.56 1935355.61 17308935.73 0.00 0.00 0.00

3/79 3161459.80 2032336.67 18438058.86 0.00 0.00 0.00

4/79 3059477.23 1961051.46 19536484.62 0.00 0.00 0.00

5/79 3161459.80 1965368.10 20732576.32 0.00^ 0.00 0.00

PURCHASER: Exxon Company, USA

FIELD: Hawkins

ACTUAL (SALES IN APPARENT VIOLATION) SALES # BBLS BONUS OVERCHARGES CUM OVERCHARGES

2297789.00 2297789.00 6.0000 13786734.00 13786734.00

1997999.00 1997999.00 6.4000 12787193.60 26573927.60

2180673.00 1868176.28 6.4000 11956328.19 38530255.79

1799331.00 1414252.18 6.7000 9475489.61 48005745.40

1836020.00 1710209.56 6.7000 11458404.05 59464149.45

1685954.00 1451977.32 6.7011 9729845.22 69193994.67

1722834.00 1522847.20 7.0026 10663889.80 79657864.47

1717721.00 1485124.12 7.1900 10678042.42 90535926.89

1716269.00 1355267.60 7.2900 9679900.80 100415827.89

1498974.00 1457407.22 7.5400 10988850.44 111404678.13

1455581.00 1314173.22 7.7900 10237409.38 121642087.51

1609927.00 1346462.42 7.7900 10488942.25 132131029.76

2417713.00 119534.90 7.7900 931176.87 133062206.63

1934181.43 1593081.65 5.9700 9510697.45 142572904.08

2027418.00 1791723.22 6.0100 10768256.55 153341160.63

1995410.00 1699983.88 6.0500 10284781.45 163625942.08

2068392.00 1768111.65 6.0800 10750118.83 174376060.91

2008093.00 1756228.74 6.1100 10730557.58 185106618.49

2039907.00 1790900.56 6.1100 10979082.42 196085680.91

2033008.00 1783095.73 6.1100 10894714.91 206980395.82

1903505.51 1762581.92 6.1144 10777130.87 217757526.69

1903657.26 1797830.65 6.1146 10993015.30 228750541.90

1903581.24 1794979.58 6.1145 10975402.62 239725944.61

1903581.25 1903581.25 6.1145 11639447.55 251365392.16

1903581.26 1903581.26 5.9151 11259873.51 262625265.67

1903581.24 1903581.24 5.9151 11259873.39 273885139.06

1903581.24 1903581.24 5.4664 10405736.49 284290875.55

1903581.25 1903581.25 5.4664 10405736.55 294696612.10

1903581.24 1903581.24 5.4664 10405736.49 305102348.59

1903581.26 1903581.26 5.4664 10405736.60 315508085.19

1903581.25 1903581.25 5.4664 10405736.55 325913821.74

1857249.00 1857249.00 5.4454 10113463.70 336027285.44

1902656.51 1902656.51 5.6977 10840766.00. 346868051.44

1902656.49 1902656.49 5.9269 11276854.75 358144906.19

1902656.49 1902656.49 6.1562 11713133.88 369858040.07

1902470.49 1902470.49 6.1860 11768682.45 381626722.52

1902656.50 1902656.50 6.2159 11826722.54 393453445.06

1902656.50 1902656.50 6.2457 11883421.70 405336866.76

1902656.51 1902656.51 6.2755 11940120.93 417276987.69

1902656.50 1902656.50 6.3054 11997010.30 429273997.99

1902656.51 1902656.51 6.3352 12053709.52 441327707.51

1902656.01 1902656.01 6.3750 12129432.06 453457139.57

1902656.51 1902656.51 6.4148 12205160.98 465662300.55

1902656.50 1902656.50 6.4546 12280886.64 477943187.19

1876593.01 1876593.01 6.5043 12205923.91 490149111.10

1939145.00 1939145.00 6.5639 12728353.87 502877464.97

1876593.00 1876593.00 6.6236 12429801.39 515307266.36

1939145.00 1939145.00 6.6634 12921298.79 528228565.15

1939145.00 1939145.00 6.7059 13003712.46 541232277.61

1751485.99 1751485.99 6.7457 11814999.04 553047276.65

1939145.00 1939145.00 6.7854 13157874.48 568205151.13

1876593.00 1876593.00 6.8311 12819194.44 579024345.57

1939145.00 1939145.00 6.8724 13326580.10 592350925.67

OPERATOR: Exxon Company, USA

PROPERTY NAME: Hawkins Field Unit

COUNTY AND STATE: Wood County, Texas

DATE BPCL TOTAL SALES CUMULATIVE _ _ _ DEFICIENCY (Bbls) (Bbls) (Bbls) ALLOWABLE SALES UPPER TIER/ EXEMPT (Bbls) ACTUAL SALES UPPER TIER/ EXEMPT (Bbls)

6/79 1869154.20 1862155.27 0.00 0.00 1862155.27

0.00 0.00

7/79 1899622.09 1823531.79 0.00 0.00 1823531.59

0.00 0.00

8/79 1867784.85 1909925.56 0.00 42140.71 1909925.00

0.00 0.00

9/79 1776723.49 1872859.91 0.00 96136.42 1872859.91

0.00 0.00

10/79 1804110.36 1893769.72 0.00 89659.36 1893769.72

0.00 0.00

11/79 1715103.03 1762225.53 0.00 47122.50 1762140.00

0.00 0.00

12/79 1740435.88 1953014.64 0.00 212578.76 1939145.00

0.00 0.00

1/80 1676761.40 1936779.21 0.00 248056.99 1842173.89

11960.82 94605.32

2/80 1456981.73 1720285.62 0.00 239079.93 1557111.00

24223.96 163175.00

3/80 1549412.43 1833881.61 0.00 245212.43 1575824.61

39256.75 256057.00

4/80 1437810.92 1747684.06 0.00 252856.48 1421546.00

57016.66 326138.00

5/80 1422063.46 1748171.65 0.00 251103.31 1341643.00

75004.88 406529.00

6/80 1314569.98 1673328.45 0.00 259741.13 1207353.00

99017.34 465854.00

7/80 1294714.50 1612948.08 0.00 215762.37 1089171.88

102471.21 523047.91

8/80 1231040.01 1571949.90 0.00 215455.05 989276.34

125454.84 581618.29

9/80 1129708.58 1431329.42 0.00 176749.81 834074.76

124871.03 594855.89

10/80 1103691.05 1491141.30 0.00 209223.13 802267.00

178227.12 689191.00

11/80 1006467.64 1501186.31 0.00 244391.02 738666.00

250327.65 762202.98

12/80 976342.08 1415902.14 0.00 196922.91 631735.00

242637.15 784167.00

1/81 912667.60 1412823.77 0.00 201062.76 492647.00

299093.39 478234.55

TOTAL OVERCHARGE (this exhibit)

