
    SOUTH DAKOTA PUBLIC UTILITIES COMMISSION, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Interstate Power Company, Iowa Electric Light and Power Company, Iowa-Illinois Gas and Electric Company, Iowa Power and Light Company, Iowa Public Service Company, Iowa Southern Utilities Company, Metropolitan Utilities, District of Omaha, Minnesota Gas Company, North Central Public Service Company, Northern States Power Company (Minnesota), Northern States Power Company (Wisconsin), Northwestern Public Service Company, Northern Natural Gas Company, Intervenors-Respondents.
    No. 79-2020.
    United States Court of Appeals, Eighth Circuit.
    Submitted Sept. 11, 1980.
    Decided March 5, 1981.
    Rehearing and Rehearing En Banc Granted June 9, 1981.
    
      Ben Stead, Asst. Atty. Gen., South Dakota Public Utilities Commission, Pierre, S. D., Frances E. Francis, Spiegel & McDiarmid, Washington, D. C., for the South Dakota Public Utilities Commission.
    George J. Meiburger, Frank X- Kelly, Gallagher, Boland, Meiburger & Brosnan, Washington, D. C., Dean W. Wallace, Daniel B. O’Brien Jr., Henry C. Rosenthal, Jr., Northern Natural Gas Company, Omaha, Neb., for Northern Natural Gas Co.
    William D. Carstedt, Springer, Carstedt & Kurlander, Chicago, 111., for Interstate Power Co.
    
      Steven G. Gerhart, Eva J. Cram, Cedar Rapids, Iowa, for Iowa Elec. Light and Power Co.
    E. J. Hartman, Charles A. Crampton, Davenport, Iowa, for Iowa-Illinois Gas and Elec. Co.
    Lynn K. Vorbrich, Keith D. Hartje, Des Moines, Iowa, for Iowa Power and Light Co.
    E. Phil Vondrak, Paul J. Leighton, Sioux City, Iowa, for Iowa Public Service Co.
    C. R. S. Anderson, Stephen W. South-wick, Centerville, Iowa, for Iowa Southern Utilities Co.
    Cecil S. Brubaker, W. L. Strong, Omaha, Neb., for Metropolitan Utilities District of Omaha.
    George C. Mastor, James B. Proman, Minneapolis, Minn., for Minnesota Gas Co.
    Ned Willis, Willis & Sackett, Perry, Iowa, for North Central Public Service Co.
    John P. Moore, Jr., Minneapolis, Minn., for Northern States Power Co. (Minnesota), Northern States Power Co. (Wisconsin).
    Everett E. Hoyt, Northwestern Public Service Co., Huron, S. D., James M. Van Vliet, Jr., Schiff, Hardin & Waite, Chicago, III, for Northwestern Public Service Co.
    Robert R. Nordhaus, General Counsel, Jerome M. Feit, Deputy Sol., Jane C. Murphy, Washington, D. C., for respondent Federal Energy Regulatory Commission.
    Before HEANEY and STEPHENSON, Circuit Judges, and MURPHY, District Judge.
    
      
       The Honorable Diana E. Murphy, United States District Judge for the District of Minnesota, sitting by designation.
    
   STEPHENSON, Circuit Judge.

This is an appeal of an order entered by the Federal Energy Regulatory Commission (FERC) permitting an accelerated rate of depreciation for certain facilities owned by Northern Natural Gas (Northern). The South Dakota Public Utilities Commission (South Dakota) opposed Northern’s proposed adjustments before the FERC and has appealed its decision. The FERC found that because of dwindling reserves of natural gas, Northern should be allowed to depreciate its equipment over a period shorter than the physical life of the equipment. That is, the FERC decided that the useful life of the pipeline systems would be shorter than the time that normal wear and tear would require abandonment.

South Dakota asserts primarily that the depreciation rates set by the FERC were premised upon baseless estimates of future reserves, that the FERC miscalculated the portion of the predicted future reserves Northern would be able to purchase and, therefore, the FERC decision was inconsistent with the standards imposed by the Natural Gas Act, 15 U.S.C. §§ 717, et seq., and as applied in Memphis Light, Gas and Water Division v. Federal Power Commission, 504 F.2d 225 (D.C.Cir.1974). A secondary issue involves South Dakota’s challenge of the FERC’s decision to take official notice of the record in one of the two related proceedings that were consolidated at the time the FERC issued its order. We affirm the FERC’s decision.

I. FACTUAL AND PROCEDURAL BACKGROUND

Northern Natural Gas is a major interstate transporter of natural gas with revenues exceeding a billion dollars per year. Its pipeline network moves natural gas from the producing areas of Texas, Oklahoma and Kansas northward to Nebraska, Iowa, South Dakota, Minnesota and Wisconsin. Northern also owns producing and gathering equipment offshore in the Gulf of Mexico plus an isolated system in Montana and Wyoming. For the purpose of computing depreciation, Northern’s properties are divided into four components, two of which are important here. The first is referred to as the South End supply area. The South End links Northern’s two major supply fields — the Hugoton-Anadarko and the Permian Basin — to the rest of the Northern system. The second major component is referred to as the Market Area and consists of the equipment north of the Kansas-Nebraska border.

The primary issues in the proceedings below were whether the FERC properly estimated the reserves of natural gas in the Hugoton-Anadarko and Permian Basin supply areas, and what share of the estimated reserves Northern would be able to acquire. The relationship of the supply of natural gas and depreciation rates is inversely proportional. The higher the estimates of natural gas supplies, the lower the depreciation rates should tend to be because it is more likely that the pipeline system will be a useful asset throughout its physical life. Conversely, the lower the estimated supplies the higher depreciation rates are called for because the pipeline system may become useless before it has physically deteriorated to the point where abandonment would be required. For example, in this case, under the FERC staff’s estimates, Northern’s facilities will be useful until approximately the year 2000. However, the physical life of the equipment will not end until about tóle year 2011. In these circumstances, the FERC concluded, an increased rate of depreciation was appropriate. Therefore, the gravamen of this litigation, and the subject of nearly 7000 pages in this voluminous record, is how much natural gas is awaiting discovery in the Hugoton-Anadarko and Permian Basin fields, and how much of that supply will Northern be able to buy.

The FERC order approved settlement agreements in two related rate cases filed by Northern. The first, RP 76-89, was filed in April 1976. The second, RP 77-56, was filed about a year later, while the earlier case was still pending. Both were requests for general rate increases that eventually were narrowed to the single issue of proper rates of depreciation.

Negotiations between the FPC and Northern in RP 76-89 began in August 1976. Thirty-one petitions for leave to intervene were granted; the bulk of these represented Northern’s customers which are local utility companies. Several state regulatory agencies were also represented including the South Dakota Public Utilities Commission and the Iowa State Commerce Commission. The FPC and Northern reached an agreement in October 1976, setting the composite depreciation rate at 4.48 percent. South Dakota filed adverse comments on the settlement proposal. The FPC rejected its arguments but on application for rehearing the FPC reversed itself finding that the settlement was not supported by substantial evidence and remanded the case to the presiding administrative law judge for a hearing on the depreciation rates. A three-day hearing was held in January and February 1978. In June, ALJ Benkin issued a decision finding that neither the settlement rates nor those proposed by South Dakota were supported by substantial evidence. He therefore held that Northern’s pre-existing rates would remain in effect.

