Court Opinion

ID: 8912940
Source: CourtListenerOpinion
Date Created: 2022-11-27 03:47:54.30243+00
Date Added: 2024-06-11T17:08:42.037411
License: Public Domain

HEANEY, Circuit Judge
dissenting.
I
I respectfully dissent. The depreciation rates fixed by the Commission are neither *516within 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.
*517First, 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.1
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 permit*518ting prices to rise will stimulate production and increase the supplies of natural gas available to consumers.2 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.3
*519Third, 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.4 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 *520the 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,5 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 *521between 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 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 *519as 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.