CUMULATIVE OVERCHARGE

PURCHASER: Exxon Company, USA

FIELD: Hawkins

SALES IN VIOLATION QUANTITY BONUS OVERCHARGE CUMULATIVE OVERCHARGE

(Bbls) ($Bbl) ($) ($)

1862155.27 6.9378 12919260.83

0.00 0.0000 0.00 12919260.83

1823531.59 6.9935 12752868.17

0.00 0.0000 0.00 25672129.00

1867784.29 7.0493 13166571.80

0.00 0.0000 0.00 38838700.80

1776723.49 7.1160 12643164.35

0.00 0.0000 0.00 51481865.15

1804110.36 7.1767 12947558.82

0.00 0.0000 0.00 64429423.97

1715017.50 7.2447 12424787.28

0.00 0.0000 0.00 76854211.25

1726566.24 7.3115 12623789.06

0.00 0.0000 0.00 89478009.31

1594116.90 7.2994 11636096.90

82644.50 29.1788 2411467.34 103525564.55

1318031.07 7.3400 9674348.05

138951.04 29.2600 4065707.43 117265620.03

1330612.18 7.4000 9846530.13

218800.25 29.2200 6393343.31 133505493.47

1168689.52 7.4000 8718423.82

269121.34 29.1800 7852960.70 150076877.99

1090539.69 7.5100 8189953.07

331524.12 29.1300 9657297.62 167924128.68

947811.87 7.5700 7173421.86

366836.00 29.0800 10667610.07 185765160.61

873409.51 7.6300 6664114.56

420576.70 29.0300 12209341.60 204638616.77

773821.29 7.6902 5950840.48

456368.45 27.9810 12769505.69 223358962.94

657324.95 7.7501 5094334.09

469984.66 27.1574 12763566.84 241216863.67

593043.87 7.8100 4631672.62

510963.86 26.8600 13724489.82 259573026.31

494274.98 7.8800 3894886.84

511875.33 26.8000 13718256.84 277186171.99

434812.09 7.9500 3456756.12

541529.85 27.7500 15027453.34 295670381.45

291584.22 8.0200 2338505.44

179141.16 28.7000 5141351.29 303150238.18

303150238.18

895501163.85

The DOE schedule for the computation of interest on overcharges, reprinted in 46 Fed.Reg. 21,412; 21,414 (1981) provides that interest should be computed:

(1) At a rate of seven percent simple interest per annum prior to October 10, 1974;
(2) At a rate of nine percent simple interest per annum between October 10, 1974 and September 30, 1979; and
(3) a. At an average prime rate for each calendar quarter on or after October 1, 1979. The applicable average prime rate for each calendar quarter shall be the arithmetic mean, to the nearest one-hundredth of one percent, of the prime rate value published in the Federal Reserve Bulletin for the fourth, third, and second months preceding the first month of the calendar quarter.
b. The interest paid under clause (3)a. should be compounded quarterly.
c. ...
As applicable, interest Should be computed from the date of the violation to the effective restitution date although where it is practically impossible to determine the specific date upon which a violation commenced, it may be necessary, for the purpose of computing interest, to treat all violations in a given month as having occurred on the last day of that month.

Under the above formula, the rates applicable to Exxon’s Hawkins Field overcharges are:

Period Rate (Percent)

January 1, 1975 to September 30,1979 9.00 percent

October through December 1979 11.70

January through March 1980 14.28

April through June 1980 15.39

July through September 1980 18.22

October through December 1980 11.74

January through March 1981 14.03

April through June 1981 19.98

July through September 1981 18.27

October through December 1981 20.31

January through March 1982 18.46

April through June 1983 16.02

July 1982 through date of effective restitution, adjusted quarterly in accordance with the above formula 
      
      . The DOE, established in 1977 under the Department of Energy Organization Act, 42 U.S.C. § 7101 et seq., has responsibility for the enforcement of federal oil price regulations. It was preceded in this task by the Federal Energy Administration (“FEA”), set up under the Federal Energy Administration Act, formerly 15 U.S.C. § 76.1 et seq., which was in turn preceded by the Federal Energy Office, (“FEO”) created following enactment of the Emergency Petroleum Allocation Act of 1973, 15 U.S.C. § 751 et seq. Where appropriate the DOE, FEA and FEO will be referred to interchangeably throughout this Opinion.
     
      
      . Initially the price of new oil was simply not controlled; the regulations allowed it to be sold “without respect to the ceiling [lower-tier] price.” 10 C.F.R. § 212.72 (1975). However, in February 1976, in implementing the Congressional directives of Section 401(a) of the Energy Policy and Conservation Act (“EPCA”), Pub.L. No. 94-163, Title IV, 89 Stat. 871, 941 (1975), 15 U.S.C. §§ 757 et seq., the FEA established the upper-tier ceiling price for new oil. 41 Fed.Reg. 4931, 4932 (1976).
     
      
      . The initial base period was calendar year 1972. 10 C.F.R. § 212.72 (1975). The FEA recognized, however, that as production at older fields declined naturally, it became increasingly difficult for producers to boost production above 1972 levels, and the lure of higher new oil prices no longer served as a realistic incentive to increased production. 41 Fed.Reg. 4931, 4932-33 (1976). Consequently, in February 1976 the FEA amended the regulations to provide producers with a choice. For production after February 1, 1976, producers could choose as their monthly BPCL either corresponding monthly 1972 production levels or average monthly 1975 production. 10 C.F.R. § 212.72 (1977); 41 Fed.Reg. 4931, 4932-33 (1976). In 1979 the DOE added a third choice for production after May 31, 1979; the BPCL could be based on average monthly production in the six-month period ending March 31, 1979. 10 C.F.R. § 212.72 (1980); 44 Fed.Reg. 25,160; 25,167 (1979).
     
