
    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, and Northern Natural Gas Company, Intervenor-Respondents.
    No. 79-2020.
    United States Court of Appeals, Eighth Circuit.
    Submitted Sept. 15, 1981.
    Decided Nov. 25, 1981.
    As Amended Feb. 9, 1982.
    
      Frances E. Francis, South Dakota Public Utilities Commission, Spiegel & McDiarmid, Washington, D. C., for petitioner.
    Joshua Z. Rokach, Federal Energy Regulatory Commission, Washington, D. C., for F. E. R. C.
    George Meiburger, Gallagher, Boland, Meiburger & Brosnan, Washington, D. C., for intervenor, Northern.
    Before LAY, Chief Judge, and HEANEY, BRIGHT, STEPHENSON, HENLEY, McMILLIAN and ARNOLD, Circuit Judges, En banc.
    
    
      
      The Honorable DONALD R. ROSS, United States Circuit Judge, took no part in the consideration or decision of this case.
    
   HEANEY, Circuit Judge, with whom LAY, Chief Judge, and BRIGHT and McMILLIAN, Circuit Judges, join.

This matter is before the Court en banc on the petition of the South Dakota Public Utilities Commission to review an order of the Federal Energy Regulatory Commission (FERC). The order permitted the Northern Natural Gas Company (Northern) to depreciate certain equipment over a period of time shorter than its physical life on the theory that Northern’s supplies of natural gas would be exhausted prior to the time the equipment became obsolete. When the matter was first before a panel of this Court, 643 F.2d 504, we affirmed. We now reverse. We hold that the depreciation rates fixed by FERC are neither within the zone of reasonableness nor supported by substantial evidence. The rates appear to have been developed to support settlement rates agreed to by Northern and its wholesale customers rather than on the basis of natural gas reserves that are or will become available to Northern. The FERC substantially underestimated the natural gas reserves in Northern’s traditional supply areas, significantly understated the share of future reserves from those areas that Northern can be expected to purchase, and failed to give any weight to the fact that Northern has entered into several agreements which reasonably insure that it will receive substantial supplies of natural gas from nontraditional supply areas during the physical life of its equipment.

We reverse and remand to the FERC.

I. FACTUAL AND PROCEDURAL BACKGROUND

Northern is a major interstate transporter of natural gas with revenues exceeding one billion dollars per year. Its pipelines move 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, in Montana and in Wyoming. For the purpose of computing depreciation, Northern’s properties are divided into four components, two of which are of primary importance here. The first is referred to as the South End supply area. The South End links Northern’s traditional major supply fields — the Hugoton-Anadarko and the Permian Basins — to the rest of the Northern system. The second major component is referred to as the Market Area which 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 available in areas capable of supplying Northern, and what share of those estimated reserves Northern would be able to acquire. The depreciation rates developed by the Staff were determined by a modified unit of production method which allocates depreciation costs on the basis of the volume of gas that is expected to flow through the facility (its useful life) rather than its physical life. 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 should be 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. The physical life of the equipment, however, will not end until about the year 2011. In these circumstances, the FERC concluded that an increased rate of depreciation was appropriate. Therefore, the gravamen of this litigation, and the subject of nearly 7,000 pages in this voluminous record, is how much natural gas Northern can reasonably expect to have available to it for purchase between now and 2011.

The FERC order approved settlement agreements in two related rate cases filed by Northern. The first, RP 76-89, was filed on April 22, 1976. It requested rate increases of $71.7 million per year. The second, RP 77-56, was filed about a year later, while the earlier case was still pending. It requested additional rate increases of $109 million per year. Both were requests for general rate increases that eventually were narrowed to the single issue of proper rates of depreciation.