Meanwhile RP 77-56 had reached a similar stage. Following discussions among Northern and other parties, a settlement was reached which, if approved by the FPC, would resolve all issues. South Dakota again was the only party active in the case which opposed the settlement rates. A hearing was held in April of 1978. The parties agreed to waive the ALJ’s initial decision and upon completion of the hearing, the proposed settlement and the record were certified to the FERC. Thus, the two cases consisting of identical parties and issues were then pending before the FERC which, in August 1979, issued its order consolidating the two dockets and approving the settlement rates. South Dakota made an application for rehearing which was denied. This appeal followed.

II. STANDARDS AND SCOPE OF REVIEW

The Natural Gas Act of 1938 provides the authority and the relevant standards to guide the FERC in its administrative function. Section four of the Act, 15 U.S.C. § 717c, provides that the FERC shall set rates that are “just and reasonable.” Section nine, 15 U.S.C. § 717h, gives the FERC the authority to determine “proper and adequate rates of depreciation” for natural gas companies within its jurisdiction. Section four modifies section nine in the sense that depreciation rates in order to be proper must be just and reasonable. See Memphis Light, Gas and Water Division v. Federal Power Commission, supra, 504 F.2d at 230 n.19. As these standards suggest, the FERC has been given the difficult job of balancing diverging interests: an excessive rate of depreciation would place a heavy burden on the ratepayers while an inadequate rate would be unfair to the company.

It is clear that by statute and case law the FERC has been granted wide latitude to use its expertise in the application of these vague standards to practical problems. Section 19(b) of the Natural Gas Act, 15 U.S.C. § 717r(b), delineates the procedure for judicial review of an FERC order. The statute provides that “[t]he finding of the Commission as to the facts, if supported by substantial evidence, shall be conclusive.” Id.; see 5 U.S.C. § 706(2XE). The United States Supreme Court has stated the role of the reviewing court in the following fashion:

First, [the reviewing court] must determine whether the Commission’s order, viewed in light of the relevant facts and of the Commission’s broad regulatory duties, abused or exceeded its authority. Second, the court must examine the manner in which the Commission has employed the methods of regulation which it has itself selected, and must decide whether each of the order’s essential elements is supported by substantial evidence. * * * The court’s responsibility is not to supplant the Commission’s balance of these interests with one more nearly to its liking, but instead to assure itself that the Commission has given reasoned consideration to each of the pertinent factors.

Permian Basin Area Rate Cases, 390 U.S. 747, 791-92, 88 S.Ct. 1344, 1372-1373, 20 L.Ed.2d 312 (1967). See Mobil Oil Corp. v. Federal Power Commission, 417 U.S. 283, 307-8, 94 S.Ct. 2328, 2345-46, 41 L.Ed.2d 72 (1974); Gulf Oil Corp. v. Federal Energy Regulatory Commission, 575 F.2d 67, 70 (3d Cir. 1978); Tenneco Oil Co. v. Federal Ener gy Regulatory Commission, 571 F.2d 834, 838-40 (5th Cir. 1978); American Public Gas Association v. Federal Power Commission, 567 F.2d 1016, 1028-30 (D.C.Cir.1977), cert. denied, 435 U.S. 907, 98 S.Ct. 1456, 55 L.Ed.2d 499 (1978); Memphis Light, Gas and Water Division v. Federal Power Commission, supra, 504 F.2d at 230. The Permian Basin decision also notes that:

[W]e have heretofore emphasized that Congress has entrusted the regulation of the natural gas industry to the informed judgment of the Commission, and not to the preferences of reviewing courts. A presumption of validity therefore attaches to each exercise of the Commission’s expertise, and those who would overturn the Commission’s judgment undertake “the heavy burden of making a convincing showing that it is invalid because it is unjust and unreasonable in its consequences.” * * * We are not obliged to examine each detail of the Commission’s decision; if the “total effect of the rate order cannot be said to be unjust and unreasonable, judicial inquiry under the Act is at an end.” * * *
Moreover, this Court has often acknowledged that the Commission is not required by the Constitution or the Natural Gas Act to adopt as just and reasonable any particular rate level; rather, courts are without authority to set aside any rate selected by the Commission which is within a “zone of reasonableness.” * * * No other rule would be consonant with the broad responsibilities given to the Commission by Congress; it must be free, within the limitations imposed by pertinent constitutional and statutory commands, to devise methods of regulation capable of equitably reconciling diverse and conflicting interests.

Permian Basin Area Rate Cases, supra, 390 U.S. at 767, 88 S.Ct. at 1360 (citations omitted).

In recent thoughtful and extensive examinations of this question, the Fifth and D.C. Circuits have concluded that the primary role for the reviewing court is to determine whether the FERC has given reasoned consideration to each of the pertinent factors. Tenneco Oil Co. v. FERC, supra, 571 F.2d at 839; American Public Gas Association v. FPC, supra, 567 F.2d at 1030. The Eighth Circuit has likewise recognized the requirement to defer to the Commission’s expertise. Otter Tail Power Co. v. Federal Power Commission, 473 F.2d 1253, 1257 (8th Cir. 1973). See Murphy Oil Corp. v. Federal Energy Regulatory Commission, 589 F.2d 944, 948 (8th Cir. 1978); Otter Tail Power Co. v. Federal Energy Regulatory Commission, 583 F.2d 399, 407 (8th Cir. 1978). Cf. Montana-Dakota Utilities Co. v. Federal Energy Regulatory Commission, 631 F.2d 557, 560 (8th Cir. 1980) (although the commission’s determination of a just and reasonable cost allocation are ordinarily entitled to considerable amount of deference, “[t]he Commission’s decision still must be supported by substantial evidence.”).

The role of the reviewing court in the special circumstances of an FERC order which allowed an increase in rates of depreciation because of decreasing supplies of natural gas has been discussed by only one other court. In the Memphis decision, the District of Columbia Circuit reversed and remanded a Commission order where there was no evidence in the record concerning the pipeline’s future reserves. Specifically, the court found that the Commission had made no attempt to tie a nation-wide reduction in natural gas reserves to the particular equipment that was the subject of the case. Memphis Light, Gas and Water Division v. FPC, supra, 504 F.2d at 232-33, 235. The court found that the Commission had been too uncritical of the utility’s projections and stated that an increase in depreciation must be based upon substantial evidence and not “snatched from the air on a purely hypothetical ‘worst case’ analysis.” Id. at 234. On remand the Commission was instructed to make a reasoned estimate of the useful life of the particular equipment involved. The court stated that the Commission should take into account current Commission policies designed to increase gas supply and to develop evidence concerning the probable extent and location of reserves which the utility might utilize at some future date. The court concluded:

We recognize that there is no one “correct” depreciation rate; thus, the Commission could develop a range of rates which would fall within a “zone of reasonableness.” Such findings would be, of course, sustained if supported by record evidence.

