South Dakota Public Utilities Commission v. Federal Energy Regulatory Commission

934 F.2d 346, 290 U.S. App. D.C. 58, 118 Oil & Gas Rep. 378, 1991 U.S. App. LEXIS 10436

• Court: Court of Appeals for the D.C. Circuit
• Decided: May 24, 1991
• Docket: Nos. 90-1136, 90-1215 and 90-1237
• Status: Published

Opinion

Opinion for the Court filed by Circuit Judge STEPHEN F. WILLIAMS.

STEPHEN F. WILLIAMS, Circuit Judge:

In the decisions under review the Federal Energy Regulatory Commission addressed a problem arising from natural gas pipelines’ and producers’ adjustments of their contract relations in response to federal ceiling prices on interstate sales at the wellhead. The Federal Power Commission (FERC’s predecessor) initially attempted to conform to Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672, 74 S.Ct. 794, 98 L.Ed. 1035 (1954), which construed the Natural Gas Act to require such ceilings, by setting “just and reasonable” rates producer by producer. The process proved “laborious”, so much so as to earn it recognition as the “outstanding example in the federal government of the breakdown of the administrative process”. Permian Basin Area Rate Cases, 390 U.S. 747, 758, 88 S.Ct. 1344, 1355, 20 L.Ed.2d 312 (1968). The Commission then switched to setting “area” rates, governing sales by all producers in each of several regions.

The ceiling prices put interstate pipelines at a competitive disadvantage vis-a-vis intrastate pipelines, which could offer market prices. To mitigate that disadvantage, the interstates often agreed to include indefinite price escalator clauses in their long-term purchase contracts. After initial uncertainty, the Commission authorized one form of indefinite price escalator (and only one), the “area rate clause”, which automatically raises the price to the area rate applicable at the time of delivery. See Order No. 329, 36 FPC 925 (1966), codified at 18 CFR § 154.93(b-l) (1990). The pipeline whose contracts are at issue here, Northern Natural Gas Company, agreed to such clauses in about 1200 contracts between the mid-1960s and 1978.

When Congress passed the Natural Gas Policy Act in 1978, it took away most of FERC’s authority to set “just and reasonable” rates and instead provided statutory ceilings. See 15 U.S.C. § 3301 et seq. (1988). The question arose whether area rate clauses, which generally spoke in terms of escalation to “just and reasonable” rates set by the Federal Power Commission, authorized producers to demand the new NGPA ceilings. For gas covered by § 104 of the NGPA, for example, this would be the April 20, 1977 “just and reasonable” rate plus an adjustment for general price inflation thereafter. See 15 U.S.C. § 3314. The parties do not state what price would apply if the area rate clause did not authorize NGPA rates, but it appears likely that under most contracts the producer would be entitled to no more than the rate the gas had reached at some point before the effective date of the NGPA.

In Order No. 23, FERC Statutes & Regulations, Regulations Preambles 1977-1981 ¶ 30,040 (1979), FERC decided that area rate clauses indeed could be interpreted to authorize collection of NGPA rates. See id. at 30,315-16. If the parties to a contract agreed on that interpretation; their agreement would normally control. Id. at 30,316. If protesters (such as those here, a purchaser from Northern and representatives of downstream consumers) offered specific evidence that the clause in question did not supply contractual authority, the case would be set down for a hearing; if not, the protest would be dismissed. See Order No. 23-B, FERC Stats. & Regs. ¶ 30,065 at 30,455 (1979); Order on Rehearing Order No. 23-B, FERC Stats. & Regs. ¶ 30,073 at 30,475-76 (1979); see also 18 CFR § 154.94 (1990) (codifying the rules). The Fifth Circuit upheld these arrangements, with some modifications, in Pennzoil Co. v. FERC, 645 F.2d 360 (5th Cir. 1981). See also Pennzoil Co. v. FERC, 789 F.2d 1128 (5th Cir.1986); Hunt Oil Co. v. FERC, 853 F.2d 1226 (5th Cir.1988).

More than ten years ago Northern invoked the Commission’s procedure, filing a list of over 1200 contracts containing area rate clauses that it and the relevant producers agreed authorized payment of NGPA rates. Various protesters challenged the submission, pointing to a statement by Peoples Natural Gas Company, then a division of Northern’s parent company, made in litigation with a producer, that a specific area rate clause, worded exactly the same as some of those in the Northern contracts, did not require Peoples to pay NGPA ceiling rates. The Commission decided that “Peoples’ interpretation of the contract language , can be attributed to Northern because of common control,” see Northern Natural Gas Co., 33 FERC II 61,355 at 61,706 (1985), and that this satisfied the protesters’ initial burden. It sent the matter to an administrative law judge for a hearing. Id.