      
      . The 1974 regulations provided a bonus of sorts. For every barrel of new oil produced, a producer could sell one barrel of “released” oil at the higher, uncontrolled price, 10 C.F.R. §§ 212.72,212.74 (1975). Provisions for releasing lower-tier crude oil to the upper tier were eliminated as of February 1, 1976. 10 C.F.R. § 212.72 (1977); 41 Fed.Reg. 4931, 4933 (1976).
      In fact, the calculation of new and old oil is further complicated by the regulation regarding “current cumulative deficiency.” Once a producer had sold new oil in a particular month (i.e., exceeded the BPCL), any amount, in any succeeding month, by which production fell short of the BPCL, constituted a “deficiency.” The sum of such deficiencies constituted the “current cumulative deficiency.” 10 C.F.R. § 212.72 (1975). Any later production above the BPCL first had to be applied to reduce the current cumulative deficiency before it could be accounted for as new oil. Id. The revised definition of BPCL contained in the February 1976 amendments to the regulations eliminated, effective February 1, 1976, all then-existing current cumulative deficiencies. 41 Fed.Reg. 4931, 4933.
      Finally, under the 1974 regulations, production from stripper well leases was exempt from price control, as required by Section 4(e)(2) of the EPAA. 10 C.F.R. § 210.32 (1975). Stripper well leases were defined as leases on which average‘"daily production per well did not exceed ten barrels. 10 C.F.R. § 212.32(b). In February 1976 when the FEA first imposed a ceiling price on new oil, it eliminated the stripper well exemption also, and provided for it to be sold at upper-tier ceiling prices. 10 C.F.R. § 212.74 (1977); 41 Fed.Reg. 4931, 4940 (1976). The ceiling price on stripper well oil was short-lived, however, as Congress in its August 1976 amendments to the EPAA again required its complete exemption. Energy Conservation and Production Act (“ECPA”), Pub.L. No. 94-385, Section 121, 90 Stat. 1125, 1133, 15 U.S.C. § 757(i). The FEA incorporated the exemption into the regulation in October 1976. 10 C.F.R. § 212.54 (1977); 41 Fed.Reg. 48,323 (1976).
     
      
      . The FEO took the' property definition unchanged from the previous CLC regulations at 6 C.F.R. § 150.354 (1974). The definition was grammatically altered in 1976 to read “the right to produce domestic crude oil, which arises from a lease or from a fee interest.” 10 C.F.R. § 212.72 (1977); 41 Fed.Reg. 4931, 4940 (1976).
     
      
      . Often numerous competing leaseholds may overlay a single large reservoir of oil. Years of competitive exploitation gradually deplete the reservoir, however, and as natural reservoir pressure lessens annual production may decline. See Plaintiffs Memorandum of Points and Authorities in Support of Motion for Summary Judgment (“Pltf. Mem.”) at 10. To reverse this decline, producers, can undertake various enhanced recovery efforts to increase the pressure in the reservoir, for example through the injection of liquids or gases. Id. To do so, however, the previously competing leaseholders must generally group their interests and form a single unit comprising all of the interests in the single reservoir of oil. This grouping of interests, usually embodied in a “Unit Agreement,” is known as unitization. Id.
      
      These efforts will most likely result in the shutting in altogether of wells within certain leaseholds and increasing the production at others, as the enhanced recovery efforts cause oil to flow underground across lease lines. See 41 Fed.Reg. 1564, 1569-70 (1976). Consequently, payments to unit participants are based not on the actual production of a particular participant’s wells, but on an imputed percentage of the unit’s total production. Id.
      
     
      
      . Preceding the issuance of Ruling 1975-15, in response to requests from producers in late 1974 and early 1975, the FEA issuéd five formal Interpretations on the subject of the application of the definition of “property” to unitized properties, later published at 42 Fed.Reg. 23,723; 23,726; 23,730 and 25,659 (1977).
     
      
      . The FEA described two ways in which the unit BPCL requirement could block unitization by discouraging potential participants from entering unit agreements. Producers of stripper well leases might hesitate to join if, when their production was averaged with that of other unit participants, their lease would lose its exempt or upper-tier status. A producer of much new crude oil might similarly hesitate, if the effect of his joining the unit would be to reclassify much or all of his new oil production as old oil due to the relatively low production on neighboring leases. See 41 Fed.Reg. 1564, 1570-71 (1976).
     
      
      . 15 U.S.C. § 757(b)(2) in fact provides that the President could find that the price increase would stimulate enhanced recovery projects or deep horizon development, but the latter is not relevant to this action.
     
      
      . Part of the FEA response to Congressional desires as to price control was to establish a ceiling price for new oil, which had theretofore been sold without regard to price controls. See n. 2, supra. The FEA was equally conscious of moderating average oil prices when it selectively applied incentives for unitized properties, depending on the date of unitization. See discussion at pp. 821-22, infra.
      
     
      
      . See S.Rep. No. 516, 94th Cong., 1st Sess. 190-91 (1975); 41 Fed.Reg. 4931, 4932 (1976).
     
      
      . Since “significant alteration in producing patterns” had been defined and because the unit BPCL rule applied to all units regardless of whether they were formed for enhanced recovery purposes, the definition of “enhanced recovery project” was deleted from the regulation effective September 1, 1976. 41 Fed.Reg. 36,172; 36,182.
     
      
      . But see n. 35, infra. In addition, the FEA recognized that, as to units at which a significant alteration in producing patterns occurred before February 1, 1976, the regulatory term was not then formally defined. In Ruling 1977-2 the agency stated that the definition effective September 1, 1976, would be used as guidance in conducting compliance audits of pre-1976 units. 42 Fed.Reg. at 4415. Moreover, operators of such units would be allowed to justify the choosing of the date of a “significant alteration” on “reasonable bases other than those specified by the present definition.” Id. The court rejects the agency’s characterization of its action as a relaxation of enforcement policy, but nevertheless upholds its retroactive application. See pp. 835-36, infra; see also n. 38, infra.
      
     
      
      . The various pleadings and exhibits attached thereto filed in connection with the parties’ cross-motions for summary judgment shall herein receive the following designations: ■ .
      (1) Plaintiff’s Memorandum in Support of Motion for Summary Judgment: “Pltf. Mem.”
      (2) Exhibits to Pltf.Mem: “PX”
      (3) Defendant’s Memorandum in Opposition to Plaintiff’s Motion for Summary Judgment: “Def. Opp.”
      (4) Exhibits to Def.Opp.: “DX Opp.”
      (5) Defendant’s Memorandum in Support of Motion for Summary Judgment: “Def. Mem.”
      (6) Exhibits to Def.Mem.: “DX”
      (7) Plaintiff’s Opposition to Defendant’s Motion for Summary Judgment: “Pltf. Opp.”
     
      
      . At the time of the initial efforts towards unitization, Exxon’s interests were in fact held by its predecessor corporation, Humble Oil and Refining Company. For the sake of clarity and simplicity, references made to Exxon shall be understood to mean Humble where appropriate.
     
      
      . For a more detailed description of the regulations and their evolution, including relevant citations, see discussion at pp. 818-22, supra.
      