Id. at 235-36.

South Dakota, the FERC, Northern and the “Northern Distributor Group” all rely upon Memphis as the controlling precedent in this case. The facts of Memphis, however, are easily distinguishable from this case since the FERC, in the case at bar, has made several independent studies to predict future natural gas reserves. Thus, the total failure of the Commission to provide what the Memphis court called a “fair guess” is not the case here. Memphis is important for our purposes because it established that exhaustion of natural resources is a legitimate factor in the determination of depreciation rates. In our view, the more significant precedent is Permian Basin and its progeny. Consequently, our task is to consider the important elements of the FERC decision to determine if the agency has given reasoned consideration to all the pertinent factors, that is, whether the Commission’s decision is supported by substantial evidence.

We emphasize the nature of our review in this case because of its importance in our conclusion. The special responsibility placed in the hands of the FERC and the corresponding limited role of judicial review has often dictated the result. See, e. g., Tenneco Oil Co. v. FERC, supra, 571 F.2d at 840; Shell Oil Co. v. Federal Power Commission, 520 F.2d 1061, 1071 (5th Cir. 1975). We think that is the case here.

III. THE RECORD

There are three basic elements to the FERC’s decision in both RP 76-89 and RP 77-56 which are challenged by South Dakota. Two are studies or models designed to estimate the amount of natural gas in the Permian Basin and the Hugoton-Anadarko fields, and the third is an analysis of what portion or share of these estimated reserves Northern will be able to acquire. The first study used to predict natural gas supply is entitled the EHF Model. The study was conducted and supported at the two hearings by the staff’s expert witness Edward H. Feinstein. The other study is based upon estimates compiled by the Potential Gas Committee (PGC), a diverse group made up of representatives from the natural gas industry, government and academia.

The following table represents the depreciation rates expressed in percentages which were supported by the various parties in RP 77-56. The settlement figures are the rates set by the FERC in its order. The Northern figures are its original proposal before negotiation. As noted above, Northern agreed to the settlement figures and supported those results during the hearing.

AREA Northern FERC SD Settlement

EHF PGC

South End 6.91 5.45 4.79 490 696

Market Area 4.67 3.96 3.10 2.00 3.76

The figures in RP 76-89 were slightly different. The settlement figure for the South End was 5.15 percent but was the same 3.75 for the Market Area. The PGC amounts were 4.99 percent and 3.33 percent for the South End and Market Area, respectively. The EHF predictions led to rates of 5.44 percent for the South End and 4.02 percent for the Market Area. South Dakota proposed the same 2.0 percent for the Market Area but had suggested that 4.35 percent would be appropriate for the South End.

The FERC suggests that the EHF and PGC studies, as rational predictions of an unknown quantity, form a “zone of reasonableness” for depreciation rates consistent with the standards expressed in Permian Basin and Memphis. South Dakota attacks both of these studies along with the share analysis used by the FERC. However, as the table demonstrates, if the EHF and PGC represent legitimate estimates, the settlement rates are acceptable because they are within the range created by these two studies.

A. EHF Model

South Dakota argues that the “sole justification” for the settlement figures rest upon the EHF model. The depreciation rates which flowed from the EHF projections represent the high end of what the FERC maintains is a zone of reasonableness. This is because the EHF model produced the lowest reserves estimates of the two studies and consequently, the highest depreciation rates.

The EHF model is statistically based and predicts annual reserves based on a theory that relates drilling efforts to results. This study uses historical data to project future reserves. Feinstein, a petroleum engineer employed by the FERC, testified that the theory behind the EHF model is that for any finite depletable natural resource the large high-grade, easy-to-find deposits are discovered during the early years of the depletion cycle and that the mature years are marked by the discovery of smaller, scattered and lower grade deposits. He stated that both the Hugoton-Anadarko and Permian Basin fields had entered mature stages so this type of analysis would produce reliable results in this case.

Feinstein based his predictions on statistics from 1967-1976. He compared cumulative exploratory drilling footage to cumulative reserve additions. He extrapolated this historical data to predict the potential gas recoverable and the reserves discovered annually. This pattern was extended to the point where the productivity of efforts to results is negligible. As part of this process, Feinstein calculated a figure referred to as “effectiveness of exploration” which was a comparison of new field drilling footage to new field discoveries. He next plotted the effectiveness of exploration data in relation to exploratory footage and time in separate graphs, and then compared cumulative reserve additions to cumulative exploratory footage. This information was compiled for each of the supply areas and was used to determine the respective depreciation rates.

South Dakota primarily attacks the EHF model because it does not include “developmental drilling.” Feinstein testified that his model considers “new field drilling” which he defined as efforts undertaken to discover new fields not directly related to those already in service. South Dakota argues that this approach ignores reserves added after the initial discovery of a field and as used in the Feinstein model represents a significant reduction in the amount of potential reserves. They argue, and Feinstein agreed, that developmental drilling would account for more activity than exploratory drilling in mature fields such as the Permian Basin and the Hugoton-Anadarko. Feinstein nevertheless maintained that this was not a serious omission. In support of his study, Feinstein constructed a second model based upon the same theory which separately calculated future additions from three categories: new fields, pre-1966 existing fields and existing fields more recently discovered. This second EHF model reached a result that differed by only three percent in total reserves from the first. The FERC also noted that a study conducted by Northern which took developmental drilling into account produced results very similar to the EHF model. Although it is not made clear in the record, at oral argument counsel for the FERC and Northern asserted that although developmental drilling is not included in the efforts side of the EHF relationship, it is a part of the results figures.

We cannot say that the FERC’s conclusion that the EHF study was reliable is not supported by substantial record evidence. Both the South Dakota and Feinstein positions are plausible and in light of our standard of review we defer to the expert judgment of the FERC. The FERC’s opinion demonstrates that the Commission has not ignored South Dakota’s arguments but has given reasoned consideration to all the pertinent factors. We are not required to find more.

South Dakota claims further that the EHF study cannot be relied upon because the PGC estimates reserves three times larger than those predicted by the EHF model. This difference in estimates is so large, in South Dakota’s view, that the EHF model cannot be used as substantial evidence. The FERC responds by suggesting that such seemingly inconsistent estimates are not uncommon. The Commission points to estimates for the United States ranging from 496 trillion cubic feet (Tcf) to 2250 Tcf. Again, we are constrained to affirm the FERC’s conclusion. It is clear, as the evidence in this record suggests, that estimating natural gas reserves is not an exact science. In such areas where technical expertise is the basis for decision making and where the question is purely factual, courts must be mindful of their role. We think that the following quotation is pertinent:

[I]n the end it was for the Commission, not us, to evaluate the respective justifications put forth on the record, and to choose between two divergent theories in setting the amount of the challenged factor. A conclusion on “conflicting engineering and economic issues is precisely that which the Commission exists to determine, so long as it cannot be said ... that the judgment which it exercised had no basis in evidence and so was devoid of reason.”

