Public Utilities Commission v. Federal Energy Regulatory Commission

817 F.2d 858, 260 U.S. App. D.C. 135

• Court: Court of Appeals for the D.C. Circuit
• Decided: May 1, 1987
• Docket: Nos. 86-1078, 86-1158, 86-1172 and 86-1210
• Status: Published

Opinion

Opinion for the Court filed by Circuit Judge STARR.

STARR, Circuit Judge:

This case comes to us in the wake of Congress’ restructuring of the pricing system for natural gas. Two questions are presented: the first concerns the proper disposition of funds remaining in a pipeline producer’s deferred tax reserves following a change in pricing structure; the second relates to the availability of a certain price category, the replacement contract price, for gas produced by a pipeline. In our view, the Federal Energy Regulatory Commission failed adequately to explain its resolution of the first issue; in addition, the second issue, we are persuaded, is not in an appropriate posture for review by virtue of a related pending issue before the Commission. We therefore remand both issues to the Commission.

I

Prior to 1978, sales of natural gas were regulated under the Natural Gas Act (NGA), 15 U.S.C. § 717 et seq. (1976 & Supp. V). Initially, FERC’s predecessor, the Federal Power Commission, regulated the gas rates of interstate pipelines,¹ but not those of independent producers. The FPC set rates for pipeline-producer gas on a “cost-of-service” basis, allowing the pipeline to be reimbursed for “all expenses incurred, including income taxes, plus a reasonable return on capital.” Public Service Co. v. FERC, 653 F.2d 681, 683 (D.C.Cir.1981).

In 1954, the Supreme Court held that the NGA conferred jurisdiction on the FPC over rates charged by independent producers of gas, as well as pipeline producers, in sales in interstate commerce. Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672, 74 S.Ct. 794, 98 L.Ed. 1035 (1954). At first, the Commission employed its individualized cost-of-service methodology across the board, but the sheer number of independent producers soon forced it to set rates for those producers on a regional, and eventually a nationwide basis. See Permian Basin Area Rate Cases, 390 U.S. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968); Shell Oil Co. v. FPC, 520 F.2d 1061 (5th Cir.), cert. denied, 426 U.S. 941, 96 S.Ct. 2660, 49 L.Ed.2d 394 (1976). The FPC continued, however, to use cost-of-service ratemaking for all pipeline-producer gas until 1969. At that point, it extended independent-producer pricing to a limited category of pipeline-producer gas.²

Congress completely revamped the regulation of natural gas, including pricing structures, in the Natural Gas Policy Act of 1978 (NGPA), 15 U.S.C. § 3301 et seq. (1982). Under section 104 of the NGPA, the maximum price for gas is set at the just and reasonable rate established by the Commission under the NGA and is thereafter adjusted over time by a statutory formula. 15 U.S.C. § 3314(b)(1). In interpreting the new statute, the Commission determined that the NGPA applied only to gas produced by independent producers;

FERC thus continued to regulate pipeline producers in accordance with pre-NGPA policies. In Public Service Commission of New York v. Mid-Louisiana Gas Co., 463 U.S. 319, 103 S.Ct. 3024, 77 L.Ed.2d 668 (1983), however, the Supreme Court held that pipeline-producer gas, as well as independent-producer gas, was subject to NGPA pricing. As a result, the pipeline producer whose rates are under review here, El Paso Natural Gas Company, was able to switch from cost-of-service rate-making to the more lucrative NGPA system.

El Paso’s transition from the old rate structure to the new regime was not entirely smooth. Because the two issues raised in this petition are, for all practical purposes, unrelated, we discuss them separately, turning first to the disposition of the deferred tax reserve created under the pri- or system of pricing (cost-of-service) and then to the availability of the replacement contract gas price category for El Paso’s gas.

A

Under cost-of-service ratemaking, the Commission required the amortization of expenses, typically mandating that a current utility expense not be borne entirely by current ratepayers, but rather be charged to customers over time.³ This policy, however, created a problem for the Commission with respect to the pipeline producer’s income taxes, one of the cost elements included in the cost-of-service rates. Determining the proper tax allowance was problematical because, whereas an expense was allocated over time for rate purposes, the tax laws generally permitted the pipeline producer to deduct the expense more quickly through accelerated depreciation.

