Full opinion text
OPINION OF THE COURT THEIS, Chief Judge. These multidistrict litigation (MDL) cases now come on for final decision of the Court. Trial of these cases, after extensive pretrial proceedings and litigation involving two appeals by the defendants to the Temporary Emergency Court of Appeals (TECA), was finally held to this Court from January 19, to February 6, 1981. After considering the evidence presented at trial, and after studying the briefs of the parties, and reviewing the appellate decisions in the consolidated cases, the Court enters this opinion. A brief review of the pretrial proceedings may be illuminating and certainly, in this Court’s opinion, accounts for the singularly bellicose and adamant efforts of the Government, through their various counsel, to resist trial on the merits of the issue of law common to all of these cases. Originating as a single case to enjoin as illegal the governmental enforcement of the regulations of the then Federal Energy Administration (FEA), now Department of Energy (DOE), prohibiting those plaintiff oil companies from including fluid injection wells in a well count to establish pricing levels for crude oil produced from stripper wells on plaintiffs’ leases, under a stripper well exemption in the legislative act, other cases were soon filed which were consolidated into one action. These cases were ruled on by this Court in its decision reported in Energy Reserves Group, Inc. v. Federal Energy Administration, 447 F.Supp. 1135 (D.Kan.1978), which held FEA Ruling 1974-29, excluding the count of injection wells, was legislative in nature rather than interpretive of the regulation, and therefore void. This decision was appealed to the Temporary Emergency Court of Appeals, resulting in a reversal of the Court’s decision in a 2 to 1 decision of the three learned judges of TECA, in which each judge rendered a separate opinion. This decision is reported as Energy Reserves Group, Inc. v. Department of Energy, 589 F.2d 1082 (TECA 1978). In short summary, the TECA majority held valid Ruling 1974-29 as a reasonable interpretation of the regulation implementing the statutory stripper well exemption, and remanded for trial the issue of whether the regulation was valid under the intent of Congress as expressed in the statute and its legislative history, and whether the regulation was arbitrarily and capriciously adopted by the administrative agency. By this time case litigation was burgeoning on the identical issues in many other federal court districts and forwarded to this district and combined for disposition of this Court as multidistrict litigation under order of the Judicial Panel of Multidistrict Litigation in June, 1979, reported as In re Dept. of Energy Stripper Well Exemption Litigation, 472 F.Supp. 1282 (1979). Governmental resistance to this Court’s efforts to get the case ready for trial and its unilateral insistence that the litigation had been terminated by TECA in the 1978 appeal, resulted in yet another appeal to mandamus this Court, reported as Duncan, Sec’y. of Energy v. Theis, Chief Judge, 613 F.2d 305 (Em.App.1979). TECA rejected the government counsels’ contention that TECA had decided this case in its prior opinion, and that there was no subject matter for litigation and decision. After continued resistance by the government at every stage of the pretrial discovery proceedings, trial finally began on January 19, 1981. The government’s theory of absolutism in the rightness of its conduct, its refusal to recognize the adversarial aspect of our legal system, and general truculence, are aptly illustrated by an early assertion in its Post-Trial Brief, wherein it is stated: “Although the trial held in this matter was extremely improper and unnecessary ...” Generally, the whole history of this litigation has been the government’s premise that its administrative decisions are judicially unreviewable, and the minds and actions of the administrative decision-makers may not be probed to determine the basis for such action. This position has been vigorously and adversarily disputed by an array of competent counsel from some of the leading law firms around this nation. As a result of an earlier injunction order in this case there has been accumulated in trust under court supervision a fund approximating one billion dollars, which awaits judicial distribution upon the termination of this litigation. The issues now before the Court in the trial and for decision are: (1) whether the regulation itself, interpreted by TECA as excluding injection wells from the well count, was reasonable and valid within congressional intent of the statutory exemption; and (2) whether the promulgation of the regulation (C.F.R. 154(s)), was arbitrary and capricious. Since the inception of this litigation these two issues have always been the principal underlying legal points for ultimate decision. To better understand the parameters of this dispute the Court considered engineering facts underlying crude oil production generally and secondary recovery in particular, various state procedures governing secondary recovery, and the treatment of injection wells in secondary recovery projects under certain federal programs. The Court’s conclusions with respect to these matters constitute the first portion of this opinion. The Court then sets out the controlling statutes, regulations and ruling. This section is followed by the holding of this Court that Congress intended injection wells to be included in the well count, and a lengthy explanation as to how the Court reached this conclusion and why the DOE’s contrary position is not binding on the Court. The Court then concludes that even if the statute did not mandate including injection wells, the manner in which the Department excluded the wells from the well count was arbitrary and capricious. For those reasons, the Court has found that the stripper well exemption regulation, as interpreted by Ruling 1974-29, is invalid and must be struck down. The Court, in this opinion, has also ruled on certain post-trial motions, and these rulings are contained in part V of this opinion and order. I. FACTUAL AND REGULATORY BACKGROUND The organic theory of the origin of oil is accepted by 99.9% of engineers. (Whiting, T. 132033.) This theory holds that oil came from organisms that lived in and adjacent to inland seas during geologic times. Plant and animal residues were deposited in these inland seas and over time were covered with sediment and subjected to great heat and pressure. (Whiting, T. 139.) This heat and pressure “destructively distilled” those organisms and generated petroleum. (Id.) This petroleum then is believed to have migrated from the place it originated, the source beds, through very small pores in the underground rock until it was caught in some kind of geologic “trap” which prevented further migration. Three of these geological traps are illustrated in P.X. 1-14 through P.X. 1-17. Oil caught in such a trap constitutes an oil reservoir. The rock formations which contain this oil must possess two characteristics to allow the oil to move within the reservoir. The rock must have “porosity” and “permeability.” Porosity is an indication of the storage capacity of a rock. (Whiting, T. 140.) Porosity must be present to have an accumulation of oil. (Whiting, T. 141.) Porosity is the measure of the microscopic pore spaces between the grains of sand in the rock formation. An artist’s conception