City of Cleveland v. Federal Power Commission, 525 F.2d 845, 849 n.36 (D.C.Cir. 1976), (quoting United States ex rel. Chapman v. FPC, 345 U.S. 153, 171, 73 S.Ct. 609, 619, 97 L.Ed. 918 (1953)).

B. PGC Model

The PGC model is based upon estimates of natural gas reserves issued by the Potential Gas Committee in conjunction with the Potential Gas Agency at the Colorado School of Mines. The Potential Gas Agency is supported by the American Gas Association. It is one of the few studies which provide natural gas estimates by area. Most predictions only give figures for the entire United States. As noted above, the PGC includes representatives from energy, government and academic institutions.

The PGC divides its estimates into three categories: probable, possible and speculative. The FERC staff did not use the third category of the PGC estimates. They concluded that the speculative category was too uncertain to be included. South Dakota claims that the FERC has arbitrarily eliminated a large source of potential reserves for Northern noting that in the 1972 PGC report the speculative category constituted twenty-nine percent of the Hugoton-Anadarko estimate and eighteen percent of the Permian Basin’s.

We conclude that the FERC’s view is supported by substantial evidence. The PGC’s own publications reveal the questionable nature of the speculative category. In the PGC’s Comparison of Estimates report, the Committee described the reserve estimates in the speculative category as having a “very high degree of uncertainty and likely represent, at best, geologically based speculation.” A Comparison of Estimates of Ultimately Recoverable Quantities of Natural Gas in the United States — A Potential Gas Committee Report 13 (Colorado School of Mines) (1977). In that same study, the PGC did not include the speculative category in its estimates of the “most likely” gas to be discovered. Id. at 12. In the 1976 report, the Committee wrote that arguments in support of both zero and fifty Tcf for the speculative category of the two relevant areas were reasonable. 1976 PGC Report at 14. We agree with AU Benkin that it would be imprudent to base the depreciation rates of a major pipeline company on such uncertain reserves.

We also agree with the FERC’s decision not to include non-traditional sources such as gas from Alaska, Canada and Mexico as well as coal gasification and the anticipated supplies discovered as a result of the Natural Gas Policy Act (NGPA), 15 U.S.C. § 3301, et seq. South Dakota did not present evidence that would allow us to remove the sources from the speculative category. The date such supplies will be available and in what quantity, the FERC found, is highly uncertain. The Commission did note that these sources will be taken into consideration in future rate proceedings when they may be estimated with some precision.

C. Share Acquisition Factor

Once total supply was estimated, the FERC used American Gas Association (AGA) data to predict annual reserve additions. Next, Northern’s probable share of these yearly future additions was estimated. To make this estimate, the FERC staff and South Dakota relied on a weighted average of Northern’s past acquisition rates. The FERC used three years (1974-76) while South Dakota based its figure on Northern’s performance over six years (1971-76). The FERC approved an acquisition rate of seven to eight percent. South Dakota predicted that Northern’s share would be fourteen to fifteen percent. The historical data is as follows:

Year Hugoton-Anadarko Permian Basin
1971 29.62% 29.37%
1972 20.14% 13.72%
1973 21.78% 7.95%
Year Hugoton-Anadarko Permian Basin
1974 6.62% 9.86%
1975 8.13% 10.59%
1976 4.25%
1977 8.14% 4.49%

The FERC found that the sharp drop commencing in 1973 and 1974 could be attributed to increased competition from intrastate suppliers who were not confined by federal price ceilings. South Dakota argues the decrease is an ephemeral phenomenon and that the NGPA, effective in 1978, has restored Northern to its strong competitive position. See note 16 supra. The FERC agreed that the NGPA will eventually relieve Northern’s disadvantage in price competition but that the increased competition experienced in the earlier 1970’s will continue. The Commission pointed to evidence detailing Northern’s increased number of competitors and the expansion of the intrastate suppliers’ equipment as foundation for this conclusion. This result is supported by substantial evidence.

South Dakota also attacks the FERC’s use of AGA area revisions in computing Northern’s share of available gas reserves in RP 77-56. South Dakota claims that the FERC staff understated Northern’s share factor by vintaging the AGA revisions over the past six years. These revisions amounted to an increase in yearly reserve additions which thereby caused a reduction in Northern’s percentage share. Staff witness Feinstein stated that the AGA, for various reasons, is not able to report additions in the year they occur. The AGA then reports the data as it becomes available. Feinstein “vintaged” these revisions, that is, he assigned the delayed figures to the year in which they were discovered. Feinstein testified that he relied partly on statements by Robert Kalisch, manager of gas supply for the AGA, made in another FERC hearing. A copy of Kalisch’s testimony was made available to counsel and South Dakota cross-examined Feinstein on this topic. We find that the FERC’s decision to include these revisions is well within their discretion.

Finally, we note that South Dakota presented only a single witness to support its contentions regarding all three elements of the FERC’s decision. The South Dakota witness, Robert G. Towers, is not a geologist or a petroleum engineer. Therefore, his testimony could reasonably have been given less weight by the FERC.

IV. PROCEDURAL ISSUES

South Dakota also raises several procedural issues which require only a brief discussion.

The FERC consolidated the two dockets discussed herein in its order issued in August 1979. In January 1978, prior to the hearings, South Dakota sought to consolidate the two cases but the FERC denied its motion finding that RP 76-89 concerned only the narrow question of depreciation while the issues in RP 77-56 were not “fully formulated.” In its August 1979 order the FERC used evidence from RP 77-56 to evaluate the reasonableness of the settlement rates reached in RP 76-89. The Commission found that the fifty percent discounting of the PGC probable and possible categories in RP 76-89 was unreasonable as well as the failure to use the least squares method to extend the EHF model analysis. See notes 11 & 15 supra. The Commission relied upon United States v. Pierce Auto Freight Lines, Inc., 327 U.S. 515, 66 S.Ct. 687, 90 L.Ed. 821 (1946), for this procedure.

Pierce held that an agency may take official notice of the records of two related proceedings among the same parties, absent a showing of “specific prejudice.” Id. at 528-30, 66 S.Ct. at 694r-695. We find that South Dakota has made no showing of specific prejudice. The parties, issues, to a great extent the evidence, and even counsel were the same in both dockets. South Dakota claims that it could not cross-examine concerning the modified Feinstein study “in the context” of RP 76-89. The Commission found that South Dakota challenged the validity and credibility of both the original and corrected studies at great length in the hearings and had not made a claim of specific prejudice. The fact that South Dakota had full notice and opportunity to be heard in the RP 77-56 proceeding is consistent with due process and within the guidelines set by Pierce. We agree with the FERC that because of the cost and time saved this was the expedient method to resolve this prolonged controversy.

South Dakota also suggests that the Commission did not give adequate consideration to the ALJ decision in RP 76-89. However, the two opinions are consistent on most points. The AU was alarmed concerning the discounting of fifty percent of the first two PGC categories (“probable” and “possible” reserves) and about the failure to use the least squares method in developing the EHF predictions. As noted, the FERC agreed as to these deficiencies. Further, they were remedied in the RP 77-56 hearing. The major area of disagreement was the use of two estimates to establish a “zone of reasonableness.” The ALJ suggested this procedure indicated that the figures were manipulated in order to reach a prearranged target rate. We agree with the FERC that the use of two models by the staff to arrive at a zone of reasonableness is consistent with Memphis and a good faith effort in a highly uncertain field.