Negotiations between the FERC and Northern in RP 76-89 began in August, 1976. Thirty-one petitions for leave to intervene were granted; most of the petitioners were local utilities. Several state regulatory agencies were also represented including the South Dakota Public Utilities Commission and the Iowa State Commerce Commission. In October, 1976, the FERC approved Northern’s settlement rates, setting the composite depreciation rate at 4.48 percent and providing for rate increases of $57 million per year. South Dakota filed adverse comments on the settlement proposal. The FERC rejected South Dakota’s arguments. On application for rehearing, the Commission 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, the ALJ found that neither the settlement rates nor those proposed by South Dakota were supported by substantial evidence. He held that Northern’s preexisting 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 providing for increases of $63.6 million per year. South Dakota again 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 similar issues were pending before the FERC. In August, 1979, the Commission issued its order consolidating the two dockets and approving the settlement rates calling for increases of $120.6 million per year. South Dakota made an application for rehearing which was denied on October 4, 1979. 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 nine of the Act, 15 U.S.C. § 717h, authorizes the FERC to determine “proper and adequate rates of depreciation” for natural gas companies within its jurisdiction. Section four, 15 U.S.C. § 717c, requires that the depreciation rates set by the FERC pursuant to section nine must be “just and reasonable.” See Memphis Light, Gas and Water Division v. Federal Power Commission, 504 F.2d 225, 230 n.19 (D.C.Cir.1974). A final Commission decision on a contested settlement must be supported by substantial evidence. Placid Oil Co. v. Federal Power Commission, 483 F.2d 880, 893 (5th Cir. 1973).

The FERC has been granted wide latitude to use its expertise to set depreciation rates. Section 19(b) of the Natural Gas Act, 15 U.S.C. § 717r(b), 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(2)(E). The United States Supreme Court has interpreted the role of a court reviewing ratemaking orders as follows:

[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. * * 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.” [Citations omitted.]

Permian Basin Rate Cases, 390 U.S. 747, 791-792, 88 S.Ct. 1344, 1372-1373, 20 L.Ed.2d 312 (1967).

While the discretion accorded the FERC in ratemaking is wide, it is not unlimited. The FERC cannot rely on empty recitals of agency expertise to sustain its decision. It must use that expertise and give “reasoned consideration to each of the pertinent factors.” Permian Basin Rate Cases, supra, 390 U.S. at 792, 88 S.Ct. at 1373; Tenneco Oil Co. v. Federal Energy Regulatory Commission, 571 F.2d 834, 839 (5th Cir. 1978); American Public Gas Association v. Federal Power Commission, 567 F.2d 1016, 1030 (D.C.Cir.1977), cert. denied, 435 U.S. 907, 98 S.Ct. 1456, 55 L.Ed.2d 499 (1978). We, as a reviewing court, have a responsibility to carefully search the record to determine whether or not the FERC has “articulatefd] some rational relation between the facts found, supported by substantial evidence, and the action which it took.” Memphis Light, Gas and Water Division v. Federal Power Commission, supra, 504 F.2d at 230. In sum, our primary role is to decide whether the rate selected by the FERC is within a “zone of reasonableness,” whether the agency has given reasoned consideration to each of the pertinent factors and whether the ultimate rate is just and reasonable.

Only one other court has discussed its role in the special circumstances of a FERC order allowing an increase in depreciation rates due to decreasing supplies of natural gas. Memphis Light, Gas and Water Division v. Federal Power Commission, supra, 504 F.2d at 232-233, 235. There, the District of Columbia Circuit reversed and remanded a FERC order where there was no evidence in the record regarding the future reserves available to the pipeline company. Id. at 236. The court found that the Commission accepted the utility’s projections without sufficient critical examination and stated that an increase in depreciation rates 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 identified three pertinent factors that the Commission must consider in making its reasoned estimate, each of which is relevant here:

(1) FERC’s independent judgment based on evidence pertinent to 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 utility may utilize. Id. at 235.

As discussed below, the FERC failed to adequately consider these and other factors in selecting its depreciation rates.

III. DISCUSSION

The FERC found that the models used by the staff established a zone of reasonable estimates of natural gas available in Northern’s traditional supply areas (the Hugoton-Anadarko and Permian Basins). The lower bounds of the zone was marked by the “EHF” model, and the upper bounds by the “PGC” model. It then found that the staff’s final estimate of the share of gas reserves available to Northern from these areas, which was based on a weighted average of Northern’s share for 1974, 1975 and 1976, was a reasonable one.