of this characteristic is shown on P.X. 1 — 9. Permeability occurs where microscopic pore spaces are interconnected in a manner such that oil can move through the rock. The rock must have permeability in order to transmit oil. Samples of the type rock which contain the oil in the underground reservoirs are shown in P.X. 170-171. The production of oil is the process of forcing the oil from the rocks in which it is found into a well bore for transportation to the surface. Primary recovery is an oil recovery process which utilizes the natural energies in a reservoir to displace the oil from the reservoir into the well bore of an output well. (Whiting, T. 154.) The three major forms of natural energy within an oil reservoir are the “gas cap drive,” the “natural water drive,” and the “solution gas drive.” These three naturally occurring drive forces are illustrated in P.X. 1-20, 1-22 and 1-21. “Gas cap drive” occurs where a quantity of undissolved gas exists within a reservoir. When a recovery well is completed in the formation, the pressure from the free gas forces the oil into the well bore through which it is transported to the surface. As the recovery continues, the gas cap expands to displace oil in the rock pores and force the oil into the recovery well bore. (Whiting, T. 160.) A natural water drive reservoir occurs where there is a water reservoir underlying the oil reservoir. In this situation, as oil is withdrawn from the reservoir, the water underlying that oil forces itself up, displacing oil as it expands into the oil bearing formation, forcing the oil into the recovery well bore. Solution gas, or dissolved gas drive, is the third primary drive mechanism. Because of the high pressures naturally occurring within an oil reservoir, natural gas is forced into solution in the oil. When a recovery well is completed the reservoir pressure is reduced, and the dissolved gas begins to come out of solution. The process is the same as when a bottle of a carbonated beverage is opened. When the cap is taken off, some of the dissolved carbon dioxide within the beverage comes out of the liquid. When the gas in the reservoir comes out of solution, it expands and forces oil out of the pore spaces in the rock and into the well bore. (Whiting, T. 155-56.) The point at which dissolved gas begins to come out of solution is referred to as the “bubble point.” There is a limit to the amount of oil that can be recovered utilizing the naturally occurring reservoir energy. A natural gas cap or natural water drive allows for the recovery of 20 to 50 percent of the oil contained in the reservoir. (Whiting, T. 169, 170.) A solution gas drive mechanism allows for the recovery of 15 to 25 percent of the oil contained in the reservoir. (Whiting, T. 169; O’Neal, T. 268.) Secondary recovery is a recovery process in which the naturally occurring reservoir energy is augmented by additional energy in the form of matter injected into the producing formation. (Whiting, T. 163.) A water injection system increases the production of oil in two ways. First, the injection helps to maintain the pressure within the reservoir. The injection process provides the power to move oil through the reservoir to the recovery well. Second, water injected into an oil reservoir physically displaces the oil and moves it toward the recovery well. Water injection has been recognized for about fifty years as an accepted efficient method of augmenting oil recovery. (Whiting, T. 164.) A water injection recovery system requires at a minimum two oil wells. One well is the injection well and is used as a vehicle to inject water into the oil formation. The other well is the recovery well and is used as the conduit to remove the oil forced into the well bore. Typically, an injection well is a former recovery well which has been converted to injection. Physically, there is little difference between the structure of an injection well and the structure of a recovery well. Plaintiffs’ Ex. 35, which is attached to this opinion as Appendix “A,” shows the similarity of physical structure between a typical injection well and a typical recovery well. From an engineering standpoint, there is an appropriate time at which to initiate waterflooding so as to maximize recovery from a reservoir. (Whiting, T. 172.) The optimum time, however, the “bubble point,” is that time at which the dissolved gas in the oil starts to come out of solution. Delay in initiating injection past the “bubble point” decreases ultimate recovery, since the mobility of the oil decreases. (Whiting, T.177.) Recovery lost because of slow initiation of secondary recovery can never be recaptured by use of primary recovery or waterflooding. Delays past the optimum point in initiating waterflooding cause an absolute decrease in recoverable oil reserves. The early initiation of injection also results in less recovery than in a properly waterflooded field, since the natural displacement power of the dissolved gas is wasted. (Whiting, T.173, 175.) The increased recovery resulting from water injection is shown on P.X.. 1037 to P.X. 1-40. The increased recovery is normally expected to be from 67 to 150 percent of the amount of oil recovered using primary methods. (O’Neal, T.268, 311.) Institution of a secondary recovery project using waterflooding is a complex and expensive undertaking. Before initiating waterflooding, a producer must determine whether an oil-bearing formation is suitable for secondary recovery. Dissolved gas drive reservoirs seem to be the best candidates for secondary recovery, since the natural energy is more quickly dissipated, leaving more oil in place. (Platt, T.698-99; Whiting, T.170.) The engineers and geologists must make laboratory studies to determine if additional oil could be recovered by injection of fluid into the reservoir. (Platt, T.700.) If it is found that water injection would be beneficial, then the entire oil field must be “unitized.” Different portions of an oil field may be leased by different companies. Efficient waterflooding requires that the entire reservoir be under a single plan. Unitization is the process through which the various leaseholders are brought into one entity for the exploitation of the field. (O’Neal, T.246-47; Platt, T.703.) A producer must obtain a source of water to inject into the reservoir. Fresh water might be obtained from a river, as was done in the Salem Unit (Eley, T.400), or from wells, as was done in the Northwest Cha Cha Unit (Shearin, T.544). Salt water might be obtained from a variety of sources (Platt, T.701). While the costs of obtaining the water vary, they may be high. The water from the water supply must be chemically treated and filtered to be suitable for injection. (See P.X. 28.) Injection of water which is not compatible with water already present in a reservoir could cause a plugging of the pore space in the oil-bearing rocks, which in turn could prohibit continued injection, or otherwise be detrimental to the recovery process. (Platt, T.708; Burt, T.1035-36.) The water is injected at high pressures which could vary between 1000 p.s.i. and 6000 p.s.i. (Platt, T.709.) These injection pressures require large injection pumps. (McConnell, D.18.) (See, P.X. 41, P.X. 29-2.) Wells to inject the water must either be drilled, or recovery wells must be converted to injection wells. Costs of drilling an injection well are comparable to the costs of drilling a recovery well. (McConnell, D.17.) The