In conclusion, we state that although the evidence is not overwhelming in its support of the FERC’s decision, we cannot hold that the Commission has not considered all the pertinent factors nor can we state that its conclusions do not have substantial support.

Affirmed.

HEANEY, Circuit Judge

dissenting.

I

I respectfully dissent. The depreciation rates fixed by the Commission are neither within the zone of reasonableness nor supported by substantial evidence. These rates will result in Northern’s ultimate customers paying several million dollars a year more than they would be required to pay if the reserves were properly estimated and Northern’s share properly computed. The rates are based exclusively on estimates of natural gas reserves in the Permian and Hugoton-Anadarko Basins, and on estimates of the share of those reserves that Northern will be able to acquire and deliver in the years ahead.

The reserve estimates relied upon by the Commission were developed by E. H. Feinstein, a member of the Staff of the Commission. The Feinstein estimates are fatally flawed because: (1) They are simple mathematical computations based on preDecember, 1976, data. They ignore available geological data and the fact that price and other controls over the industry have been eased since that date. (2) They largely ignore the potential developmental reserves from drilling in the Permian and Hugoton-Anadarko Basins. (3) They appear to have been developed to support the settlement rates agreed to between Northern and its utility customers rather than to fairly and honestly project the potential natural gas reserves that will become available to Northern from the Permian and Hugoton-Anadarko Basins. This is highlighted by the fact that the alternate estimates approved by the Staff (reserves estimated by the Potential Gas Committee excluding speculative reserves), and admittedly within the zone of reasonableness, project reserves three times as large as those projected by Feinstein. (4) They ignore reserves in the Gulf Coast region and supplemental supplies from Alaska and Canada, reserves and supplies to which Northern has access.

Northern’s share factor estimates are likewise severely flawed since: (1) they project Northern’s share based upon only three years acquisition experience, and among the company’s worst years; (2) they fail to take account of what decontrol will do for Northern’s share factor in the future; and (3) they also fail to project Northern’s share of the potential recoverable non-traditional natural gas supplies.

I would remand this matter to the Commission with directions to: First, recompute Northern’s depreciation rates on the basis of the PGC’s estimates of reserves in the Permian and Hugoton-Anadarko Basins (excluding speculative reserves), plus realistic estimates of natural gas that Northern expects to acquire from other sources during the remaining physical life of its facilities; and second, recompute the share of natural gas that Northern can reasonably be expected to obtain from the two named basins, as well as other non-traditional gas supplies that Northern can reasonably expect to obtain during the physical life of its facilities.

II

I have little quarrel with the majority’s statement of the” applicable law and the scope of our review. My own disagreements are with the application of the law and the emphasis that ought to be given to Memphis Light, Gas & Water Div. v. FPC, 504 F.2d 225 (D.C.Cir.1974). Memphis permits a natural gas pipeline company to increase the rate of depreciation on its facilities if the natural gas reserves reasonably available to the company are such that, as a result of declining natural gas reserves, the “useful life” of the pipeline’s facilities would be so affected that “physical life” could not adequately measure the facilities’ future use. Id. at 231. Memphis requires the Commission to make a reasoned estimate of the useful life of the property even though the estimate requires a projection of future reserves. Memphis identifies three criteria that the Commission is to apply in estimating reserves:

(1) What the Commission really expects will happen;

(2) Current policies designed to increase or sustain industry-wide gas supply; and

(3) The extent and location of reserves that the pipeline may utilize. Id. at 235.

The Commission failed to apply these criteria in a reasoned manner.

First, there is little in the record to support the view that the Commission really believed that Northern will be unable to obtain sufficient natural gas to provide service to its customers at present rates of consumption during the physical life of its existing facilities. It never got that far in its cognitive process, instead it adopted an estimate that was primarily designed to support the Commission’s own settlement efforts between Northern and the other affected utilities.

The Commission Staff used three different approaches at various stages of this proceeding to determine the appropriate rates of depreciation. Initially, the Staff assumed that the reserves would be those estimated by the PGC — discounting the probable and possible categories by 50% and eliminating the speculative category entirely. It then determined that Northern would secure 10.40% of the reserves discovered in the Hugoton-Anadarko Basin and 9.06% of the reserves discovered in the Permian Basin. These percentages represented the weighted average of the newly discovered reserves in 1974 and 1975.

When a serious question was raised as to whether it was appropriate to discount the possible and probable categories by 50%, the Staff took a totally different approach to the problem of predicting reserves. Feinstein produced for each supply area a success ratio graph that had as its data points the ratio between new field footage drilled and new field discoveries for each year from 1970 to 1976. His estimates of reserves using this formula were substantially higher than those he had predicted using the PGC estimates. However, Feinstein then significantly reduced his estimate of Northern’s share of these reserves with the result that his bottom line estimates were lower than they had been using his original technique. When this method was objected to, he made a third attempt. He returned to the Potential Gas Committee’s work and adopted the PGC’s 1976 estimates for probable and possible natural gas supplies in the Permian and Hugoton-Anadarko Basins. However, once again he substantially reduced his estimate of Northern’s share in the relevant basins, with the net result that his projected reserves were again lower than either of the first two estimates.

In commenting on Feinstein’s effort, the Administrative Law Judge stated:

It is difficult to know what to make of all this.
The fact that the Staff’s principal expert first went at the task of computing proper and adequate depreciation rates and thereafter felt compelled to repeat the exercise two more times, using different techniques and producing different results, does not inspire great confidence in the validity of the initial job. * * *
Considering the implications of the question, one suspects that the Staff has sought to justify a predetermined result. ♦ * *

In re Northern Nat. Gas Co., FERC Doc. No. RP 76-89 at 30 (June 22, 1978) (Initial Decision of the AU). I agree with the comments of the Administrative Law Judge.

The Commission stated that if it is wrong now, it can reduce Northern’s depreciation rates in some later rate case. The trouble with this theory is that the cost of Northern’s service to its present consumers is unnecessarily excessive. Moreover, the Commission’s approach creates a disincentive to Northern’s acquiring new supplies of gas.

Second, the Feinstein estimate ignores current governmental policies expressed in the Natural Gas Policy Act, 15 U.S.C. § 3301 et seq. (Supp. Ill 1979). The Act deregulates the natural gas industry over a period of years on the theory that permitting prices to rise will stimulate production and increase the supplies of natural gas available to consumers. The Commission’s response to the assertion that it was obligated to consider the Act’s effect on the industry and the likelihood of its generating more reserves was that it “could not take into account the effect of the Natural Gas Policy Act on drilling because, as yet, we do not have sufficient facts on either drilling or the reserve additions that may result.”. In re Northern Nat. Gas Co., FERC Docket Nos. RP 77-56 and RP 76-89 at 5 (October 4, 1979) (Order Denying Rehearing). This is nonsense! The natural gas industry, including Northern, sold deregulation to Congress on the theory that it would lead to more natural gas. Northern now changes its tune — and the Commission steps to its beat — when it comes to passing any of the benefits of deregulation to the ultimate consumer.