The following tables set forth the depreciation rates derived from the two models, the present rates and the settlement rates.

RP 77-56
EHF PGC Settlement
South End 5.45 4.79 4.65 5.25
Market Area 3.96 3.10 3.75 3.75
RP 76-89
South End 5.44 4.99 4.65 5.15
Market Area 4.02 3.33 3.75 3.75

Before discussing whether the models properly establish a zone of reasonableness, it would be well to explain the models in some detail.

The EHF model is named for Edward H. Feinstein, a member of the Commission staff. The EHF model is statistically based and predicts annual reserves based on a theory that relates drilling efforts to results. The model uses historical data to project future reserves. The theory assumes 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. Hugoton-Anadarko and Permian Basin fields are mature basins.

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 relationship of effort to results was 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 is based on national data and was used to determine the respective depreciation rates by applying these national averages to the basins here.

The PGC model is based upon estimates of natural gas reserves developed by the Potential Gas Committee (PGC) in conjunction with the Potential Gas Agency at the Colorado School of Mines. The Potential Gas Agency is supported by the American Gas Association. The PGC model is one of the few studies which utilizes factual regional data, including data from the two basins here. The estimate represents the potential supply to be found by wells expected to be drilled in the future under conditions of (1) adequate but reasonable prices, and (2) normal improvements in technology. Estimates are made for only those accumulations which occur at less than 30,000 feet. Gas from nonconventional sources is not included. The estimates have remained reasonably consistent since 1968.

PGC divides its estimates into the following categories:

Proved reserves — Proved reserves are the current estimated quantity of natural gas which analysis of geologic and engineering data demonstrate with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions. * * *
Potential supply — This is the prospective quantity of gas yet to be found or to be added to existing fields exclusive of proved reserves. It is divided into the following three categories:
Probable — The most assured of new supplies resulting from the growth of existing fields. This includes extensions and new pools in productive discovered reservoirs and shallower or deeper new pool discoveries within existing fields in formations productive elsewhere within the same geologic province or subprovince. * * *
Possible — Less assured is the supply from new field discoveries in formations previously productive; such new fields would be distinctly separated from existing fields.. As an example, an undrilled structure would be in this category.
c. Speculative potential gas supply (associated with non-productive formations.)
(1) Supply from new pool discoveries in formations not previously productive within a productive geologic province or subprovince.
(2) Supply from new field discoveries obtained by:
(a) Future new field discoveries in formations not previously productive within a productive geologic province or subprovince.
(b) Future new field discoveries within a geologic province not previously productive. [Emphasis included.]

Potential Supply of Natural Gas in the United States (as of December 31, 1976), Potential Gas Committee, Potential Gas Agency, Colorado School of Mines at 5, 6 & 30 (1977).

With this background, we turn to the question of whether the rates approved by the FERC are within the zone of reasonableness. In our view, they are not for the following reasons:

A. The rates appear to have been developed to support the settlement rates, and the share factor analysis is not supported by substantial evidence in the record.

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 natural gas reserves available in the Hugoton-Anadarko and Permian Basins would be those estimated by the Potential Gas Committee (PGC) in 1972— discounting the probable and possible categories by 50 percent and eliminating the speculative category entirely. Then using a weighted average of Northern’s shares in 1974 and 1975, the Staff estimated that Northern would secure 10.40 percent of the available natural gas in the Hugoton-Anadarko Basin and 9.06 percent of the available reserves in the Permian Basin. Based on these estimates, the Staff arrived at depreciation rates that approximated those agreed to in the settlement agreement.

The matter was appealed to the Commission which held that the Staff had demonstrated no basis for discounting the possible and probable categories by 50 percent. The Staff then took a different approach to predicting reserves. E. H. Feinstein of the Staff utilized the above-described EHF model using data for each year from 1970 to 1976. His estimates of the natural gas reserves in the Hugoton-Anadarko and Permian Basins using this formula were higher than those predicted using the discounted PGC estimates. Feinstein then reduced the estimate of Northern’s share of these reserves to 4.65 percent for Hugoton-Anadarko and 8.22 percent for Permian. As a result, his estimates of natural gas available to Northern from the two basins were even less than the Staff’s initial predictions.