conversion of wells from recovery wells to injection involves first performing remedial work on the recovery well. (Platt, T.710; P.X. 35.) Next, tubing is placed in the well casing and a packer is placed around the bottom of the tubing. (Platt, T.711.) A well head sufficient to withstand the high pressures is installed on the top of the well. (Id.) Various patterns of the placement of injection wells can be used in a secondary recovery project. The pattern which is selected depends upon the geologic characteristics of the reservoir, such as the permeability of the rock, the reservoir pressure and the oil characteristics. (O’Neal, T.269.) Recognized patterns include the peripheral flood pattern (O’Neal, T.270; P.X. 7), the five spot flood pattern (O’Neal, T.270-1; P.X. 8), and the inverted nine spot pattern (O’Neal, T.271; P.X. 8). The five spot and the nine spot pattern result in an injection well to recovery well ratio of one to one and one to three, respectively. (O’Neal, T.270-71.) Long pipelines for transporting the water from its source to the treatment plant to the injection pumps and then to the injection wells may be required. These pipelines may need to be specially treated to withstand corrosive forces and the high pressures associated with the injection process. (Platt, T.709, 710.) Other facilities may be necessary for separation of oil from the water lifted by the recovery wells. Facilities may be necessary for preparing recovered water for reinjection, or disposing of recovered water in some other manner. The important contribution that oil recovered through waterflooding operations makes to the oil needs of this country, and the necessary role of injection wells in that process, is undisputed. In 1973, approximately one billion barrels of oil were produced through the injection process. (Platt, T.722-23.) Thirty to fifty percent of all oil produced in the United States was attributable to fluid injection projects. (Platt, T.743.) The injection well is a necessary and indispensible ingredient in the secondary recovery process. Professor Whiting, on cross-examination, was asked: “Q. When you testified that an injection well is a producing well or a well that produces crude oil, didn’t you mean in fact what you means is that it assists in the emitting of oil by the production well, the recovery well, at the surface of the earth? A. I will say once again — and I guess other times if you insist on it — I teach my students that there is no question about the fundamental premise that there are three necessary parts of a secondary recovery system. Elements of it. The reservoir, the input well, and the production well — using your words. All of those are essential ingredients, and I think I should answer your question by saying without an injection well in secondary recovery there would be no oil production into the well bore of the production well you are talking about. It is an essential ingredient of the system. Without an injection well you don’t have secondary recovery. This has been recognized I know for 40 years.” (Emphasis added.) (Whiting, T.193.) The Government expert, Mr. Burt, agreed with Professor Whiting, as follows: “Q. Right. And, therefore, wouldn’t you agree that an injection well is an absolute and necessary essential part of a secondary recovery water-flood producing system? A. I don’t think I ever said otherwise. I’ve always said it was essential to have an injection point.” (Burt, T.1062-63.) Mr. O’Neal testified that injection wells and recovery wells are “hydraulically linked.” He explained: “A. ‘Hydraulic linkage’ is merely a form of reservoir communication in one sense. As I mentioned before, we started out with a tiny sample of rock that is in a reservoir that is in a stannic conduit, the pore spaces, but those things are connected, they are not efficient pipelines, but they are connected from one end of the reservoir to another. And that is what you are able to utilize in conducting a waterflood, is that you use that communication, and then by injecting water into the well on the left you force that water out into the oil-bearing formation, and that provides the energy to move the oil and the water, and it also is sweeping the oil out of those pore spaces. Q. All right. Mr. O’Neal, as I understand it, then, there is an hydraulic linkage between the injection well here and the recovery well here, is that correct? A. That is correct. Those two wells are used in pairs.” (O’Neal, T.273-74.) The relationship described is rather like a pipeline with the injection well acting as one end and the recovery well acting as the other end. Nothing can flow out the one end of the pipeline in the absence of something being forced into the other end. An injection well provides the force. On cross-examination the witness clarified this relationship: “Q. Now you testified in response to a question by Mr. Beck, the summary question, that producing, that injection wells, are wells that produce crude oil. You mean by that, do you not, that they help produce crude oil, isn’t that a fact? A. No. As I said for me the injection well, number one, is a well that produces crude oil, like that which was demonstrated on the model— A. All right. What I said was that an injection well forces, by the use of water, puts energy in the reservoir, and displaces oil through the reservoir and up the recovery well. And, I said more than ‘assist’ — I said it was the prime mover, because if I did not put that injection well in, I would have no more oil production.” (Emphasis added.) (O’Neal, T.351-52.) Mr. Eley testified similarly: “A waterflood, certainly a waterflood, such as the Salem Unit — and this unit is typical of a successful waterflood unit — I can see it as a hydraulic system, you inject water into the injection wells, and put energy in the formation which moves oil and water to your recovery wells where you recover. In the absence of water injection, you would certainly, in this field, you would have no production at all. And today, today as of October 1, 1980, our injection program has resulted in the production of an additional 118 million barrels of oil, and will ultimately produce an additional 138 million barrels of oil. Now, this is, again, oil that would not be produced in the absence of injection wells. Injection wells are an essential part of your injection operation, and certainly in this sense injection wells do produce crude oil.” (Eley, T.434.) All of these principles were clearly and graphically demonstrated through the model of the oil reservoir. Movies of this demonstration were submitted as P.X. 175 and P.X. 176. The defendant did aptly point out that other types of wells are present on oil leases. No other type of well, however, contributes to the recovery process in the manner that both injection and recovery wells do. These are the only two types of wells which cause oil to flow within the reservoir. In many states, the entire process is heavily regulated. The materials submitted by the plaintiffs show that California, Colorado, Illinois, Kentucky, Michigan, Nebraska, New Mexico, Texas, Utah and Wyoming, all require producers to obtain permits prior to drilling a well for injection purposes. All of these states and Arkansas, Kansas, Montana, and Oklahoma require application and approval prior to instituting water injection. The approval necessary to institute waterflooding seems to be obtainable only after furnishing extensive studies on the