Over the past twenty years, the Commission alternately employed two methods (“flow-through” and “normalization”) to deal with the timing differences between its pricing policies and the tax treatment of expenditures. See Memphis Light, Gas & Water Div. v. FERC, 707 F.2d 565, 568 (D.C.Cir.1983) (describing history). Under the “flow-through” method, the Commission allowed customers to receive the entire benefit of a tax deduction at the time the pipeline producer took the deduction. As this court put it not long ago, “[t]he primary rationale for flow-through is the actual taxes paid principle, i.e., in each year customers are charged no more than the current tax liability of the utility.” Public Systems v. FERC, 709 F.2d 73, 76 (D.C.Cir.1983) (Public Systems II). Under the “normalization” method, on the other hand, the benefit of a tax deduction is spread evenly over the period that customers were charged for the expense. “The primary rationale for normalization is the matching principle, i.e., equity demands that the customers who pay the expense receive the tax benefit associated with that expense.” Id4

After 1975, the Commission consistently permitted employment of the normalization method. As tax buffs might suspect, normalizing taxes for rate purposes allowed the pipeline producer to collect more from its customers in early years than needed to cover current taxes (because, as explained above, of accelerated depreciation). During the period when amounts collected from ratepayers for taxes exceeded actual taxes paid, FERC required the pipeline producer to account for the difference by creating and maintaining reserves for deferred taxes. The Commission also required the pipeline producer to deduct the amount reflected in the deferred tax reserves from its rate base. The rationale undergirding this requirement was twofold: (1) that the pipeline producer should not be permitted to earn a return on funds contributed by ratepayers, and (2) that the pipeline should not be able to use the funds for purposes other than payment of taxes when those taxes ultimately became due. See Memphis Light, Gas & Water Div., 707 F.2d at 568, 572; Public Systems v. FERC, 606 F.2d 973, 976 (D.C. Cir.1979). The pipeline producer thus functioned as a custodian, as it were, of the deferred tax funds, until such time as the taxes were due and owing.

This system had a direct and substantial effect on El Paso. Over the period when its gas was priced on a cost-of-service basis, El Paso accumulated a sizable sum (approximately $147 million) in its deferred tax reserves. With the advent of NGPA pricing, however, tax costs (and tax benefits) became irrelevant to the calculation of El Paso’s rates, because under the NGPA, rates are no longer cost-based but are instead set according to a statutory formula. See supra text at 860. FERC was therefore faced with the question of what to do with the amount accumulated by El Paso in the deferred tax reserves.

Before the Commission, petitioners argued that the deferred tax reserves were intended to benefit future ratepayers, because taxes were normalized in order that customers who paid an expense would get the benefit that accompanied the expense.⁵ They contended that allowing El Paso to keep the reserves would result in an unjustifiable windfall, and urged that El Paso be required to refund the reserves to its customers.

The Commission’s staff agreed that the reserves were intended to inure to the benefit of future ratepayers, but suggested a different solution than that championed by petitioners. The staff maintained that “the most rational and equitable approach to adopt in this case (consistent with the principles underlying normalization) is to require that El Paso continue to maintain its deferred tax account, reducing its rates to its customers in the future by amounts equal to those which are over time drawn down from the account to pay the previously deferred tax liability.” Initial Brief of the Commission Staff (Initial Brief), Joint Appendix (J.A.) at 123-24. The staff further opined that, until the reserves were depleted, “the balance in the account must be deducted from El Paso’s rate base.” Id. See supra text at 861.

Unconvinced by either the petitioners or its staff, the Commission awarded the deferred tax reserves to El Paso. Addressing the staff’s suggestion, the Commission stated, in conclusory fashion, that “it would be inappropriate from an accounting standpoint to continue to credit the deferred taxes against El Paso’s remaining rate base after the associated property is removed.” Order Resolving Deferred Issues (Order), J.A. at 235. No explanation was provided for this conclusion. In addition, the Commission observed that “if the production-related deferred taxes are credited against El Paso’s remaining rate base, then El Paso will in effect, be able to cross-subsidize its transmission business with production-related deferred taxes.” Id.

As is evident, FERC’s abbreviated objections are directed solely at the staff’s recommendation that the reserves continue to be deducted from El Paso’s remaining rate base; by so limiting its focus, the Commission ignored the conceptual core of the staff’s approach. Under the staff’s proposal, the deferred tax funds would inure to the benefit of future customers because, although ratepayers pay the full NGPA ceiling price, part of their payment would come out of the reserves. This resolution, the staff argued, would achieve fairness to El Paso and “all generations of ratepayers” because “El Paso receives the intended benefits of tax normalization (e.g., improved cash flow) but is not permitted a windfall. Ratepayers, on the other hand, are also treated equitably in that the tax benefits associated with expense transactions are evenly distributed over time as required by the matching principle.” Initial Brief, J.A. at 124.