Feinstein then made a third attempt at estimating total reserves. He adopted the PGC’s 1976 estimates for probable and possible natural gas supplies in the Permian and Hugoton-Anadarko Basins, once again excluding the speculative category. Next, he estimated Northern’s share in the relevant basins to be 6.3 percent for Hugoton-Anadarko and 9.29 percent for Permian. These percentages represented the weighted average of Northern’s shares from 1974 to 1976. Feinstein contends that the change in percentages was the result of the addition of Northern’s share for 1976 and the inclusion of American Gas Association “revisions” of previously reported reserves. The net result was that his estimate of reserves available to Northern again approximated the reserves predicted by the settlement agreement.

In commenting on Feinstein’s effort, the ALJ 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. But that is not the Staff’s function. Its function here was conscientiously to draw reasoned inferences from data which in its best judgment most closely correspond to the truth.

Docket No. RP 76-89, Initial Decision of Administrative Law Judge, at 30 (1978).

Wé agree with this statement. We would add that neither the Staff nor the Commission has given any satisfactory explanation for reducing Northern’s shares from 10.4 percent and 9.06 percent to a lower level. The Commission does state that the final share factors — 6.3 percent for the Hugoton-Anadarko Basin and 9.29 percent for the Permian Basin — represent the average of the shares acquired by Northern for the years 1974, 1975 and 1976. It argues that these years are more apt to predict the future than the years suggested by South Dakota, 1971-1976. (Under the latter suggestion, Northern’s share factor would be 17.22 percent for the Hugoton-Anadarko Basin and 14.89 percent for the Permian Basin.)

If the Staff had adhered to the data for the same three-year period from the start, one might be inclined to accept the decision as a rational one; but it did not. After having to modify its total reserve projections, the Staff adjusted the shares three times to bring the final result within the terms of the settlement agreement. Moreover, at the time the decision was being considered by the Commission, two additional years of experience — 1977 and 1978— were available which it did not use. In 1977, Northern acquired 8.14 percent of the available gas in the Hugoton-Anadarko Basin and 14.49 percent of the natural gas in the Permian Basin. In 1978, Northern acquired 7.98 percent of the reserves available in the Hugoton-Anadarko Basin and 12.77 percent of the reserves available in the Permian Basin. If the Commission modified its estimates to reflect the addition of recent data, as it did for the 1976 data, it could and should have also used the information that was available for 1977 and 1978, information which reflects Northern’s ability to acquire a larger share of the gas in the basins here as a result of the Natural Gas Policy Act.

Moreover, Northern’s shares during the 1974-1976 period used by the Commission were particularly low due to intense competition from intrastate companies which were not subject to the federal price ceiling that controlled interstate companies. With the enactment of the Natural Gas Policy Act, the intrastate/interstate distinction has been eliminated. As a result of the new price parity, Northern, as its own witness admitted, can reasonably expect to obtain an increased share of the natural gas available in the Hugoton-Anadarko and Permian Basins. Indeed, this fact is evidenced by the larger shares that Northern obtained in 1977 and 1978 — which the Commission ignored.

B. The EHF model on which the rates are primarily predicated is seriously flawed.

The validity and reasonableness of the EHF model is critical to the Commission’s decision. It is the model primarily relied upon by the Commission to estimate the reserves in Northern’s traditional supply areas — the Hugoton-Anadarko and Permian Basins. This model projected the following reserves:

EHF PGC
Hugoton-Anadarko Basin 37 99
Permian Basin 10 55
47 Tcf 154 Tcf

(The PGC model is shown at this point to illustrate the fact that if the Commission had relied on it, Northern’s reserves of natural gas would be more than sufficient to meet Northern’s need through the life of its equipment.)

In our view, neither the validity nor the reasonableness of the EHF model has been sustained by substantial evidence on this record.