     
      
      . The court specified that “[n]o one has claimed that there was any flaw in the rule-making encompassing the property definition.” 680 F.2d at 167.
     
      
      . The nine industry commenters included Gulf Oil Corporation, PX 27; Exchange Oil & Gas Corporation, PX 26; Union Oil Company of California, PX 28; Texaco, Inc., PX 30; Andover Oil Company, PX 24; Phillips Petroleum Company, PX 25; Ashland Oil, Inc., PX 23; Ernest Cockrell, an independent oil and gas producer, PX 22; and the Denver law firm of Holme Roberts & Owen, PX 31. The FEA received a total of 272 comments, all of which it considered despite the fact that 110 were filed late. 38 Fed.Reg. 22,536.
     
      
      . That a party follows the clear commands of a final rule does not necessarily prove that it has received sufficient notice of the proposed rule, but where, as in the instant case, the final rule differed so little from the proposed rule, see discussion at p. 828, infra, Exxon’s unhesitating compliance with the unit property rule on September 1, 1973 is certainly evidence that it understood the virtually identical proposed rule a month earlier.
     
      
      . The summary of the history of the stripper well exemption in the text is recounted in greater detail in In re DOE Stripper Well Exemption Litigation, 690 F.2d 1375, 1380-86 (Em.App.1982). See also n. 4, supra.
      
     
      
      . Production at individual wells could exceed ten barrels per day and not undo the exemption so long as production from other wells was sufficiently low so that average production per well did not exceed ten barrels per day.
     
      
      . In the February 1, 1976 amendments to the regulations, the FEA provided that producers at units formed thereafter could sell at upper-tier prices a volume of crude oil equal to the average volume of stripper well lease production in the twelve months preceding the establishment of a unit BPCL, an amount termed “imputed stripper well oil.” 41 Fed.Reg. 4931, 4941 (1976); 10 C.F.R. § 212.75(f) (1977). When Congress mandated the return of stripper well oil to exempt status eight months later, the FEA amended the regulations to allow “imputed stripper well oil” to be free of any price controls. 41 Fed.Reg. 36,172; 36,184 (1976).
     
      
      . Exxon appears at first to argue that the unit property rule cannot be applied at all to any unit containing stripper well leases. See, e.g., Def.Mem. at 116 (“[T]o the extent that the DOE’s reading of the ‘property’ regulation in this case requires that a unit be regarded as a single ‘property’ for purposes of the stripper well lease exemption, it is beyond the agency’s statutory authority and is invalid and unenforceable.”) In its Reply Memorandum Exxon retreats from this extreme position. See Def. Reply at 14.
     
      
      . Exxon also argues that in enacting the EPCA Congress intended that the FEA remove the barriers to unitization which the oil industry had identified as resulting from the unit property rule as set forth in Ruling 1975-15. Among those barriers was the reluctance of stripper well leaseholders to join a unit if doing so would cause their oil to lose its exempt status. See n. 8, supra. The FEA responded in February 1976 when it created a measure of “imputed stripper well oil” which could be claimed by units formed after that date. See n. 22, supra. To deny the benefits of the imputed stripper well exemption to units formed before February 1976, says Exxon, contravenes Congressional intent in the EPCA and ECPA because to do so maintains the disincentives faced by stripper well leaseholders asked to join an enhanced recovery unit. The court addresses in greater detail at pp. 836-40, infra, the issue of discrimination by the FEA in February 1976 between preexisting and future units. It is enough for the purposes of the present discussion to note that those eager to form a unit could persuade reluctant stripper well leaseholders to join by providing in the unit agreement a formula for the allocation of production to such leaseholders which would recognize the sacrifice they made in joining the unit — in other words, by paying them more. Indeed, even under 10 C.F.R. § 212.75(f), stripper well production is imputed to the unit as a whole, and not to individual leaseholders. See Francis Oil & Gas Co. v. Exxon Corp., 687 F.2d 484, 490 (Em.App.1982). Allocation of imputed upper-tier or exempt oil within the unit was left to private contract. Id.; 41 Fed.Reg. at 4937.
     
      
      . Exxon’s heavy reliance on the plain language of the TAPAA and the EPAA, referring to exempt production from stripper well “leases,” is undermined by the choice of Congress, in reenacting the exemption in Section 121 of the ECPA, to substitute the word “property” for “lease.” See 90 Stat. 1132-33 (1976).
     
      
      . The possibilities for abuse are illustrated by practices at the Hawkins Field itself, where after unitization average production at a few stripper well leases jumped at times to between 30 and 80 barrels per day, and in one case to 118 barrels per day. PX 309, 310; see Pltf. Opp. at 25 n. 21.
     
      
      . See also Pasco, Inc. v. FEA, 525 F.2d 1391, 1394 n. 6 (Em.App.1975) (“This phrase [‘gargantuan task’] was similarly applied to the burden imposed on the Cost of Living Council under the [Economic] Stabilization Act [of 1970] which, like the [Emergency Petroleum] Allocation Act, was an extremely broad delegation of authority by Congress to the Executive Branch under recognized emergency conditions.”).
     
      
      . When the district court in Pasco., Inc. v. FEA, supra, invalidated the FEA’s failure to extend a particular exemption to all small refiners, finding that failure contrary to one of the enumerated purposes of the EPAA, the TECA reversed, writing:
      “[T]he FEA had at the same time to consider the other eight objectives of Section 406(b)(1), including ... equitable distribution of crude oil at equitable prices.” 525 F.2d at 1397.
     
      
      . Upon rehearing, the court found that under Louisiana law, the original state order compelling unitization of the five properties created a unit only for purposes of production from the reservoir in which the first well had been drilled. 585 F.2d at 1084. Grigsby’s second well, although within the contours of the five properties, produced oil from a geologically separate reservoir and therefore created a separate “right to produce” under state law. Id at 1085. As such, the court held Grigsby was permitted to treat all production from the second well as new oil. Id. The court’s finding in no way detracted, however, from the strength of its earlier holding that the right to produce defined the property for purposes of federal price control regulations, but merely recognized that the right to produce could arise not only through contractual relations, but also by state law. See id. at 1083.
     