feasibility of waterflooding. In Kansas, for example, an application to inject must show: “(1) the location of the intake well; (2) the location of all oil and gas wells, including abandoned and drilling wells and dry holes, and the names of landowners and lessees within one-half mile of the intake well; (3) the formation from which wells are producing or have produced; (4) the name, description and depth of the formations to be flooded; (5) the openhole depths of each formation to be flooded; (6) the elevations of the top of the oil-or-gas-bearing formation in the intake well and the wells producing from the same formation within one-half mile radius of the intake well; (7) the log of the intake well or such information as is available; (8) descriptions of the intake well casing; (9) descriptions of the liquid, stating the kind, where obtained and the estimated amounts to be injected daily; (10) the names and addresses of the operators notified of the application and the date that such notice was given; (11) such other information as the commission may require to ascertain the flooding may be safely and legally made.” Kan.Admin.Reg. No. 82-2-502. Other states have similar requirements. See, e. g., Rule 401, Rules and Regs, of Neb. Oil and Gas Comm.; Rule 228.3, Gen.Rules and Regs, of Oil and Gas Comm, of Montana. See also, P.X. 48, which is form H-l of the Texas Railroad Commission and is required to be completed prior to initiation of injection. These natural and regulatory barriers to the institution of waterflooding render the process quite expensive. Even the defendant’s expert engineer acknowledged: “The cost of a waterflood system is more than primary.” (Burt, T.1073.) This fact was affirmed by other experts who testified: Shearin, T.536; McConnell, D.15 — 20; Platt, T.700-04. Moreover, as aptly pointed out by the Government’s engineer, water injection is subject to the risk of failure. (Burt, T.1033, 37; G.X. G2-A through G2-E.) State agencies have afforded injection wells special treatment in proration programs, to insure that their contribution to the production process is recognized. One of the goals of a system of proration or allowables is to maximize the ultimate recovery from each field, thereby preventing waste and conserving oil. (Coker, T.598; Baumel, T.663.) This Court was treated to an extensive lesson in the method allowables are determined in Texas. The actions of the Texas regulators, the Texas Railroad Commission, are of particular interest since that oil rich state accounts for approximately one-third of the total oil production in the forty-eight continental United States. (Platt, T.723; Coker, T.624.) Mac Coker, who served the Texas Railroad Commission for 28 years, Jack K. Baumel, who worked for the Commission for 15 years, and designed the system of yardstick allowables used in Texas, and Bob Harris, who currently is director of the Oil and Gas Division of the Commission, provided the Court with a full picture of the functions of the allowable system in Texas. No individuals could possibly be more qualified to testify about the Texas practices than these three individuals, and their credibility was unsullied. To establish an allowable for a water flood project, each well must undergo a test prior to injecting water into the formation. This test is required of all wells which are either converted from recovery wells or drilled as injection wells. (Coker, T.608.) The test required determines how much oil the well can yield in a twenty-four hour period. Thus, even if a well was drilled to be operated as an injection well, the operator must use that well as a recovery well for twenty-four hours to determine how much oil that well can recover in that period. (Coker, T.609.) The amount of oil that the well emits in that test period is assigned to that well as its allowable. (Coker, T.610.) When the test is completed and the wells are converted to injection wells, the allowable of those wells are transferred to other specific recovery wells on the property. (Id.) Thus, if prior to injection, an injection well has an allowable of five barrels per day, and a recovery well has an allowable of six barrels per day, the allowable of the injection • well can be transferred to the recovery well so that the recovery well could extract eleven barrels per day. (Coker, T.611.) If the waterflood operation is able to produce more oil than this allowable permits, a different set of allowables comes into play. Rule 48, Texas Railroad Commission. The first step in increasing the allowable for waterflood projects is to assign a “marginal allowable” to the wells on the property. The allowables for the injection wells are transferred to the recovery wells. If the waterflood produces more than this allowable permits, a yardstick allowable is assigned to each well, including injection wells, and the allowables from the injection wells are transferred to the recovery wells (Coker, T.638.) Other higher allowables can be assigned after a hearing and are assigned on a lease basis rather than a well basis. (Coker, T.615-619.) Mr. Coker made clear the reasons for allowing the transfer of allowables from injection to recovery wells: “The transfer of an allowable concept was initiated by the Railroad Commission for two primary reasons: One, as an incentive to operators to initiate secondary recovery in order to increase the ultimate recovery from the various fields. Further, the transfer allowable concept was adopted and has been utilized for at least 40 years in recognition of the fact that the water injection wells are an integral part of the recovery system in secondary recovery projects.” (Coker, T.629.) State conservation practice recognizes the importance and necessity of secondary recovery, and the essential contribution of the injection well to secondary recovery. Louisiana has also recognized the role of injection wells in their allowable system. Not only does Louisiana allow the transfer of allowables from injection wells to recovery wells on a unit, but Louisiana also allows an extra allowable to be assigned to a property for each injection well. • This bonus allowable “was an incentive for operators to initiate secondary recovery early in the life of a reservoir or earlier than might be normally done to ensure that the maximum recovery from the reservoir is obtained.” (Boudreaux, D.15.) Oklahoma and New Mexico also allow the transfer of allowables in waterflood operations. New Mexico Oil Conservation Div. Rules and Regs., Rule 701 (1968); Corporation Commission of Oklahoma Rules and Regs., 2-240, 2-250, 2-261 (1973). The material before the Court shows no state in which production from secondary recovery projects is treated in a manner identical to production from primary recovery projects. The systems of allowables shown in the records before this Court show that the state regulators all recognize the role played by enhanced recovery techniques and the necessary role of injection wells in the production of crude oil. The state regulators recognize that the goals of the proration system — to prevent waste and to ensure maximum recovery of oil from a reservoir- — can be achieved by providing for the role of injection wells when setting allowables. Historically, federal agencies have recognized the identity of contribution to the oil production process made by recovery wells and injection wells on secondary recovery projects. In 1944, the director of the Office of Economic Stabilization granted “stripper wells” an increase in price. The plan was designed to “keep stripper wells in operation, to encourage reopening and cleaning out of old wells, and to make secondary recovery projects feasible.” 