1. The model unduly minimizes the importance of developmental drilling during a period when rising prices have led to increased drilling activity. For example, in 1976, 1.5 Tcf of natural gas were added to the reserves in the Hugoton-Anadarko Basin by developmental drilling while only .211 Tcf were added to the same reserves by new field drilling. Similarly, 9,234 exploratory wells were drilled in the United States in 1976 compared to 7,539 in 1973, an increase of 22 percent. Thus, even if the model might have some validity at another time, it has little or none during this period. Higher prices brought about by the Natural Gas Policy Act and OPEC have led to massive developmental drilling which is not predicted with any degree of accuracy by a historical analysis of new field drilling. To illustrate this point, between 1972 and 1976, higher prices made drilling at depths between 15,000 and 30,000 feet feasible in the Hugoton-Anadarko Basin. This drilling resulted in additions of 28 Tcf to the reserves of that basin — an incremental addition that a lone equals 76 percent of the total reserves projected by the EHF model.

2. The study imputes the results of studies of nationwide gas production to the Hugoton-Anadarko and Permian Basins. No substantial evidence has been introduced to justify this extrapolation. In contrast, the PGC breaks down its estimates into regions, including the Hugoton-Anadarko and Permian areas.

3. The results give the impression of facial absurdity. The model projects that 80 percent of the reserves in the Hugoton-Anadarko Basin and 75 percent of the reserves in .the Permian Basin will remain undiscovered through the year 2000. There is no evidence in the record to support this result.

4. The EHF estimates ignore 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 record is replete with evidence that, by early 1979, the Act, whatever else it had accomplished, was already beginning to achieve its goal of encouraging new drilling, exploration and production of natural gas.

5. The model did not consider reserves in the two basins below the level of 15,000 feet even though wells below that depth were producing as early as 1976.

6. The Commission argues that the EHF estimates are substantiated by the testimony of Gary D. Hancock, Manager of Supply Evaluation for Northern. He theorized that the natural gas available in the Hugo-ton-Anadarko and Permian Basins would be limited by the fact that not more than 2,300 drilling rigs would be operating in the time period in question here. In fact, by the time this case was presented to the Commission, a substantially greater number of drilling rigs were already in operation.

C. The PGC model developed by the FERC staff falls within the zone of reasonableness but it was essentially ignored by the Commission in predicting reserves available in the Hugoton-Anadarko and Permian Basins.

The PGC model used by the Staff and approved by the Commission projected reserves of 99 Tcf in the Hugoton-Anadarko Basin and 55 Tcf in the Permian Basin. Even though these estimates entirely exclude the PGC speculative category, they project total reserves in the two basins which are 97 Tcf larger than those projected by the flawed EHF model. To put it another way, the PGC model projects reserves three times as large as the EHF estimate. If the speculative reserves were included, the differences would be even larger.

The Commission, commenting on these differences, stated: “Widely divergent estimates are not uncommon, and the Commission is satisfied that both of the staff’s models are serious and careful studies satisfying the requirements of Memphis.” It cited a 1977 study of the PGC as support for its position. The study does not support the Commission’s claim of wide divergence. In fact, the study flatly contradicts the Commission’s position. It states:

[W]hen the quantities of natural gas expressed in the various estimates are placed on the same basis and when the differences in basic assumptions and method of approach are considered, there is a remarkable degree of uniformity among most workers as to the most likely value of the quantity of natural gas yet to be discovered and developed within the United States.

A Comparison of Estimates of Ultimately Recoverable Quantities of Natural Gas in the United States: A Potential Gas Committee Report, Potential Gas Agency, Colorado School of Mines, at 9 (1977).

That the estimates are nearly uniform is clearly demonstrated by a close examination of Appendix No. 1, which has been reproduced from the 1977 PGC comparison study. This appendix not only debunks Feinstein’s testimony that the estimates of the PGC are the highest in the field, but it also demonstrates graphically that the estimates of the PGC are remarkably consistent with other projections. The PGC estimates are particularly close to other predictions when the speculative category has been excluded, as they have been here. The chart below, derived from Appendix No. 1, illustrates this fact. We have included only those projections subsequent to 1972 which can reasonably be compared to the PGC projections.