      
      . See n. 8, supra. But Exxon exaggerates the importance of the disincentive created. It argues that holders of leases producing much new or stripper oil would simply refuse to join a unit if doing so would cause their oil production to lose its exempt status. But as discussed in n. 24, supra, it would not be a difficult matter for Exxon to devise a formula, to be incorporated in the unit agreement, compensating such reluctant leaseholders for their sacrifice and persuading them to join the unit. To be sure, to the extent the other prospective participants, eager to induce the necessary cooperation of the stripper and new oil producers, would have to pay such producers more, they would in turn earn that much less from the unitization scheme. But to say that the other participants would earn some lesser amount is not to conclude that the unitization project would necessarily be scuttled. The success of a unitization and enhanced recovery project depends on the amount of additional oil it will yield above what could be produced in the absence of unitization. If the amount of additional oil is sufficiently large, then the present value of the stream of payments to unit participants after unitization could be greater than the present value of the stream payments which would flow to those interest holders from a continuation of pre-unitization, competitive production — even if post-unitization production must be sold at old oil prices and even as adjusted to account for buying off the reluctant stripper and new oil producers. This is not to say that in fact such would be the case at, say, the Hawkins Field. But Exxon’s contention that the unit property rule in all cases necessarily presents insuperable obstacles to unitization is incorrect. And any cost which the rule’s application adds to the process of unitization are reasonable in light of the agency’s obligation to protect against gerrymandering and evasion of price controls.
     
      
      . After discussing the rescission of Ruling 1975-15 by the agency in February 1976, and the announcement of the “significant alterations in producing patterns” test, the TECA in Pennzoil concluded: “There is not now before us any issue concerning the application of this subsequent rulemaking and we refrain from expressing any opinion concerning it other than that it does not militate against our disposition of the issues presented to us on this appeal.” 680 F.2d at 164 n. 13.
     
      
      . At units formed after February 1, 1976 producers could calculate the unit BPCL based on average production not in 1975 or 1972 but in the twelve months preceding the date on which enhanced recovery operations began or a significant alteration in producing patterns occurred. Producers at new units could also sell at upper-tier prices “imputed stripper well oil” and, as of September 1, 1976, “imputed new oil”, both calculated on the basis of the average volume of such production from the properties comprising the unit during the same twelve months. Existing units, on the other hand, received lesser incentives, including the revised 1975 BPCL base period, the elimination of cumulative deficiencies, and the retroactive rescission of Ruling 1975-15. See discussion at pp. 820-21, supra, and citations therein.
     
      
      . According to Ruling 1977-2, 42 Fed.Reg. 4409 (1977), after the February 1976 amendments to the regulations were issued two elements determined the required manner of accounting for oil production at units: the date on which the unit was formed and, more important, the date on which enhanced recovery operations began or a significant alteration in producing patterns occurred.
      Although Ruling 1977-2 is not a model of clarity, three categories of units may be distilled from it. The first category consisted of all units formed before February 1, 1976, and at which enhanced recovery operations or a significant alteration in producing patterns occurred before September 1, 1976. At units in the first category a unit BPCL had to be established as of the date the significant alteration in producing patterns occurred. Only Section 212.72 applied to these units. 42 Fed.Reg. at 4415.
      The second category consisted of all units, whenever formed, at which a significant alteration in producing patterns occurred only after August 31, 1976. At units in this second category, as well, a unit BPCL had to be established as of the date the significant alteration in producing patterns occurred, but such units enjoyed all the benefits of Section 212.75. Id.; see n. 35, infra.
      
      The third category consisted of units formed between February 1, 1976 and August 31, 1976 and at which either enhanced recovery operations began, or a significant alteration in producing patterns occurred, prior to September 1, 1976. The agency defined “enhanced recovery” in February 1976 to include gas or liquid injection operations. 41 Fed.Reg. at 4941. The definition of significant alteration in producing patterns, which came only as of September 1, 1976, swallowed up the concept of enhanced recovery, because the new definition included “the application of extraneous energy sources by the injection of liquids or gases into the reservoir.” 41 Fed.Reg. at 36,184. The agency recognized, however, that producing patterns might be altered before gas injection, and so added as an alternative definition of significant alteration “the increase of production allowables for any property that constitutes the unitized property.” Id.
      
      Because operators of units in this third category, formed after February 1, 1976, knew the definition of enhanced recovery when their units were formed, whereas “significant alteration” was defined only in September, the agency chose to apply the two concepts differently. Operators of units at which enhanced recovery operations began before September 1, 1976 were required to establish a unit BPCL as of the date such operations began. 42 Fed.Reg. at 4915. But operators of units at which no enhanced recovery operations began, but where a significant alteration in producing patterns occurred, before September 1, 1976, were allowed to wait until September 1, 1976 to establish a unit BPCL. Id.
      
      As a practical matter this meant that if an operator began gas or liquid injection — which would constitute both enhanced recovery and a significant alteration — the operator had to establish a unit BPCL as of that date. If there occurred only a shift in production allowables — which would constitute a significant alteration but not enhanced recovery — the operator could wait until September 1, 1976 to establish a unit BPCL.
      Both kinds of units within this third category benefitted only from those provisions of Section 212.75 in effect at the time the enhanced recovery project began or the significant alteration occurred. Id. In other words, such units were not allowed any measure of imputed new oil, but they were allowed to use the special unit BPCL rule and the provisions for imputed stripper well oil.
      In connection with its argument against retroactive application to it of the significant alterations test, Exxon complains that the FEA unlawfully discriminated by requiring operators of units formed after February 1, 1976 to establish a unit BPCL no earlier than September 1, 1976, even if a significant alteration in producing patterns occurred before that date. But the Hawkins Field Unit, under a legal obligation to establish a unit BPCL as of the date of its formation on January 1, 1975, was not similarly situated to a unit formed at a time, between February and September 1976, when the agency had expressly reserved fpr further comment and study the definition of the legal standard by which the obligation to calculate a unit BPCL would be established. See 41 Fed. Reg. at 4937. On the contrary, the agency’s decision to admit this small measure of relief to those who, when they formed their units, had acted with a view to the still nebulous standard, was eminently fair.
     
      
      . See discussion at pp. 832-33, supra.
      
     
      
      . To say that the agency extended the benefits of Section 212.75 to new units alone is imprecise. Units which, like the Hawkins Field Unit, were formed before February 1976, but at which, unlike the Hawkins Field Unit (see pp. 842-45, infra) a significant alteration in producing patterns occurred only after September 1, 1976, also could benefit from the favorable provisions of Section 212.75. See n. 33, supra. The FEA, explaining in Ruling 1977-2 the application of the significant alterations test to pre-existing units, wrote:
      All such units formed during or after 1972 were required to calculate a BPCL by aggregating the BPCL’s of all the participating properties at such time as significant changes in the units’ producing patterns occurred .... If no such alteration has occurred as of September 1, 1976, determinations of upper-tier and stripper well crude oil volumes may continue to be made on a lease by lease basis until such time as a significant alteration does occur, at which time the unitized property must be treated as a single property and a unit BPCL must be established. As of the time that a unit BPCL is established, the provisions of § 212.75 then in effect are applicable.
      