Third, the Feinstein model ignores current geological estimates. It is based exclusively on Northern’s past- drilling experience in two mature producing areas. The Commission explained the technique used by Feinstein in this manner:

To predict Northern’s future gas supplies on the EHF model, the staff divided new field discoveries by new field drilling footage over a ten year period to get an annual “effectiveness of exploration” factor per foot drilled. The effectiveness factor changes both over time, as the field matures, and with the amount of footage, drilled (cumulative footage). To derive the annual reserve additions for each future year, the staff first determined the effectiveness factor for that year from the original trend line, then calculated the level of cumulative footage that would be drilled at that level (by use of historical AGA data). The relationship between efforts (cumulative footage drilled) and results (reserve additions), over time (as the effectiveness factor changes) produced annual reserve estimations that were then totalled to produce a final estimation figure. Both the Permian Basin and Hugoton-Anadarko Basin are in the mature producing stage, which is marked by the discovery of smaller, scattered, and lower-grade deposits than the early years.

In re Northern Nat. Gas Co., FERC Docket Nos. RP 77-56 and RP 76-89 at 11 (August 3, 1979) (Order Approving Settlement Agreement) (footnote omitted).

This method is valid only if one assumes that drilling after 1976 will be limited to the same depths and to the same recovery methods that existed before that date. However, it was to encourage the use of newer and more costly techniques, designed to reach gas at greater depths and in new geological formations, that the Natural Gas Policy Act was passed by Congress. Feinstein’s estimate, moreover, ignores developmental drilling; precisely the type of drilling that is apt to result in new discoveries of natural gas in the Permian and Hugoton-Anadarko Basins. The Staff’s suggestions to the contrary are not convincing.

The Staff also considered the estimates of the Potential Gas Committee (excluding speculative reserves) to be within the zone of reasonableness. Without considering speculative reserves, the PGC estimated the reserves in the Permian and Hugoton-Anadarko Basins to be about three times larger than those estimated by Feinstein. The estimates were:

Feinstein PGC
Hugoton-Anadarko Basin 37 Tcf 99 Tcf
Permian Basin _10 Tcf _55 Tcf
47 Tcf 154 Tcf

I agree with the Commission that the modified PGC estimates fall within the zone of reasonableness — albeit at the lower end of that zone.

The Commission is simply adjusting its analysis to match its desired result by characterizing the PGC estimates as overly optimistic. The estimates of the PGC are authoritative and consistent with other reputable studies. The President of the American Gas Association, appearing before the House Subcommittee on Energy and Power, testified:

[A]ll of the recent authoritative estimates of remaining recoverable conventional natural gas resources in the U.S., including Alaska, are in the range of 700 to 1200 trillion cubic feet (Tcf). These include estimates of the U.S. Geological Survey, the National Academy of Sciences, and the Potential Gas Committee. Thus, at the current U.S. consumption rate of about 20 Tcf/year, there are between 35 and 60 years of conventional U.S. gas supplies remaining to be produced.

Natural Gas Issues 1979: Hearings Before the Subcommittee on Energy & Power of the House Comm, on Interstate & Foreign Commerce, 96th Cong., 1st Sess. 76 (1979) (Testimony of G. H. Lawrence).

The Feinstein estimate also fails to account for Northern’s non-traditional natural gas sources, including Alaska, Alaska offshore, Atlantic offshore, and the Arctic. A depreciation engineer for the Staff, Ronald Lucas, testified that the Commission was aware that Northern had recently invested in gas reserves in Alaska and the Arctic. Northern, in fact, agreed to pay $30 million for the dedication of 1.5 Tcf of natural gas in the Prudhoe Bay Field area, and pay $20 million to develop oil and gas sources in offshore Alaska and the Atlantic Coast. Northern has also agreed to advance $75 million for drilling expenditures in the Canadian Arctic Islands. See Northern Natural Gas Co., SEC File No. 1-3423, Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 [SEC Form 10-K] at pp. 12-14 (for fiscal year ending December 13, 1978).

Ill

It appears questionable, at best, that the Staff’s share factor analysis is reliable; it is surely not supported by substantial record evidence. The record clearly demonstrates that the Staff could not even make up its mind on how to measure Northern’s past experience. The Staff’s analysis changed drastically three times, leading to three different share factor determinations for the same year. Most distressing is the fact that the Staff’s determinations were obviously stretched to accommodate its settlement efforts.

In its initial filing, the Staff’s share factor determination for the Hugoton-Anadarko Basin was 10.40%. In the course of the RP 76-89 hearing, the Staff altered its determination to 4.65%. Finally, in the RP 77-56 hearing, the Staff raised its share factor determination once again to 6.30%. Although the Staff could not properly account for its own internal inconsistencies, the Commission ultimately adopted the Staff’s latest attempt, notwithstanding the fact that in 1977 Northern acquired 8.14% of the Hugoton-Anadarko area reserve additions.

Besides these internal inconsistencies, several other factors reveal that the Commission’s estimate of Northern’s market share is fatally flawed. The Commission’s estimate for RP 76-89 was the weighted average of Northern’s share in the years 1974 and 1975; this figure was determined to be 10.40%. This share factor was later altered, based in part upon Northern’s 1976 percentage share. In the end, the Staff determined Northern’s share factor based upon its past acquisition experience for a mere three years. Furthermore, Northern’s own witness testified that two of these three “test” years were extraordinarily “bad years.” These years were particularly bad due to the construction of large intrastate pipelines, and their success in securing reserves. The intrastate companies were not constrained by the federal regulatory ceiling that controlled the price they could offer producers for the area’s new gas supplies. The Staff estimate, thus, relied upon, a time when Northern was faced with bitter competition but unable to raise its prices to the higher intrastate level.

With the enactment of the NGPA, the intra/interstate distinction has been eliminated. By bringing price parity between interstate and intrastate gas pricing, the new legislation will permit Northern to secure increasing share factors. Northern’s witness, J. P. Guinane, testified that with some sort of price parity Northern would expect to acquire a percentage share of between 7% to 8%. Accordingly, even Northern’s own conservative estimate is higher than the Staff’s prediction. It is apparent that the Staff’s estimates ultimately rest upon its assumption, that the adverse impact of intra/interstate competition would continue for the next twenty years. This assumption is clearly erroneous and supported by absolutely no record evidence.