Institution Conducting the Study Proved Probable Possible Total
PGC — 1972 266 266 384 916
U. S. Geological Survey— 1974 (95% probability) 237 202 322 761
Institute of Gas Technology — 1974 (Low estimate) 237 663 900
Mobil — 1973 250 52 485 787
Exxon (full inventory— mean estimate) 237 111 582 930

These estimates of total reserves of natural gas in the United States are very close indeed. The ratio between the lowest, U. S. Geological Survey, and the highest, Exxon, is only 1 to 1.20. Appendix No. 2 also illustrates clearly that the PGC estimates are conservative and well in line with those conducted by other major institutions.

D. The Commission’s estimates fail to give any weight to nontraditional natural gas sources in which Northern has made substantial investments, 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 agreed to pay $30 million for the right to purchase 1.5 Tcf of natural gas in the Prudhoe Bay area at two cents per Mcf, and agreed to pay $20 million for development of natural gas fields 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). The total Northern investment in these areas was $125 million from which it expects to receive substantial supplies of natural gas in the years ahead to supplement its purchases from its traditional supply areas and from Montana and the Gulf Coast.

Moreover, Northern contracted, in the late 1970s, to purchase gas from Canadian sources to help meet its needs until the Alaskan, Atlantic Coast and Arctic were able to deliver natural gas to it. Natural gas was being delivered pursuant to this contract at the time the final hearing on this matter was being held.

In projecting the natural gas reserves that will be available to Northern, the Commission failed to give any weight to these substantial efforts by Northern to secure gas from non-traditional sources.

In sum, we are thoroughly convinced from a careful review of the entire record that the EHF estimates of natural gas reserves reasonably available to Northern are without support in the record and are not within the zone of reasonableness. The EHF estimates are substantially less than the PGC predictions which the Staff also examined. The PGC is one of the most respected analysts in the natural gas industry and its projections are well in line with those of other groups. Nevertheless, without any apparent rational basis, the EHF model totally eliminates the PGC’s speculative category and then reduces the remainder by 300 percent. Moreover, the EHF projection ignores entirely the fact that Northern has spent at least $125 million to acquire the right to obtain reserves from non-traditional sources that show at least a reasonable probability of being productive. Prudence obviously dictates that a discount factor be applied to the speculative category of the PGC estimates and to non-traditional sources, but it also demands that some weight be given to these sources in setting the upper limits of the zone of reasonableness. The result is that Northern’s consumers are unfairly overcharged.

The Commission finally argues, however, that if the depreciation rates it established now are too high, it can reduce them in a later rate ease. The trouble with this theory is that the cost of Northern’s service to its present consumers is unnecessarily excessive. Even if the facts are adjusted in the future, there is no guarantee that the present consumers will be compensated by such adjustments. Moreover, the Commission’s approach creates a disincentive for Northern to acquire new supplies of gas. 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 mechanism 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.

IV. CONCLUSION

The Congress of the United States has given the Federal Energy Regulatory Commission the important and sensitive responsibility of regulating natural gas rates. To set appropriate rates, the Commission must necessarily determine depreciation rates; and 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 to use its expertise to establish a zone of reasonableness. It did not do so here. It simply developed a mathematical formula that insured that its reserve estimates supported its settlement efforts. In so doing, it ignored the conservative geological estimates of the Potential Gas Committee which predicted reserves three times as large as those predicted by the Staff’s EHF model. It also ignored non-traditional sources available to Northern. The FERC, with its expert staff, can certainly do better than that.

The public interest demands that the Commission fulfill its responsibilities. Accordingly, this case is remanded to the Commission with directions to it to vacate the rate increase granted pursuant to the orders being reviewed here and for further proceedings consistent with this opinion.

STEPHENSON, Circuit Judge,

dissenting, with whom HENLEY and ARNOLD, Circuit Judges, join.

I respectfully dissent for the reasons stated in the majority panel opinion which I authored. See South Dakota Public Utilities Commission v. Federal Energy Regulatory Commission, 643 F.2d 504 (8th Cir.), rev’d en banc, 668 F.2d 333 (8th Cir. 1981). 1981).