9 Fed.Reg. 7769. “Pools” which were averaging less than nine barrels of oil per well per day were allowed to increase prices. The regulations required calculation of: “Daily Average per well production of pool during month of December 1943 in terms of 42-gallon barrels. (The number of wells to be considered the number of wells producing as of December 31, 1943.)” (Id.) Although it is unclear whether this definition was subject to one standard interpretation or not, the only evidence this Court has as to the application of this provision to injection wells is the undisputed testimony that in Texas injection wells were included in determining qualification for the increased prices under that federal regulation. (Baumel, T.668, 671.) Section 263 of the Internal Revenue Code allows operators an option either to deduct or capitalize intangible drilling and development costs “in the case of oil and gas wells.” This provision has been implemented to include all intangible expenditures “incident to and necessary for the drilling of wells and preparation of wells for the production of oil and gas.” Treas.Reg. Sec. 1.612 — 4(a). The I.R.S. recognizes that the costs incurred in drilling an injection well should be treated in the same manner as those costs incurred in drilling a recovery well, and are chargeable to capital or deductible as expenses. Rev.Rul. 69-583, 1969-2 C.B. 41. The I.R.S. thus has held that injection wells are within the term “oil wells” as used in Section 263 of the Internal Revenue Code. The Mineral Land Leasing Act of 1920, Pub.L.No.146, Ch. 85, 41 Stat. 437, authorized the execution of oil and gas leases by the Secretary of the Interior on federal lands at royalties to be determined by the Secretary on the basis of competitive bidding. The Act itself provided a stripper well exemption from these standard royalty provisions: “Whenever the average daily production of any oil well shall not exceed ten barrels per day, the Secretary of the Interior is authorized to reduce the royalty on future production when in his judgment the wells can not be successfully operated upon the royalty fixed in the lease.” The apparent purpose of this exemption was to allow marginal wells preferential treatment to prevent abandonment and to insure maximum production. In 1935, as a part of a general revision of this act, the exemption was rewritten to provide: “Whenever the average daily production of the oil wells on an entire lease or on any tract or portion thereof segregated for royalty purposes shall not exceed ten barrels per well per day, or where the cost of production of oil or gas is such as to render further production economically impracticable the Secretary of the Interi- or, for the purpose of encouraging the greatest ultimate recovery of oil and in the interest of conservation of natural resources, is authorized to reduce the royalty on future production when in his judgment the wells cannot be successfully operated upon the royalty fixed in the lease.” (Emphasis added.) Ch. 599, Sec. 1, 49 Stat. 676 (Aug. 8, 1935). In 1936, the statutory measure was implemented through a provision which provided that only wells which yielded commercial volumes of production during part of a month were to be considered in ascertaining the well count for determining average daily production. Injection wells were to be counted. 56 I.D. 415, 427 (1936). This holding has remained unchanged and is currently embodied in Section 221.49 of 30 C.F.R.: “Sliding and step-scale royalties are based on the average daily production per well. The supervisor shall specify which wells on a leasehold are commercially productive . . . but only wells which yield a commercial volume of production during at least part of the month shall be considered in ascertaining the average daily production per well. “(b) Wells approved by the supervisor as input wells shall be counted as producing wells for the entire month if so used 15 days or more during the month, and disregarded if so used less than 15 days during the month.” Although the statutory stripper well exemption from the royalty rates was subsumed into a general provision granting the Secretary of the Interior power to modify royalty rates, the exemption continues in the administrative practices of the Department of Interior. The testimony of John Duletsky provided the Court with great insight into the manner in which this provision was actually applied by the Department of Interior (DOI). Mr. Duletsky had been a long time employee of the DOI and had served as a senior official in a position within the DOI which dealt with the application of this regulation. The Court believes that there could be no individual more knowledgeable about the treatment of injection wells for purposes of the step or sliding scale royalty than Mr. Duletsky. He testified that to be counted as a well for purposes of determining average daily production, an injection well had to meet two conditions. First, the injection well had to be completed in the correct oil bearing formation. Second, the well must have been injecting water into the oil bearing formation for at least fifteen days a month. (Duletsky, T.577-78.) He dispelled any doubt that the term “input well” used in the regulation, is synonymous with the term “injection well.” (Duletsky, T.575-76.) This testimony is buttressed by plaintiffs’ Exhibit 45, which is a chapter from the DOI Conservation District Manual, containing rules and procedures relating to the variable regulatory rate and well count. See, P.X. 45, pp. 6-7. Duletsky stated it was his belief that the inclusion of injection wells was brought about by the Government’s concern “in the public interest to maximize the ultimate recovery from a reservoir, prevention of waste, and conservation.” (T.579.) Duletsky’s testimony shows that the DOI treats injection wells in a manner similar to recovery wells for purposes of determining well count. An active injection well is routinely counted as a well for determining average daily production per well. A shut-in injection well is usually treated as a shut-in recovery well and excluded from the well count. Beyond all question, DOI regulation 221.49(b) is not a narrow, limited exception niggardly administered by a secretary who exercises discretion to exclude injection wells. This section establishes the general proposition that active injection wells are productive wells and are to be included in the well count for purposes of the variable royalty. II. STATUTORY BACKGROUND In the early 1970’s, acting pursuant to the Economic Stabilization Act of 1970, 12 U.S. C.A. Sec. 1904 (note), the Cost of Living Council (CLC) promulgated a comprehensive series of regulations governing the maximum prices at which domestic crude oil and refined petroleum products could be sold. In general, the regulations established a “two tier” price system for production from each “property,” and set a ceiling on the prices charged for the first sale of domestic crude oil. This system was designed to halt the inflationary spiral of crude oil prices while limiting the disincentive effect of oil price regulations. 