      41 Fed.Reg. at 4415 (emphasis added).
      The agency articulated no reasons for acting so generously towards such units when its stated purpose was only to encourage prospective unitization. See discussion at p.-, supra. One might speculate that because such units had not yet undergone a significant alteration in producing patterns, they faced a greater risk of dissolution than did units where significant and perhaps irreversible alterations had already occurred. The agency may have wished to provide particular incentives for the maintenancé of such units by holding out the prospect of greater rewards. But whatever the agency’s reasons, the issue of the reasonableness of extending the benefits of Section 212.75 to some units formed before February 1976 is not before the court. Even if it were, the court could at most strike down that small portion of Section 212.75 as an unjustifiable windfall to preexisting units. That decision would not affect the validity of the agency’s decision to provide incentives for the creation of new units while denying those incentives to pre-existing units like the Hawkins Field Unit.
     
      
      . On the other hand, had the FEA continued to treat all units as required by Ruling 1975-15, it would have violated Congress’s intent to provide further incentives for increased domestic oil production — in particular, to spur unitization and enhanced recovery projects.
     
      
      . The FEA’s sliding scale of incentives, though complex, reasonably carried out the conflicting objectives of the EPCA. The FEA offered strong incentives — a special unit BPCL rule and provisions for imputed stripper well oil — to those considering unitization in February 1976. It added yet another incentive — imputed new oil — seven months later, for those still hesitant to unitize. It offered the least relief — a 1975 BPCL base period and the retroactive rescission of Ruling 1975-15 — to those units least in need, those formed before February 1976 and unlikely to dissolve given the participants’ substantial stake in them as evidenced by a significant alteration in producing patterns having already taken place.
     
      
      . In Ruling 1977-2, the FEA said it would, “on a case by case basis, permit unit operators to justify the establishment of the date of significant alteration in producing patterns in [pre-existing] units on reasonable bases other than those specified by the present definition.” 41 Fed.Reg. at 4415. But Exxon has never proffered any alternative basis to the agency, contending instead that the agency’s purported relaxation of enforcement policy is invalid and that only Section 212.75 applies to it. Consequently, the question of what might be a reasonable alternative basis to justify the establishment of the date of significant alteration is not before the court. However, Exxon’s suggestion to this court that a significant alteration be determined on the basis of changes in the field’s underground drive mechanism is not such a reasonable alternative basis. Even case by case determinations must be workable, and doubtless few petroleum engineers would agree on the amorphous “significance” of voluminous data on geological transformations. For the same reason, it would serve no purpose for this court to hear the “expert” testimony Exxon would offer. As Exxon itself vigorously asserts, “significant alteration” was not a term of art in the oil industry, but was, in Exxon’s words, “cut from whole cloth” by the agency. See Def.Mem. at 61-62. Accordingly, it would be futile for the court to hear petroleum engineers testify as to a legal conclusion they have no expertise to make: what alterations in producing patterns were “significant.”
      Exxon’s argument that a trial is necessary to resolve conflicting factual contentions as to when a significant alteration in producing patterns occurred is mistaken. As the TECA wrote in Grigsby v. DOE, supra, 585 F.2d at 1079, “ ‘[t]o preclude summary judgment the disputed facts must be material and must affect the outcome of the litigation.’ ” Grigsby had argued that he should be allowed to establish that his second well had been drilled on a different lease within the unit. See p. 833, supra. The TECA found that fact immaterial, because Grigsby’s unitized property had to be treated as one property even if the second well had been drilled on a different lease within the unit. 585 F.2d at 1079 n. 17. In the same manner, Exxon’s insistence that it be allowed to establish that the Hawkins Field underground drive mechanism was not altered until sometime in 1979 is irrelevant. As a matter of law, a significant alteration occurred when there was either a transfer of production allowables among leases within the unit or gas injection, regardless of when the field’s drive mechanism was transformed. Accordingly, there exists no genuine dispute as to issues of material fact and summary judgment is appropriate.
     
      
      . Exxon’s barrage of attacks on the agency’s amendments to the regulations in February and September 1976 — decrying their retroactive application, their discriminatory effect, and the rigor of their standards — is puzzling. If the court were to uphold Exxon’s challenges, at most the court could invalidate all or part of Section 212.75 and the significant alterations test as applied to pre-existing units. But that would not leave a vacuum. Instead, there would remain to apply to the Hawkins Field Unit only Section 212.72, unembellished by either Ruling 1975-15 (rescinded ab initio) or by the significant alterations test. But the TECA has held in the Pennzoil case that implicit in the property regulation itself is the unit property rule, the requirement that a unit BPCL be calculated as of the date of unitization. 680 F.2d at 176. Consequently, if Exxon’s attacks were to succeed, it would still find itself in the position it is trying to escape. Exxon apparently seeks the best of all possible worlds. It would like the court to uphold the rescission of Ruling 1975-15 and to rewrite the rule which replaced it to suit Exxon’s practices at the Hawkins Field, in effect leaving it free of any rule at all. The 1976 amendments to the oil price regulations cannot reasonably be read that way.
     
      
      . Exxon in fact understood the regulation to require unit-wide accounting much earlier. Interpreting the September 1976 amendments to the regulations, including the definition of significant alteration, one Exxon manager wrote: “This exception is of no benefit to Hawkins because of the transfer of allowables provisions. It appears that this regulation will require that Hawkins begin unit calculations on February 1, 1975.” PX 231 at 5. (Memorandum from H.T. Wright to S.W. Abel, August 23, 1976).
     
      
      . The figures concerning transfer of production allowables among constituent properties in the first five months of 1975 appear below. See Plaintiff’s Appendix of Charts and Graphs, C.
      Month (1975) Number of leases at which production increased above prior allowable Increase in production (barrels) Number of leases at which production decreased Decrease in production (barrels)
      Jan. 65 319,654 137 294,536
      Feb. 56 316,027 145 320,711
      March 51 442,878 150 417,553
      April 45 441,548 153 446,447
      May 53 546,959 148 540,503
     
      
      . Exxon’s own measurements and analysis of production shifts at the Hawkins Field show the dramatic changes that occurred in 1975. Studying the question only days after the February 1976 amendments were issued, Exxon engineer L.D. Carlson concluded that almost 20 percent of 1975 production had shifted across lease lines, almost two and one-half times as much as had shifted in either 1974 or 1973. PX 200 (February 6, 1976).
      Two other Exxon engineers were assigned the task in mid-1975 to determine why volumes of “Phase IV” or new oil at the Hawkins Field had exceeded earlier forecasts. They concluded that, of the excess, “[approximately 21.2 MB/D is due to the redistribution of production on Exxon-operated leases. Formation of the unit has enabled us to reduce production from those leases with high gas-oil or water-oil ratios. This results in increased production from those leases in the fíush part of the field and correspondingly their Phase IV volumes." PX 126 at 1 (Report by L.D. Roeder and J.B. Holmes, June 20, 1975) (emphasis added).
     