The role of a court reviewing a decision by the FERC is limited to determining whether the FERC has given reasoned consideration to each of the pertinent factors. See South Dakota Public Utilities Commission v. Federal Energy Regulatory Commission, supra, 643 F.2d at 509.

It is my view that the Commission has given “reasoned consideration” to all of the pertinent factors in the formulation of the depreciation rates in question. Moreover, as noted in the panel opinion, “[t]he special responsibility placed in the hands of the FERC and the corresponding limited role of judicial review has often dictated the result.” Id. at 510 (citing Tenneco Oil Co. v. Federal Energy Regulatory Commission, 571 F.2d 834, 840 (5th Cir. 1978); Shell Oil Co. v. Federal Power Commission, 520 F.2d 1061, 1071 (5th Cir. 1975)).

It remains my view that the combination of these two factors should likewise have dictated the result in this case.

Appendix No. 1

Appendix No. 2

X-ASSUMING THE PROPRIETY OF ADDING VALUES FOR: PROSPECTIVE RESERVES TO EXPECTED VALUE (MOBIL) INFERRED RESERVES TO MEAN VALUE (U.S.G S )

Figure 5 depicts the estimates of the quantities which include "most likely" or mean values from each of the four sources.

The values may not all be exactly comparable but they do represent values of the quantity of undiscovered gas which can be expected to be found with a reasonable (on the order of 50% probability) degree of certainty. There is a close similarity among the estimates which have been made by the majority of estimators vhen one considers that the sum of the most likely value of possible potential supply and the probable growth of known fields should be about the same order of magnitude as the most likely, or 50% probability, quantity in statistical evaluation. Exxon's full inventory value is the most comparable to the PGC, Mobil and USGS estimates.

Appendix No. 3

tt ASSUMING THE PROPRIETY OF ADDING VALUES FOR: PROSPECTIVE RESERVES TO 10% PROBABILITY (MOBIL) INFERRED RESERVES TO 5% PROBABILITY VALUES (U.S.G.S.)

The estimates shown on Figure 6 include the total probable plus possible plus speculative categories of the Potential Gas Cctnmittee and the estimates of low probability fran the other three sources previously considered. It seems ranarkable, when recognizing the uncertainties involved in these types of estimates, that the values fran these independent sources should be relatively close together, ranging fran about 1 to 1.6 times as much potential, essentially undiscovered, gas as has been previously discovered. 
      
      . The other two components are the Montana supply area and the Gulf Coast area. Together, these two areas contain 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 or FERC 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 determine depreciation cost. 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. We find no error in this decision.
     
      
      . The Minnesota Public Service Commission intervened on appeal.
     
      
      . Permian Basin Rate Cases, 390 U.S. 747, 791-792, 88 S.Ct. 1344, 1372-1373, 20 L.Ed.2d 312 (1967); Mobil Oil Corp. v. Federal Power Commission, 417 U.S. 283, 307-308, 94 S.Ct. 2328 (1974); Gulf Oil Corp. v. Federal Energy Regulatory Commission, 575 F.2d 67, 70 (3rd Cir. 1978); Tenneco Oil Co. v. Federal Energy Regulatory Commission, 571 F.2d 834, 838-840 (5th Cir. 1978); American Public Gas Association v. Federal Power Commission, 567 F.2d 1016, 1028-1030 (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, 504 F.2d 225, 230 (D.C.Cir.1974).
     
      
      . Feinstein testified that the method used in the EHF model is to
      analyze and extrapolate the historical exploration results with the expended effort. * * By expended effort, I mean “new field drilling footage.” * * * My model dictates that it is unnecessary to use the intermediate efforts, such as extensions, deeper horizons, and development [drilling] to arrive at total reserve additions. [Emphasis added.]
      Docket No. RP 77-56, Record, vol. 3, at 527-528.
     