6 C.F.R. Sec. 150.354. The statutory stripper well exemption originated as an amendment to S. 1081 (TA-PA A) offered by Senator Bartlett, United States Senator from Oklahoma, a principal oil-producing state, on the Senate floor. This original amendment read: “Those oil leases whose daily average production per well does not exceed that of a stripper well of not more than ten barrels of oil per day shall be exempt from any allocation or price restraints established by any act of law.” This amendment was adopted by the Senate and subsequently amended by Senator Jackson to read: “The first sale of crude oil and natural gas liquids produced from any lease whose average daily production of such substances does not exceed ten barrels per well shall not be subject to price restraints established pursuant to the Economic Stabilization Act of 1970 as amended, or to any allocation program for fuels or petroleum established pursuant to that Act or to any Federal law for the allocation of fuels or petroleum.” Senator Jackson also amended the amendment to provide that the agency designated to administer the allocation program be allowed to promulgate regulations implementing the exemption. The exemption as amended was enacted as Section 406 of the Trans-Alaska Pipeline Authorization Act, Pub.L.93-153, 87 Stat. 590 (codified at 12 U.S.C. § 1904). The Conference Committee added a provision requiring leases to be operated at the maximum feasible rate. Regulations implementing this exemption were published by the Cost of Living Council (CLC) at 38 Fed.Reg. 32494 (November 26, 1973) (6 C.F.R. Sec. 150.54(s)). These regulations defined the terms “average daily production” as follows: “Average daily production” means the qualified maximum total production of domestic crude petroleum and petroleum condensates, including natural gas liquids, produced from a property during the preceding calendar month, divided by a number equal to the number of days in that month times the number of wells which produced crude petroleum and petroleum condensates, including natural gas liquids, from that property in that month. To qualify as maximum total production, each well on the property must have been maintained at the maximum feasible rate of production, in accordance with recognized conservation practices, and not significantly curtailed by reason of mechanical failure or other disruption in production.” On November 27, 1973, the President signed into law the Emergency Petroleum Allocation Act of 1973 (EPAA), Pub.L.No. 93-159, 87 Stat. 628 (codified at 15 U.S.C. Sec. 751). Section 4(a) of the EPAA required the President promulgate regulations providing for the mandatory allocation of crude oil, residual fuel oil, and each refined petroleum product, in amounts and at prices specified in regulations. Subparagraph 4(e)(2)(A) of the EPAA also contained a stripper exemption. Regulations implementing this provision were published as a revised version of 6 C.F.R. Sec. 150.54(s), 38 Fed.Reg. 34464 (December 14, 1973). These regulations were identical to the earlier regulations in all respects important to this case. On December 4, 1973, the President issued Executive Order No. 11748, establishing the Federal Energy Office (FEO) and delegating to the FEO primary responsibility for administering and enforcing the petroleum allocation and pricing provisions of the EPAA. 38 Fed.Reg. 33575 (December 6, 1973). The FEO thereafter adopted Mandatory Petroleum Price Regulations which incorporated the petroleum pricing regulations that had originally been promulgated by the CLC. The CLC’s stripper well lease exemption was ultimately incorporated in these regulations, when on January 14, 1974, FEO adopted and reissued the CLC definitions of “stripper well lease” and “average daily production.” 10 C.F.R. § 210.32(b), being identical to 6 C.F.R. § 150.54(s). On May 7, 1974, the President signed into law an act of Congress known as the Federal Energy Administration Act of 1974 (FEAA), 15 U.S.C. Sec. 761 et seq., Pub.L. No.93-275, 88 Stat. 96. The FEAA established the Federal Energy Administration (FEA) and authorized the President to delegate to the FEA authority vested in the President by law. On June 25, 1974, the President issued Executive Order No. 11790. 39 Fed.Reg. 23185 (June 27, 1974). That Executive Order, in addition to giving notice that the FEAA was to become effective as of June 27, 1974, abolished the FEO, revoked Executive Order No. 11748, and delegated to the FEA all authority vested in the President by the EPAA. The duty of administering and enforcing the petroleum allocation and pricing provisions of the EPAA was thereby assigned to the FEA, and the implementing regulations became the responsibility of the FEA. On December 19, 1974, the FEA issued Ruling 1974-29, 39 Fed.Reg. 44414 (December 24, 1974). That Ruling held that injection wells were not to be counted as wells for purposes of determining whether the average daily production per well from a property exceeded ten barrels in the preceding calendar year. The relevant portions of the Ruling read as follows: “ISSUE: Is an ‘injection well’ a “well” for the purpose of determining whether the average daily production of a property was 10 barrels or less per well in the preceding calendar year, for purposes of the stripper well lease exemption of 10 C.F.R. § 210.32? “RULING: No. Under the FEA regulations, the first sale of domestic crude petroleum and petroleum condensates, including natural gas liquids, produced from any stripper well lease is exempt from the mandatory price and allocation regulations. A stripper well lease is defined as a property whose average daily production did not exceed 10 barrels per day per well during the preceding calendar year. ‘Average daily production’ is further defined in 10 C.F.R.. § 210.32(b) as: ‘The qualified maximum total production of domestic crude petroleum condensates, including natural gas liquids, produced from a property during the preceding calendar year, divided by a number equal to the number of wells which produced crude petroleum and petroleum condensates, including natural gas liquids from that property in that year.’ “Thus, the FEA regulations by their specific language provide that only wells ‘which produce crude petroleum’ are to be counted in calculating average daily production for the purpose of determining whether the stripper well lease exemption applies. While injection techniques help to ‘produce’ crude petroleum, they are not wells which themselves ‘produce’ crude petroleum. Therefore, wells which did not actually yield or produce crude petroleum during the preceding calendar year are not production wells for this purpose. Whether the non-producing well was an ‘injection’ well, a disposal well, a dry well, a spent well or a shut-in well will not change this result.” III. THE DOE’S EXCLUSION OF INJECTION WELLS CONFLICTS WITH CONGRESSIONAL INTENT As stated in this Court’s order of June 11, 1980, the Court believes that TECA has held that the regulation defining average daily production itself mandated the exclusion of injection wells from the well count. The focus of this decision, therefore, is upon the underlying regulation and not upon the ruling. The legal foundation and proper procedure for this Court to follow in reviewing the regulation at issue in this case was stated by the Supreme Court in Citizens to Preserve Overton Park v. Volpe, 401 U.S. 402, 91 S.Ct. 814, 28 L.Ed.2d 136 (1971). Three distinct inquiries are required. First, this Court must determine whether the