After extensive discovery, including two opportunities for the protesters to review all of Northern’s relevant files, the AU held the required hearing. Fourteen Northern officials and 56 producer witnesses testified for Northern and were cross-examined at length, producing a transcript of about 5400 pages. See Northern Natural Gas Co., 43 FERC ¶ 63,015 at 65,147-48, 65,169 (1988) (“Initial Decision”); Northern Natural Gas Co., 48 FERC ¶ 61,177 at 61,649 (1989) (“Order”), reh’g denied, 50 FERC ¶ 61,288 (1990). Another 58 producer witnesses were prepared to testify, but the AU decided that their testimony would be cumulative — 56 was enough. The protesters offered no witnesses. See Initial Decision, 43 FERC at 65,147-48; Order, 48 FERC at 61,649.

The AU ruled that the evidence “overwhelmingly” showed that Northern and the producers intended the area rate clauses “to trigger payment of all generally-applicable ceiling prices established by federal authority”. See Initial Decision, 43 FERC at 65,149, 65,169. The AU considered the contract language, the parties’ testimony of mutual intent, their course of dealing, their course of performance, and trade usage. Id. at 65,149-69. The Commission upheld the AU’s decision, emphasizing the evidence of the parties’ course of performance. Order, 48 FERC at 61,651-52. We affirm.

The AU framed the issue as being whether Northern and the producers “intended [area rate clauses] to trigger payment of NGPA ceiling prices when the contracts at issue were entered into.” Initial Decision, 43 FERC at 65,147 (emphasis omitted). The Commission’s Order sometimes used a similar formula, see, e.g., 48 FERC at 61,648, and sometimes spoke of intent in a more generalized way, referring, for example, to evidence of “ ‘Northern’s intent to pay the highest prices allowed by law or regulation’ ”, id. at 61,651 (evidently quoting a Northern witness). The latter formula tracks the Commission's conclusion in Order No. 23 that many gas producers and pipelines, in agreeing to area rate clauses, “intended to permit prices to escalate to the highest generally applicable ceiling rate allowed by governmental authority”. FERC Stats. & Regs, at 30,314.

Neither formula seems to us to quite confront the reality of the case. It appears common ground that, at least until the latter part of the period, the parties were unlikely to have guessed that Congress would set the ceilings itself. For contracts of the earlier period, it seems something of a fiction to infer by “interpretation” that the parties “intended” escalation to statutory ceilings. Even the more general formula, which treats the parties’ reference to Commission-determined rates as a shorthand for a broader intent (to escalate to the highest lawful rate), suffers the same flaw in a more subtle form: if the only issue the parties had occasion to address was fully solved by the narrower language, their intent as to the broader issue is hardly historical reality.

A number of contracts scholars frankly acknowledge the special character of such an inquiry. Farnsworth, for example, speaks of addressing issues that the contract language “omits”, see E. Allan Farnsworth, Contracts §§ 7.15-.17 (1982), and Corbin distinguished between “interpretation”, a term he reserved for exploring the meaning of words actually used, and “construction”, which he applied to “filling gaps in the terms of an agreement, with respect to matters that the parties did not have in contemplation and as to which they had no intention to be expressed”, 3 Corbin on Contracts § 534 at 11 (1960). See also 6 Samuel Williston, A Treatise on the Law of Contracts § 825 (3d ed. 1962) (on “Fictitiously Imputed Intentions”). Thus a blunter way of framing the issue would be to ask whether the parties would have intended area rate clauses to authorize payment of NGPA rates if they had anticipated them at the time they negotiated the clauses. The distinction is helpful, as we shall see shortly, because it puts in proper perspective a number of points raised by petitioners’ counsel that assume the sole inquiry is into historical intent.

For the end of the period, while Congress was hammering out the terms of the NGPA, it can hardly be said that the parties omitted reference to statutory ceilings because they failed to foresee their arrival. For this period another reason comes into play (which indeed had been at work throughout the period, inhibiting anyone who did imagine the problem) — the Commission’s explicit rule that area rate clauses were the sole permissible form of indefinite price escalator. See 18 CFR (b-l).¹ Here the inquiry more aptly concerns what the parties would have provided had the Commission allowed them to express their intent. As the Commission was obviously aware of the problem as it formulated Order No. 23, the order reflects its judgment that its earlier restriction of parties to area rate clauses should not prevent collection of statutory ceilings where the parties would have agreed to them. See FERC Stats. & Regs, at 30,315 (despite the limitations of 18 CFR § 154.93, FERC will give effect to escalator clauses that “specifically permit escalation to Congressionally or legislatively authorized prices or which specifically reference Natural Gas Policy Act prices”).