      
      . In its 1976 study, the PGC reported that
      The most significant change from the 1972 Potential Gas Committee estimates for this area has been made in the estimates for the deeper portion of the Anadarko basin at depths between 15,000 feet and 30,000 feet. There is a major increase of 28 TCF in the Possible category. Increased drilling activity has taken place in the deep trough of the basin in response to increases in natural gas prices, which have made high risk, very costly ventures more attractive from an economic standpoint. This has resulted in new data and significant discoveries. Several new fields have been discovered at intermediate depths and producing potential of the ultra-deep Hunton and Ellenberger/Arbuckle has been demonstrated. Recent discoveries in the Hunton have shown high deliverability (8 BCF per well per year) and high ultimate recovery (100 BCF per well). In addition to the prolific Hunton reservoir, the Mills Ranch and West Mayfield discoveries in 1974 and 1976 have added the Ellenberger/Arbuckle deep carbonate reservoir as a viable commercial target with potential that could overshadow the ultimate gas recovered from the earlier Hunton Fields.
      Potential Supply of Natural Gas in the United States (as of December 31, 1976), Potential Gas Committee, Potential Gas Agency, Colorado School of Mines, at 13-14 (1977).
     
      
      . G. H. Lawrence, President of the American Gas Association, testified before the House Subcommittee on Energy and Power as follows:
      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.
      # sf! Jjt
      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. 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.
      
        Natural Gas Issues: Hearings Before the Sub-comm. on Energy & Power of the House Comm, on Interstate & Foreign Commerce, 96th Cong., 1st Sess. 67, 68 (1979) (Statement of G. H. Lawrence).
      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 nontraditional sources of natural gas were potentially plentiful and would play a significant role in America’s energy policy.
      The Institute’s Summary also reported that the critical variable in making more gas available was price — in other words, 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.
      Additionally, J. P. Guinane, Manager of Gas Acquisition for Northern, substantially corroborated this view of the effect of the Act in his testimony. Docket No. RP 77-56, Record, vol. 2, at 39-48.
     
      
      . The projections that are not shown on the table were either prepared prior to 1972 or did not break down potential reserves into categories corresponding to those used by the PGC. The estimates that are included in the table substantially correspond to the PGC’s proved, probable and possible categories. The PGC’s categories are used to facilitate comparison. The values depicted in the table may not all be exactly comparable but they do represent values of the quantity of gas which can be expected to be found with a reasonable degree of certainty. See A Comparison of Estimates of Ultimately Recoverable Quantities of Natural Gas in the United States: A Potential Gas Committee Report, Potential Gas Agency, Colorado School of Mines, at 10 (1977).
     
      
      . A third exhibit was prepared by the PGC. It is reproduced and included here as Appendix No. 3. With respect to this exhibit, which includes speculative categories, the PGC noted:
      It seems remarkable, when recognizing the uncertainties involved in these types of estimates, that the values from these independent sources should be relatively close together, ranging from about 1 to 1.6 times as much potential, essentially undiscovered, gas as has been previously discovered.
     
      
      . For example, Northern’s Vice President John R. Brady testified that as a result of its agreements to obtain natural gas from Alaska, “[Northern’s] customers now are able to look forward to a very substantial gas supply from a domestic source which will be available in the market area in the relatively near-term future.” Docket No. RP 77-56, Record, vol. 2, at 58-59.
     
      
      . The Staff’s failure to seriously consider the availability of natural gas from non-traditional sources is illustrated by the following testimony of its principal expert, E. H. Feinstein:
      Q. Why did you limit your estimates to the traditional sources only?
      A. [Feinstein] I guess my answer is that I was really only requested to come up with— to provide Ron Lucas with an estimate for the traditional sources of supply.
      If you recall, I adopted Ray Vincent’s testimony, and his testimony was in relation to the traditional sources of supply. That was in 76-89.
      Docket No. RP 77-56, Record, vol. 3, at 525.
     
      
      . On the other hand, we cannot agree with South Dakota’s contention that the Commission erred in consolidating the 1976 and 1977 proceedings.
     
      
      . The compounding effect of underestimating both Northern’s share factor from the two basins and the reserves available in those basins results in projected reserves for Northern that are at least 3.9 times lower than those predicted by the Staff’s PGC model.
     