actions of the agency were within the agency’s authority. Second, the Court must decide whether the action by the agency was “arbitrary, capricious or an abuse of discretion, or otherwise not in accordance with law.” Finally, this Court must decide whether the agency’s actions followed the necessary procedural requirements. In the prior proceedings in this case the third inquiry has been satisfied. Both the regulation and ruling at issue have been determined to be procedurally valid. The Court need now only consider the first two issues. The defendant contends that the agency’s interpretation of the statute to exclude injection wells from the well count must control this Court. Much of the problem with this position, as will be more fully noted, is that the only real clue of how the agency viewed the statute is the result it reached in holding that injection wells cannot be counted. The Court is acutely aware that an agency’s interpretation of a statute which the agency is authorized to administer is entitled to “substantial deference.” Quern v. Mandley, 436 U.S. 725, 736, 98 S.Ct. 2068, 2076, 56 L.Ed.2d 658 (1978). This deference, however, does not render an agency’s interpretation exempt from judicial scrutiny. The deference due any interpretation “is constrained by our obligation to honor the clear meaning of a statute, as revealed by its language, purpose and history.” International Brotherhood of Teamsters v. Daniel, 439 U.S. 551, 99 S.Ct. 790, 800, 58 L.Ed.2d 808 (1979). “The weight to be given to an administrative interpretation depends upon ‘the thoroughness evident in its consideration, the validity of its reasoning, its consistency with earlier and later pronouncements, and all of those factors which give it power to persuade, if lacking power to control.’ ” Standard Oil Co. v. D. O. E., 596 F.2d 1029, 1056 (Em.App.1978), quoting Skidmore v. Swift & Co., 323 U.S. 134, 140, 65 S.Ct. 161, 164, 89 L.Ed. 124, 129 (1944). The Court has an obligation to examine anew the legislative history and purpose of the statute. The interpretation given the statute did not evolve as a result of a comprehensive evidentiary hearing, as is done in many instances. Nor does the interpretation given the statute appear to have been the product of the expertise of the agency. Rather, the interpretation seems to have been the product of the agency’s reading of congressional intent, principally from language of the Act alone. Divining congressional intent behind a statute is a task to which courts are at least equally suited as are administrative agencies. This fact mitigates against according the interpretation extra authoritative weight. In Barlow v. Collins, 397 U.S. 159, 166, 90 S.Ct. 832, 837, 25 L.Ed.2d 192 (1970), the Supreme Court was faced with a challenge to a regulation promulgated by the Secretary of Agriculture which defined “making a crop.” The Court held that defining that term was not a discretionary judgment of the Executive Branch: “On the contrary, since the only or principal dispute relates to the meaning of the statutory term, the controversy must ultimately be resolved, not on the basis of matters within the special competence of the Secretary, but by judicial application of canons of statutory construction. See Texas Gas Transmission Corp. v. Shell Oil Co., 363 U.S. 263, 268-70, 80 S.Ct. 1122, 1126-1127, 4 L.Ed.2d 1208. ‘The role of the courts should, in particular, be viewed hospitably where . . . the question sought to be reviewed does not significantly engage the agency’s expertise. “Where the only or principal dispute relates to the meaning of the statutory term ...” (the controversy) presents issues on which courts, and not (administrators), are relatively more expert.’ Hardin v. Kentucky Utilities Co., 390 U.S. 1, 14, 88 S.Ct. 651, 658-659, 19 L.Ed.2d 787 (Harlan, J. dissenting).” See also, Wilderness Society v. Morton, 479 F.2d 842, 866 (D.C.Cir.1973), cert. denied, 411 U.S. 917, 93 S.Ct. 1550, 36 L.Ed.2d 309 (1973); UPG, Inc. v. Edwards, 647 F.2d 147, at 156 n. 23 (Em.App.1981). The defendant argues that other factors are also important in determining whether the agency interpretation should be given extra authoritative weight. Three questions are generally considered when looking at an agency interpretation. Was the interpretation contemporaneous with the enactment of the statute? Has the interpretation consistently been followed over a long period of time? Was the interpretation outstanding at the time of a reenactment of the statute? Energy Consumers and Producers Association, Inc. v. D. O. E., 632 F.2d 129, 143 (Em.App.1980). It is true that, in this case, the regulation was issued contemporaneously with the statute. It is equally true, however, that the regulation was not drafted with the intent either to exclude or to include injection wells from the well count. There raged within the agency a great debate as to whether injection wells were within the statutory exemption. The documentary material before the Court shows that the proper interpretation to be given the regulation and statute was debated until the time that Ruling 1974-29 was promulgated. See, e. g., P.X. 72, 73, 75, 85, 92, 131, 132, 136, 137, 139, 140. See also, G.X. Z-l. All individuals involved in the agency action with respect to injection wells who came before this Court agreed that the inclusion of injection wells in the stripper well exemption was an unresolved issue until the time of the Ruling. Linda Buck, in May, 1974, prepared a memorandum, the purpose of which “was to devise a method of proposing a clarification to what we believed to be an ambiguous regulation.” (Buck D. 41.) George Biondi recognized in July of 1974, that the issue was unresolved. (Biondi, D.36 — 7.) See also, Walker, D. 59, 64, Ware T. 957, 1005-16, 1009-10. Phillip Essley recognized that the regulation did not conclusively decide the issue, and that the issue was not finally determined until the release of Ruling 1974-29 in December, 1974, more than one year after the passage of the stripper well exemption. (Essley, T. 1208-15.) Since the construction ultimately arrived at by the agency was not one made “soon after the time of enactment,” it does not qualify as a contemporaneous construction. Russ v. Wilkins, 624 F.2d 914, 923 (9th Cir. 1980). The evidence before the Court shows that there was no single contemporaneous construction of the statute or regulation to exclude injection wells from the well count. This factor does not indicate that extra authoritative weight need be given the agency interpretation. Nor does the evidence show that' there was one consistent and uniform application of the statute and regulation to exclude injection wells. The record before the Court contains examples of times at which oil producers were advised to count injection wells. On December 6, 1973, Robert Weldon, who was then Engineering Supervisor of Joint Operations for Clinton Oil Company (now Energy Reserves Group, Inc.), contacted the CLC to determine whether injection wells could be included in the well count. Mr. Weldon was referred to Andrew Drance, of the CLC, who advised him that injection wells were to be included in the well count. (Weldon, D. 21-4.) Mr. Drance’s position within the agency was close to that of the regulation’s draftors. On December 7, 1973, Ernest T. Pelikan, who was then in the Management Services Department of Arthur Young & Company, contacted the CLC on behalf of Suburban Propane