In affirming the ALJ, the Commission rested primarily on the evidence as to course of performance, which of course is probative whether one thinks of the problem in terms of historical or reconstructed intent. With narrow exceptions addressed later, Northern paid the NGPA ceilings for more than six years — and not through oversight or inattention. Before the statute went into effect on December 1, 1978, officials of its Supply Division and its Law Department began internal discussions on the issue. See Initial Decision, 43 FERC at 65,160. Three days before the President signed the Act, a company attorney circulated a memo among the gas acquisition staff asserting that the area rate clauses in Northern’s contracts entitled producers to charge the NGPA prices. See Memorandum from Patrick J. McCarthy (Nov. 6, 1978), reprinted in Joint Appendix (“J.A.”) at 1614. Its conduct clearly conformed to this view for more than six years.

Protesters regard this long pattern as completely undermined by Northern’s decision, implemented on January 1, 1985, to stop paying NGPA ceiling prices under the contracts at issue for categories of gas still subject to regulation. They claim this shift reveals that the prior six years’ behavior was merely a ploy “to curry favor with Producers in a time of shortage”, Reply Brief for Petitioners at 13 n. 13, and assert that Northern’s true construction emerged only in 1985 when it stopped paying NGPA prices because of a gas glut. As the petitioners see it, the post-1984 evidence is paramount because it shows that Northern did not intend to be obligated by the area rate clauses to pay NGPA ceiling prices “under all market conditions ”. Brief for Petitioners at 19 (emphasis in original).

It is undisputed, however, that Northern sought price relief, in the form of contract amendments, without regard to whether the area rate clauses in its contracts were in any way applicable. See, e.g., Letter from Northern to Horizon Oil & Gas (Sept. 4, 1984) (form letter proposing contract amendments), reprinted in J.A. at 1970. Indeed, Northern acted the same as to contracts with clauses expressly referring to congressional price ceilings — clauses that, while inconsistent with the language of 18 CFR § 154.93(b-l), the Commission had expressly found effective in Order No. 23. See Initial Decision, 43 FERC at 65,163; see also FERC Stats. & Regs, at 30,315. Moreover, Northern’s price-reduction efforts focused heavily on gas that was deregulated as of January 1, 1985, and on which area rate clauses could have no effect. Even in the case of contracts that could be affected by area rate clauses, petitioners have uncovered no effort by Northern to justify its price cutback moves by a revisionist approach to those clauses. There is ample evidence to support the Commission’s conclusion that the cutbacks were implemented not in reliance on the clauses but in spite of them. See Order, 48 FERC at 61,652; Initial Decision, 43 FERC at 65,163. Finally, petitioners’ argument would seem to eliminate course of performance evidence from contract disputes. Some sort of resistance to past performance, on one side or the other, would seem a prerequisite to a dispute’s ever landing in court. If performance is automatically negated by later resistance, then it is hard to imagine a case it would help resolve.

For their claim that the pre-1985 performance was variable, petitioners point to Northern’s refusal to pay the special “tight sands” ceiling prices authorized by the Commission pursuant to § 107(c)(5) of the NGPA. But from the moment the Commission established the “tight sands” rate, it reasoned that the rate could only function as an incentive for producers to increase production of such gas if it was available only where it was “a negotiated contract price”; FERC thus rejected reliance on a mere indefinite price escalator. See 18 CFR §§ 271.701-703 (1990); see also Pennzoil Co. v. FERC, 671 F.2d 119 (5th Cir.1982) (upholding the requirement); Midwest Gas Users Ass’n v. FERC, 833 F.2d 341 (D.C.Cir.1987). In refusing to treat area rate clauses as justifying the tight sands rate, Northern merely hewed to the Commission’s line.

The other alleged exception is the refusal of Northern’s affiliate, Peoples Natural Gas, to pay NGPA rates (except for gas under § 104 of the NGPA) — the conduct that led to the hearings in the first place. The AU found, however, that Peoples, a local distribution company regulated by state authorities, not by FERC, acted as it did because of concerns peculiar to its regulatory environment. In particular, Peoples feared (and later events proved) that Kansas regulators would refuse to allow it to pass NGPA rates through to its customers. See Initial Decision, 43 FERC at 65,-166-67. The AU also found that the decisionmaking of the two affiliates was largely independent on the issue, a finding backed by substantial evidence. See id. at 65,167-68. Thus the course of performance evidence for the period prior to Northern’s general effort to cut its gas costs back appears essentially unqualified.