      
      . Exxon argues that its re-injection into the Hawkins Field of natural gas taken from the field was outside the definition because the gas was not an “extraneous” energy source. See Def.Opp. at 182-83. The FEA made clear, however, in the preamble to the February 1976 amendments, that “extraneous” included gas recycled from the reservoir itself. The agency explained:
      In response to the proposed definition, many comments expressed concern that the language “from extraneous sources” might preclude some types of enhanced recovery projects that recycle reservoir gas .... The fact that the injected fluids or gases may have originated in the reservoir is irrelevant as long as they are injected by an extraneous energy source.
      41 Fed.Reg. at 4938.
     
      
      . Total annual gas injections at the Hawkins Field from 1972 to 1975 were.as follows:
      Year Total (mcf)
      1975 13,945,000
      1974 7,652,916
      1973 7,229,119
      1972 6,897,093
      
        See PX 210 at 2, 5; PX 109 at 2.
     
      
      . Statements by Mr. Langdon were also the cornerstone of the estoppel defense raised by Pennzoil. See Pennzoil Co. v. DOE, supra, 680 F.2d at 166. The TECA in Pennzoil on strikingly similar facts to those before this court declined to estop the government, writing that “[t]here is simply no basis in the circumstances of the present case to find unreasonableness, unfairness, or any other element of estoppel in applying the agency interpretation to the relevant period in question here.” Id. at 176. That court added, moreover, that “The ‘interpretations given by an individual member of a Board or by its attorney is not, we think, to be taken as that official kind of interpretation to which courts must pay attention.’ It is ‘absurd’ to rely upon the unsupported opinions of agency staff attorneys when trying to divine the meaning of a regulation.” Id. at 161-62 n. 8 (citations omitted).
     
      
      . See J. Langdon, FEA Price Controls on Crude Oil and Refined Petroleum Products, 26 Annual Oil & Gas Institute of the Southwestern Legal Foundation 55, 66 (1975).
     
      
      . Not even Pennzoil, the direct recipient of Langdon’s purported assurances in July 1974, ventured to follow Exxon’s course in ignoring Ruling 1975-15, but instead applied a unit BPCL at its Walker Creek Unit as of September 1, 1975. See Pennzoil Co. v. DOE, supra, 680 F.2d at 160.
     
      
      . Further evidence that Exxon could not reasonably feel reassured is found in Exxon’s felt need to return to the agency again and again in the wake of Ruling 1975-15 to push for clarification or modification of its then clear legal obligation to treat the Hawkins Field as a single property. See Def.Opp. at 30-46, 49-61. Had Exxon already obtained the kinds of assurances which might support a claim of reasonable reliance, it would not have needed to return to the agency with such frequent inquiries and comments, all the while refusing, however, to ask for a formal written interpretation. But of course Exxon obtained no such assurances in the tumultuous months following Ruling 1975-15. As Exxon itself describes, it was “pushing [DOE officials] not only to say they didn’t take exception to what we were doing, but to come out with new regulations that would clearly spell out what we were doing was in accordance with the regs.” File Dep. at 127. But Exxon came away each time unsatisfied: it was “distressed with the slowness in which they failed to respond.” Id.
      
      Indeed, Exxon’s internal memoranda from that time show that the agency was at most noncommittal in its responses to Exxon’s repeated requests. Agency personnel were “completely unsympathetic” to Exxon’s plight. PX 159 (Memorandum from M. Krause, Jr. to files, Nov. 4, 1975). FEA counsel reportedly did not take exception to Exxon’s accounting practices, “but at the same time, they did not endorse such action.” PX 169 at 3 (Memorandum from Fred W. File to Exxon Price and Wage Coordination Committee, Price Subcommittee, Nov. 26, 1975). When “pressed ... for specifics”, FEA officials were “vague on details as to how new oil could be calculated in units like Hawkins.” PX 180 (Memorandum from Fred W. File to O.L. Luper Dec. 31, 1975). Fred File concluded that Exxon could continue to make payments to royalty owners based on lease-by-lease accounting, but cautioned that “there is a risk that this method may result in a disallowance of costs and a problem in effecting recovery of overpayments to third parties.” PX 153 (Memorandum from Fred W. File to Exxon Price and Wage Coordination Committee, Price Subcommittee, Oct. 30, 1975). That risk lingered even after the September 1976 amendments to the regulations, when Mr. File wrote that “all doubts as to the proper method of computation before September 1, 1976 have not been removed” despite the fact that Peter Luedtke, FEA staff attorney, “did not take any exception to my interpretation and that it is his understanding that prior to September 1, 1976 upper tier oil may be computed on a tract-by-tract basis, provided the unit meets the test of the prior regulations relating to implementation of enhanced recovery techniques and significant alteration of producing patterns.” The risk lingered because “while Mr. Luedtke agrees with my interpretation of the August 20, 1976 clarifications as applied to Hawkins, his views are not official FEA interpretations.” PX 236 at 4 (Memorandum from Fred W. File to Fred M. Perkins, October 1, 1976) (emphasis added).
     
      
      . Schweiker v. Hansen, 450 U.S. 785, 788, 101 S.Ct. 1468, 1470, 67 L.Ed.2d 685 (1981) (“This court has never decided what type of conduct by a government employee will estop the government from insisting upon compliance with valid regulations governing the distribution of welfare benefits.”); Montana v. Kennedy, 366 U.S. 308, 315, 81 S.Ct. 1336, 1341, 6 L.Ed.2d 313 (1961) (“[W]e need not stop to inquire whether, as some lower courts have held, there may be circumstances in which the United States is estopped to deny citizenship because of conduct of its officials.”). Interestingly, the Court in Schweiker v. Hansen declined to estop the government from denying Social Security benefits to an applicant who had been misinformed by a government agent, writing that “at worst, [the agent’s] conduct did not cause respondent to take action, or fail to take action, that respondent could not correct at any time.” 450 U.S. at 789, 101 S.Ct. at 1471 (citations omitted). So, too, could Exxon have corrected its accounting practices at the Hawkins Field at any time.
     