The Commission’s failure to consider Northern’s non-traditional gas supplies affects its market share analysis also. The Commission’s admitted decision to completely ignore potential gas supplies from new or non-traditional supply sources is inexcusable. Failure to even attempt to make a reasoned estimate of these non-traditional sources renders the Staff’s determination weak at best. The Staff’s own witness testified that the Commission was aware that Northern was actively engaged in an extensive program to obtain new gas supplies from the Canadian Arctic, Alaska, the Gulf Coast, the North Atlantic and from coal gasification. It is true that the Commission would have had to make a reasoned “guess” of the potential supplies from these non-traditional sources, but after all, that is the Commission’s job. It is inevitable that Northern will secure a share of these new supplies, and that they will flow through a part of the company’s existing Market Area facilities. Of course, any supplies retrieved from the Gulf Coast will most certainly flow through Northern’s Southend mainline. See Northern Natural Gas Co., SEC File No. 1-3423, Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 [SEC Form 10-K] at pp. 11-14 (for fiscal year ending December 31, 1978). See also Northern Natural Gas Co. Annual Report 1978 at pp. 5-7.

IV

The Congress of the United States has given the Federal Energy Regulatory Commission the important and sensitive responsibility of regulating natural gas rates. To determine appropriate rates the Commission must necessarily determine depreciation rates, and in order for it to do this, it must estimate the potential recoverable natural gas reserves available to pipeline companies. Recognizing the difficulty of estimating reserves, the courts have permitted the Commission to develop estimates within a “zone of reasonableness.” The Commission is expected tó use its expertise to establish a zone of reasonableness. It did not do so here. It simply developed a mathematical formula that fit the estimates to its settlement efforts. In so doing it ignored the conservative geological estimates of the Potential Gas Committee without giving adequate reasons. It also failed to develop alternative geological estimates of its own.

By permitting the Commission’s decision to stand, the majority gives support to a “zone of reasonableness” that permits estimates to vary by at least three hundred percent and by as much as four hundred and fifty percent. We don’t need experts if they can’t do better than that. It also gives support to the principle of ignoring nontraditional sources of natural gas to which a pipeline company has access; we don’t need experts if they hide from the facts.

The public interest demands that the Commission fulfill its responsibilities. Accordingly, I would remand this case to the Commission for action consistent with this dissent. 
      
      . The other two components are the Montana supply area and the Gulf coast area. These two areas combined amount to approximately five percent of Northern’s depreciable property. South Dakota abandoned its attack on the settlement rates for these two areas during the hearing before the administrative law judge in RP 76-89.
     
      
      . The FERC was established as part of the Department of Energy Organization Act which became effective on October 1, 1977. 42 U.S.C. § 7101, et seq. Most of the duties of the now defunct Federal Power Commission (FPC) were transferred to the FERC. These transferred responsibilities include the authority to set “proper and adequate” depreciation rates contained in section nine of the Natural Gas Act, 15 U.S.C. § 717h. Section 402(a)(2) of the Department of Energy Organization Act, 42 U.S.C. § 7172(a)(2), 91 Stat. 565, 584 (1977). Any reference to the Commission in this opinion corresponds to the appropriate agency depending upon the time frame..
     
      
      . The FERC regulations define depreciation as follows:
      “Depreciation,” as applied to depreciable gas plant, means the loss in service value not restored by current maintenance, incurred in connection with the consumption or prospective retirement of gas plant in the course of service from causes which are known to be in current operation and against which the utility is not protected by insurance. Among the causes to be given consideration are wear and tear, decay, action of the elements, inadequacy, obsolescence, changes in the art, changes in demand and requirements of public authorities, and, in the case of natural gas companies, the exhaustion of natural resources.
      
      FERC Uniform System of Accounts for Natural Gas Companies, 18 C.F.R. Part. 204-1 IB (1979) (emphasis added).
      There are, generally, two methods to assign depreciation cost. The first and most familiar is the straight line method which evenly distributes the cost of an asset over the full physical life. The second is based upon units of production. This method places emphasis on the total units to be produced and the rate of production. It takes into consideration the service life of an asset and thereby permits exhaustion of natural resources to be taken into account. The unit of production is prescribed by the Commission in its regulations. 18 C.F.R. Part. 201-404.1(B), 404.2(B) (1979). The FERC used the unit of production method to determine the settlement rates in question here.
     
      
      . The Northern Distributor Group is a collection of twelve natural gas distribution companies which provide service to approximately 1.5 million customers in five states with gas purchased from Northern. This group, as intervenor-respondents, supports the settlement figures as approved by the FERC.
     
      
      . Exhaustion of resources is expressly recognized as a factor in determining proper and adequate depreciation rates in the Commission’s uniform system of accounts. See n.3, supra.
      
     
      
      . The depreciation rates which RP 76-89 were designed to supersede were 4.65 percent and 3.75 percent for the South End and Market Area, respectively. Thus, the settlement figure for the Market Area is the same as the previous rate.
     
      
      . Estimates of natural gas supply and the share factor are clearly not the only steps in arriving at depreciation rates. But for purposes of this appeal, South Dakota has primarily based its attack on these issues. Therefore, a discussion of the remainder of the process is unnecessary.
     
      
      . For example, in the Hugoton-Anadarko field the EHF model predicted 37 trillion cubic feet (Tcf) while the PGC figures estimated 99 Tcf.
     
      
      . This is in contrast to the PGC estimate which is a geologically based study.
     
      
      . The following table is an example of the comparison between efforts and results made by the EHF model. This table details exploratory drilling and gas reserve statistics for the Permian Basin.
      Efforts Results
      New Field Footage Annual Cumulative Year 1000 ft. 1000 ft. Additions Reserve Cumulative* Annual Bcf** Bcf
      97,546 58,627
      1967 3,598 101,144 3,307 61,931
      1968 2,455 103,599 984 62,918
      1969 2,122 105,721 1,107 64,025
      1970 2,466 108,187 2,012 66,037
      1971 1,765 109,952 1,871 67,908
      1972 2,166 112,118 1,883 69,791
      1973 2,331 114,449 1,567 71,358
      1974 3,030 117,479 1,139 72,497
      1975 4,310 121,789 791 73,288
      1976 4,202 . 125,991 650 73,938
      * Includes New Field Discoveries, New Reservoir Discoveries, Extensions and a certain adjustment for additions not reported in the year of occurrence.
      ** Billion cubic feet.
      RP 77-56, Exhibit 17 (EHF-1), Schedule 14, p. 1595.
     
      
      . In RP 76-89, (before ALJ Benkin), Feinstein did not use a least squares method to plot the extension of the historical data. At that hearing he testified that he had simply “eyeballed it on a least square basis.” In the later proceeding, RP 77-56, Feinstein used data based upon the more precise least squares method. This procedure is defined as “a statistical method of fitting a line or plane to a set of observational points in such a way that the sum of the squares of the distances of the points from the line or plane is a minimum.” Webster’s Third New International Dictionary (Merriam-Webster 1971).
     
      
      . South Dakota suggests that the EHF model was created simply to support the settlement rates in this case. However, Feinstein testified that this approach has been used in about fifteen earlier rate cases before the Commission, most of which were settled. Also, the Commission has previously approved the basic approach of the EHF model. See Texas Eastern Transmission Corp., 54 FPC 1260, 1270-72 (1975).
     