Petitioners devote much of their brief to various witnesses’ testimony that the intent of the clauses was just what they said (see, e.g., Brief for Petitioners at 54-58), that “just and reasonable” rates referred only to rates set by the Federal Power Commission (Brief for Petitioners at 51), and that the parties intended to conform to the Commission’s requirements in 18 CFR § 154.93(b-l) (Brief for Petitioners at 58-60), and to documentary evidence of similar import (Brief for Petitioners at 45-49). If the issue were truly one of historical intent, these might be telling blows. But when the problem is viewed as one of how to fill a contract gap — how to address a circumstance that the contract plainly omitted — the statements look irrelevant and even tautological.

We note that even petitioners’ literalism has bounds. Even though the escalation clauses conforming to the language of 18 CFR § 154.93(b-l) could refer only to area rates, petitioners appear not to read them as excluding coverage of the national rates that the Commission started to promulgate in 1974. See Opinion No. 699, 51 FPC 2212 (1974). Nor, even for clauses referring only to the Federal Power Commission, do petitioners read them as excluding coverage of rates set by FERC after its creation in 1977.² While this is not necessarily a case of straining at a gnat after swallowing a camel, it leaves us puzzled as to petitioners’ principle of construction.

The petitioners also point to testimony suggesting rather obliquely that Northern would not have agreed to price escalator clauses that would require it to “pay even if its customers won’t pay Northern for the gas”, see J.A. at 983; Brief for Petitioners at 53, i.e., if the escalated price exceeded what Northern’s customers were willing to pay. Indeed, as Congress obviously cannot reexamine natural gas pricing as frequently as a regulatory commission, the shift to statutory ceilings carried the risk that the ceilings would outrun the market, as in fact occurred. But that shift also contained the risk of ceilings well below market-clearing prices. As the ceilings would bind if they were below market, at the expense of producers, it is hardly surprising for the parties to have agreed that pipelines should bear the opposite risk.

Moreover, the ALJ reasoned that pipelines would be more concerned with the average price of gas than with the risk of some above-market purchases. See Initial Decision, 43 FERC at 65,158. The point is quite correct: interstate pipelines, operating under average-cost price regulations, do not “lose” the difference between the cost and selling price of a unit of gas (bought for more than the selling price), as would an unregulated firm; the above-average unit is “rolled” into the average, i.e., it gives the pipeline legal authority to charge a higher price. See id.3 Further, the Commission’s analysis of the effect of area rate clauses leaves untouched any price-reduction claims and any defenses to non-performance that a pipeline might assert under other clauses of the contracts (such as market-out clauses) or under general contract doctrines (such as impractica-, bility). Finally, petitioners have framed the argument as a general one that appears to dispute the basic premises of Order No. 23 — the sort that we have ruled out as a collateral attack on Order No. 23. Associated Gas Distributors v. FERC, 810 F.2d 226, 231-33 (D.C.Cir.1987).

The last of petitioners’ claims that is marginally worthy of discussion is their suggestion that Northern and the producers did not meet their burden for the numerous contracts as to which no producer witness testified (what petitioners call the problem of “non-appearing producers” or “NAPs”). The petitioners’ idea appears to be that there is a failure of evidence as to such contracts. But the testimony of the Northern witnesses encompassed all the contracts, as did the course of performance evidence. The 56 producer witnesses confirmed Northern’s picture (as was to be expected in view of the producers’ interest in escalated prices). In the absence of some hint that matters were different for any other producer, there was no reason for the AU to acquiesce in petitioners’ effort to further bloat the proceedings. Compare Pennzoil Co. v. FERC, 789 F.2d at 1145 n. 44; see also Order No. 23-B, FERC Stats. & Regs. ¶ 30,065 at 30,453-55 (anticipating pipeline-by-pipeline review of protests, with initial submission of evidence only by pipelines).

Finding substantial evidence in support of the Commission’s orders, we deny the petitions for review.

So ordered.

1 . Curiously, even the version published in 1990 contains only the reference to area rates, although the Commission had started setting national rates for certain gas in 1974. See Opinion No. 699, 51 FPC 2212 (1974).

2 . See Department of Energy Organization Act, Pub.L. No. 95-91, 91 Stat. 565 (1977), terminating the FPC and replacing it with FERC.

3 . And, if rate regulation has held the pipeline’s rates to a relatively inelastic portion of its demand curve, materially below the level that would maximize its profits in an uncontrolled ■ market, the pipeline will be able to charge the higher lawful rate with only a limited offsetting reduction in sales. An unregulated firm, by contrast, would presumably charge profit-maximizing rates anyway, and any purchase at a price above that rate would simply cost it money.