      
      . See, e.g., Portmann v. United States, 674 F.2d 1155 (7th Cir.1982); Santiago v. Immigration and Naturalization Service, 526 F.2d 488 (9th Cir.1975); United States v. Lazy FC Ranch, 481 F.2d 985 (9th Cir.1973); cf. Investors Research Corp. v. SEC, 628 F.2d 168, 174 n. 34 (D.C.Cir.1980) (“The fundamental principle of equitable estoppel applies to government agencies, as well as private parties.”). Courts have employed various devices to get around the traditional rule, such as by distinguishing between offensive and defensive estoppel, or between proprietary and sovereign functions of the government, or by adding an additional prerequisite that the government engage in “affirmative misconduct.” See Note, Equitable Estoppel of the Government, 79 Colum.L.Rev. 551, 555 (1979) and cases cited therein. Some courts have abandoned the device of categorical exceptions to the traditional rule and have held, in simple but opaque language, that “the estoppel doctrine is applicable to the United States where justice and fair play require it.” United States v. Lazy FC Ranch, supra at 988.
     
      
      . At a meeting of interest owners on September 10, 1974 in reply to a question “as to how the Operator planned to account for new, released and stripper oil”, an Exxon representative outlined Exxon’s plans to account for production on a lease by lease basis to determine total unit production in each category, but to allocate volumes of new, released and stripper oil to each tract pro rata, based on tract participation. PX 85 at 11 (Minutes of meeting of Exxon interest owners, September 10, 1974).
      After Ruling 1975-15 was issued, Exxon simply informed royalty interest owners that “Exxon has elected to compute exempt oil as it did before the ruling was issued.” PX 145 (Letter from Exxon to Hawkins Field interest owners, Oct. 20, 1975).
      Similarly, after the September 1976 amendments to the oil price regulations Exxon peremptorily informed other interest owners that in accordance with the new rule, “[w]e have ... established a single base production control level for the Hawkins Field Unit based on old oil produced and sold during the twelvemonth period from September 1, 1975 through August 31, 1976.” PX 241 (Letter from Exxon to Hawkins Field interest owners, Oct. 20, 1976).
     
      
      . Exxon’s argument that it cannot be held liable for overcharges on the 5 percent of Hawkins Field production owned and taken by Texaco was rejected in Sauder v. DOE, supra, 648 F.2d 1341. Sauder argued, like Exxon, that he could not be found responsible for the overcharges on the share of production received and sold by other interest owners. The TECA rejected Sauder’s argument and held him, as operator and animating force of the unit, responsible for all overcharges from the leases, regardless of whether Sauder himself received all of the monies illegally obtained. 648 F.2d at 1347-49.
     
      
      . See, e.g., Interpretation 1975-3, 42 Fed.Reg. 23,724; 23,726 (1977).
     
      
      . See PX 304 at 11-12 (Letter from FEA Administrator Frank Zarb to Sen. Henry Jackson, December 6, 1975).
     
      
      . To the extent Exxon suffered as one of the 200 domestic refiners whose costs were inflated by the Hawkins Field overcharges, Exxon is barred by the doctrine of “unclean hands” from receiving equitable restitution of any of the overcharges. See Citronelle-Mobile Gathering, Inc. v. Edwards, 669 F.2d 717, 723 (Em.App. 1982).
     
      
      . On November 23, 1982 and on January 20, 1983, certain refiners and independent retailers, respectively, filed motions to intervene in this action, arguing that they as victims of the Hawkins Field overcharges were entitled to any recovery DOE might obtain. The preceding discussion shows, however, that due to the workings of regulations applicable throughout the oil industry, from producer to retailer, the real victims are the unidentifiable millions of ultimate consumers of petroleum products. Accordingly, the motions to intervene are denied.
     
      
      . To the extent that the utilities which purchased overpriced oil from NEPCO were able under state public utility regulation to pass through increased operating costs to customers, presumably those same state regulatory bodies could act to ensure that the effects of the refunds received by those utilities from the escrow account would also eventually reach the ultimate consumer. Importantly, no corresponding mechanism exists in the case before the court.
     
      
      . The “energy conservation programs” identified in Section 155(e)(2) are: (1) the program under Part A of the Energy Conservation in Existing Buildings Act of 1976, 42 U.S.C. § 6861 et seq.; (2) the programs under part D of title III of the Energy Policy and Conservation Act, 42 U.S.C. § 6321 et seq.; (3) the program under part G of title III of the Energy Policy and Conservation Act, 42 U.S.C. § 6371 et seq.; (4) the program under the National Energy Extension Service Act, 42 U.S.C. § 7001 et seq.; and (5) the program under the Low-Income Home Energy Assistance Act of 1981, 42 U.S.C. § 8621 et seq.
      
     
      
      . Accordingly, the escrow fund established pursuant to this court’s order shall of course not be subject to the provisions of subsection (e)(1) of Section 155 which limit the monies the Secretary of Energy may disburse to $200 million — received in settlements, not pursuant to judicial order — and which require a finding that the funds to be disbursed “are not likely to be required for satisfying claims of potential claimants ...” and that “the use [of funds] under this section would be consistent with the remedial order or consent order covering such funds.” Section 155 shall otherwise apply in its entirety under this court’s order as the set of terms and conditions governing DOE’s handling of the escrow account established to receive restitution payments from Exxon.
     
      
      . The unit BPCL and cumulative deficiency for January 1975 came from information given to Texaco, a Hawkins Field interest owner, in early July 1975. PX 117 (Letter from H.M. Krause, Jr. to Texaco, Inc., April 2, 1975). Data on the amounts of lower and upper-tier or exempt oil claimed by Exxon was derived from statements given by Exxon to Mobil, another Hawkins Field interest owner. PX 284.
     
      
      . See Pltf.Mem. at 135-39.
     
      
      . In connection with their cross-motions for summary judgment, the parties filed more than 1,000 pages of memoranda, supported by fourteen volumes of appendices containing approximately 600 exhibits.
     
      
      . Other courts which have found regulatory violations and ordered restitution of overcharges have nevertheless refused to assess civil penalties and often for reasons similar to those given above. See, e.g., Sauder v. DOE, 4 Energy Mgt. (CCH) ¶ 26,157 (D.Kan.1980), aff'd, 648 F.2d 1341 (Em.App.1981) (award of penalties inappropriate because regulatory definition of “property” confusing and agency made no finding of gerrymandering); Citronelle-Mobile Gathering, Inc. v. O’Leary, 499 F.Supp. 871 (S.D.Ala.1980), aff'd sub nom. Citronelle-Mobile Gathering, Inc. v. Edwards, supra, 669 F.2d 717 (penalties inappropriate because, inter alia, violators clearly explained their behavior to Commerce Department).
     