      
      . South Dakota also claims that the model is so statistically unsupportable that its results are invalid. They rely upon the “t”-test of statistical significance. This test was conducted by the FERC staff following the hearing in RP 77-56. The “t”-test produces a significance level which measures the validity of using the relationships between variables to support a hypothesis. According to South Dakota, the FERC staff determined significance levels of .66 and .87 for the EHF models concerning the Hugoton-Anadarko and Permian Basin areas, respectively. South Dakota maintains in its brief that a .90 level of significance is required before such a study can be considered to be reliable.
      In its order denying rehearing, the Commission states that the “t”-test results were .80 and .90 for the two fields. The Commission also noted that if the figures for 1977 and 1978 are added to the data base, the “t”-test figure for the EHF model increases to over .97.
      The “t”-test figures are not a part of the record and therefore it is not possible for us to fully evaluate these arguments. We do note, however, that reserve additions for 1977 support the estimates derived from the EHF model. According to the FERC opinion, the EHF model predicted reserve additions of 700 Bcf in the Permian Basin and 2079 Bcf in the Hugoton-Anadarko for 1977. Actual additions were later confirmed to be 730 Bcf and 2081 Bcf, respectively.
     
      
      . “Probable” is defined as “the most assured of the new supplies.” The “possible” category is less assured supplies that will come from new field discoveries in previously productive formations. The “speculative” classification is described as the “most nebulous of new supplies.”
     
      
      . In RP 76-89 the FERC discounted the estimates from the “probable” and “possible” categories fifty percent as well as discounting the “speculative” category one hundred percent. ALJ Benkin criticized the discounting of the first two categories by fifty percent. In RP 77-56 the third category was also excluded by the staff but the “probable” and “possible” classifications were not discounted.
     
      
      . The Natural Gas Policy Act is designed to allow a carefully managed deregulation of newly discovered natural gas and, while this process takes place, the wellhead price of intrastate producers will be federally regulated. A purpose of the Act is to allow interstate pipeline companies, such as Northern, to compete with intrastate companies more effectively. See 19 Nat.Res.J. 811 (1979). The Act became effective in November 1978, and therefore any effect of this statute is not a part of the record.
     
      
      . Until 1978, the United States had a two-tier market of natural gas: interstate and intrastate. The interstate market was subject to federal control of wellhead prices while the intrastate market was not. See Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672, 74 S.Ct. 794, 98 L.Ed. 1038 (1954). Intrastate suppliers were thereby able to outbid interstate pipeline companies. See generally, R. Stobaugh and D. Yergin, Energy Future 56 et seq. (1979).
     
      
      . The accelerated depreciation rates will cause the rate base to decline more rapidly than it otherwise would if a realistic depreciation rate were used. While there may be an immediate improvement in cash flow that could be used to acquire new gas supplies, there is no medianism for insuring that the added funds will be used to benefit Northern’s gas customers inasmuch as Northern is a diversified company and may decide to invest the cash in its non-pipeline activities.
     
      
      . G. H. Lawrence, President of the American Gas Association, testified before the House Subcommittee on Energy and Power that the NGPA represented a major commitment on the part of Congress to develop an energy policy that is national in scope, definite in purpose and equitable in implementation. He noted that the Act promised “to deliver more domestic energy, thereby benefiting consumers by helping reduce higher cost oil imports and other higher cost energy alternatives.” Natural Gas Issues: Hearings Before the Subcomm. on Energy & Power of the House Comm, on Interstate & Foreign Commerce, 96th Cong., 1st Sess. 67 (1979) (Statement of G. H. Lawrence).
      Lawrence further testified that:
      Even at this early date the indications are that passage of the NGPA is playing a significant role in encouraging the production of gas energy from domestic production.
      * * * Investment by the gas production industry for drilling, exploration, and production is now rising rapidly. The 1979 figures are running some 14 percent over 1978 figures * * *.
      Second, seismic activity, which is the initial exploratory step has increased markedly. Last year was a boom year and so far 1979 has been even stronger. New seismic activity in early 1979 was up 8 percent over the corresponding period of 1978.
      Gas well completions set a record in 1978. Despite that new record the monthly data through April show that each month in 1979 has recorded even higher gas well completions. So far they are running 19 percent ahead of last year.
      New gas discoveries in Texas as of mid-May are 40 percent above the rate of discoveries recorded in 1978.
      $ sfs $ % $ $
      The statistics show that in 1978 deep well drilling was up over 60 percent from the previous year, much of this was in anticipation of the NGPA deep drilling incentives or other deep drilling incentives. This year with the special incentives in the Natural Gas Policy Act for the early deregulation below 15,-000 feet we fully expect this trend to continue since deep well drilling alone is up by 23 percent during the first 5 months of 1979 over the comparable period in 1978.
      
        Id. at 67-68.
      The Congressional Subcommittee also received testimony from the Aspen Institute for Humanistic Studies, in the form of a prepared written Executive Summary of a Workshop on “R & D Priorities and the Gas Energy Option” published in June, 1978. The Institute was comprised of 50 noted scientists, engineers, economists, environmentalists and industry leaders, who exchanged research at a seminar extending over a five-day period. The Institute concluded that traditional and non-traditional sources of natural gas were potentially plentiful and would play a significant role in America’s energy policy.
      The Conference was sponsored by the Aspen Institute in cooperation with the American Gas Association and the Gas Research Institute. The Institute’s conclusions were optimistic about the future of natural gas as an energy resource in the United States. The Institute concluded, inter alia, that:
      U.S. resources of conventional natural gas are large, constituting 30 to 60 times current annual production levels. With relaxation of price controls for new natural gas, current production levels of gas in the U.S. can' be sustained, and perhaps even increased, at prices comparable to projected prices for fuels refined from imported oil. * * *
      
        Id. at 139.
      The Institute’s Summary also reported that the critical variable in making more gas available was price — i. e., deregulation. The prepared testimony continued: “Higher prices over the past few years have already resulted in increased drilling and reserve additions. In 1977, reserve additions were the highest in ten years.” Id. at 145.
     
      
      . Northern’s customers are all too aware of the company’s benefit from deregulation. In 1978, Northern filed a purchased gas adjustment of $100 million with the Commission. In July, 1979, it announced that it had acquired 1,000,-000 acres óf land to explore for natural gas. Northern also requested permission from the Commission to increase deliveries of gas to its customers. In that request it admitted that its new reserves were nearly three times as high as Feinstein had estimated in this proceeding and in excess of the reserves estimated by the petitioner, South Dakota Public Utilities Commission.
     
      
      . If speculative reserves were included in the PGC estimates, the total potential recoverable reserves estimated by the PGC in the two basins would increase to over 200 Tcf.
     
      
      . Some of these differences can be explained, but not adequately, by the Staffs handling of “revisions” to gas reserve estimates and of its consideration of Northern’s 1976 share when it became available. The Staff adjusted Northern’s share factor based, in some unknown part, upon the impact of “revisions.” Attempting to account for revisions in evaluating Northern’s year to year acquisition experience is dangerous, and introduces potentially serious distortions because revisions cannot be vintaged. The Staffs share factor attempts to vintage them, but in the same breath admits that revisions are not associated with gas discovered in the year in which the revisions are made. Furthermore, the Staff does not explain the vintage allocations that it made.
     