Gas Corporation, another of the plaintiffs. Mr. Pelikan also had a telephone conversation with Andrew Drance and was advised that injection wells could be included in the well count. (Pelikan, D.27-8.) In January, 1974, August Erickson, then Vice-President of Sklar & Phillips, contacted Eugene Waters of the Internal Revenue Service, the agency delegated responsibility at that time for enforcing the petroleum pricing regulations. On January 30, 1974, Waters and W. M. Meriwether, of the I.R.S., telephoned Erickson and advised him that injection wells could be included in the well count. (Erickson, D. 28-31.) The oral advice that injection wells could be counted was confirmed by a letter from Waters on January 31, 1974 (P.X. 54). In late 1973, James H. Roark and Carl E. Stone, of King Resources Company (now Phoenix Resources Company) were advised by I.R.S. officials in Oklahoma City that injection wells could be included in the well count. (Roark, D.12-3, 46). In October, 1974, Larry White, Dallas Area Manager of the F.E.O.’s Region VI Office, advised a New Mexico producer that injection wells could be included in the well count in calculating average daily production under the stripper well exemption regulation. (White, D.26, 39, 71-7.) White based this advice on the regulations and on Form P-1 of the Texas Railroad Commission, Oil & Gas Division, which included injection wells as producing wells. (White, D.85-7, 99, 101.) White’s advice was founded in part on a mid-May, 1974, letter from the Regional Counsel of Region VI, advising a Dallas-based company that injection wells were to be included in the well count, a copy of which he had seen. (White, D.26-8, 32, 75-6.) White established a training program for the agency’s auditors in Region VI. (White, D. 82-7.) This program, adopted by the national office, instructed auditors that the stripper well exemption permitted producers to include injection wells in the well count. (White, D.82-7.) On October 2, 1974, M. H. McConnell, of Phillips Petroleum Company, traveled to Washington, D.C., to obtain guidance from agency officials concerning the injection well issue. McConnell was referred to and met with Roy Whitson, Rendel Alldredge, and a Mr. Kourkoumelis of the F.E.A. After a lengthy conference, McConnell was advised that injection wells should be counted. (McConnell, D.304.) In August and September, 1974, Audie Moore, of Kewanee Oil Company, also visited Washington, D.C., to obtain guidance as to the meaning of the agency’s stripper regulation. He initially met with Rendel Alldredge and Bob Kahl, of the F.E.A. (Moore, D.29.) At that meeting, Alldredge and Kahl expressed the view that injection wells could be included in the well count. (Moore, D.30-1.) In order to obtain additional confirmation, however, Moore met on September 4, 1974, with four other officials of the Compliance Division of F.E.A. At the conclusion of that meeting Moore was advised that injection wells could be included in the well count. (Moore, D.37-8.) The defendant’s argument that only official interpretations should be examined is patently incorrect, and has been rejected by the Court on at least one prior occasion. See Order filed June 11, 1980. TECA, in Standard Oil Co. v. Department of Energy, 596 F.2d 1029, 1056 (Em.App. 1978), held that statements of lower level officials should not be disregarded: “The FEA contends that only the FEA’s General Counsel, his staff, and other ‘high level policy makers’ had the authority to issue official interpretations of its regulations. Consequently, it argues, in determining what the agency’s interpretation was this court should ignore the actions of the FEA auditors and other lower level officials during the relevant period. This court held in California Molasses Co. v. California & Hawaiian Sugar Co., 551 F.2d 1230, 1235, 1239 (Em.App.1977), that the interpretation of agents of the IRS, which had been charged with enforcing price controls, were entitled to deference by the courts. We recognize, as the FEA argues, that California Molasses is not precisely in point. We do conclude, however, that the statements by the FEA auditors and other lower level officials are entitled to weight in determining the thoroughness of the FEA’s consideration of its regulations, the validity of its reasoning, and its consistency with earlier and later pronouncements.” This Court considered the evidence of the interpretation given by lower level officials only as it impacted on the consistency and contemporaneous construction issues. The defendant contends that the Standard Oil rule is applicable only where the only announced public position is contrary to the formal interpretation eventually adopted by the agency. 596 F.2d at 1056. The defendant does not explain why the broad statement cited above should be so limited. If this Court were to accept this argument, the “consistency” inquiry would be relevant only where the agency’s final position is contrary to all advice theretofore given. This Court can see no reason that the consistency inquiry would not be equally applicable in this case where not all the advice expressed was contrary to the final position. The concerns raised by the defendant more nearly reflect on the extent of consistency or inconsistency rather than whether it is properly an issue for this Court. The record before the Court does disclose that perhaps the bulk of the advice given by the agency was to the effect that injection wells should not be counted. The reason that this advice was given does not seem to be that the interpretation was uniformly accepted as the “true” interpretation of the regulation or statute — rather, the interpretation was the most favorable to the agency, and represented the most conservative advice. Linda Buck identified the reasons that this advice was given: “Q. Okay. Now, let’s talk a little bit about how the advice you — -what the advice you gave to crude oil producers was characterized. As I understand what your testimony has been thus far, the advice you gave to crude oil purchasers when an inquiry was made about the injection well issue was basically in four parts: one, that the regulation was unclear and ambiguous; two, that the issue was unresolved in the agency; three, that the agency was working on the issue; and four, because the issue remained unresolved, that if the producer included injection wells in the well count they did so at their own risk. A. I hope I said it that well; but, yes, that is the essence.” (Buck, D.74-5.) The Court concludes that the current interpretation is not one which has been followed consistently over a long period of time, such as would justify special deference. The third inquiry the Court must make in determining whether the interpretation is entitled to special deference is whether the interpretation was outstanding at the time of a reenactment of the statute. The stripper well exemption was reenacted in § 121 of the Energy Conservation and Production Act of 1976, P.L. 94-385, 90 Stat. 1125 (1976). At that time there was no attempt to change the interpretation. This fact is a reason for deference to the existing interpretation. See, Energy Consumers and Producers Association, Inc. v. D. O. E., 632 F.2d 129, 144 (Em.App.1980). The weight to be accorded this fact, however, is greatly lessened by the fact that there was actual disagreement with the interpretation by Congress following the reenactment. In 1977, Senator Bartlett propos