We recognize full well that the Commission is not obligated to justify deviations from an approach suggested by its own staff. Cf. National Fuel Gas Supply Corp. v. FERC, 811 F.2d 1563, 1571 (D.C. Cir.1987). After all, it is the Commission’s decision, not a staff recommendation, which is under review. Here, however, treatment of the conceptual underpinnings of the staff’s approach seems to us critical to a reasoned resolution of the problem. The staff, in essence, argued that FERC will achieve the most equitable solution to the dilemma of the deferred tax account by carrying out the reserves’ initial purpose. That common-sense position raises difficult issues of equity, which need squarely to be addressed. Since in the post-NGPA era rates are no longer based on El Paso’s cost of service, it is no longer possible for FERC to ensure that the deferred tax reserves will be utilized for their intended purpose of matching the receipt of tax benefits with the payment of the expenses that generated those reserves. It may be, however, that the reserves’ purpose can at least be effectuated in part through an arrangement by which the intended beneficiaries (El Paso’s future customers) are the eventual recipients through rate adjustments. On the other hand, it may be (although it is by no means clear to us at this juncture) that the future customers’ claim to the funds under the cost-of-service regime was somehow compromised or diminished by El Paso’s transition to NGPA pricing. The difficulty for us is that FERC never grappled with any of these competing considerations; it devoted its attention to perceived flaws in alternate approaches while failing adequately to explain the comparative advantages of its approach (favoring El Paso) over those alternatives. The Commission’s analysis, when measured against the standard of reasoned decision-making, is intolerably mute, see Greater Boston Television Corp. v. FCC, 444 F.2d , 853 (D.C.Cir.1970), cert. denied, 403 U.S. 923, 91 S.Ct. 2233, 29 L.Ed.2d 701 (1971); cf. Center for Science in the Public Interest v. Department of the Treasury, 797 F.2d 995, 999 (D.C.Cir.1986); International Ladies’ Garment Workers’ Union v. Donovan, 722 F.2d 795, 817-18 (D.C.Cir.1983), and thus deficient in a critical respect.

After disposing, too quickly, of the staff’s approach, the Commission went on to reject petitioners’ request for a refund to the ratepayers. In this regard, the Commission explained that the deferred taxes are not “customer-contributed capital or a ‘loan’ by customers to the pipelines.” Order, J.A. at 235. This conclusion was not without basis in the case law. In Public Systems II, we recognized that, inasmuch as ratepayers receive tax benefits in proportion to the expenses they pay “[normalization does not charge ratepayers for any costs in excess of those associated with the service they receive.” 709 F.2d at 85-86. Instead, “each generation of customers pays its own costs.” Id. at 85. Moreover, we expressly rejected in that case the proposition that ratepayers have an “equitable interest” in the deferred taxes. Id. at 86 n. 30. In light of Public Systems II, FERC’s reasoning in this respect is correct so far as it goes, but its articulated analysis does not, again, adequately support the decision to permit the funds to remain entirely with El Paso.

It may be that, by virtue of the change in rate-setting methodologies ushered in by the NGPA, an entirely fair manner of treating the deferred tax reserves will be highly difficult to craft.⁶ But an issue of such moment requires the careful consideration and explanation demanded under the standard of reasoned decisionmaking. See Citizens to Preserve Overton Park, Inc. v. Volpe, 401 U.S. 402, 414-17, 91 S.Ct. 814, 822-24, 28 L.Ed.2d 136 (1971); FEC v. Rose, 806 F.2d 1081, 1087-89 (D.C.Cir.1986); National Black Media Coalition v. FCC, 775 F.2d 342, 354-56 (D.C.Cir.1985); Motor Vehicle Manufacturers Association v. EPA, 768 F.2d 385, 389 n. 6 (D.C.Cir.1985), cert. denied, — U.S.-, 106 S.Ct. 852, 88 L.Ed.2d 892 (1986). We therefore remand this issue to the Commission for further consideration and explanation of why the reserves should not redound to the benefit of El Paso’s future customers and, should the Commission stick to its guns, why El Paso enjoys a greater equitable claim to the reserves than its past customers (whose rates generated the funds now reflected in the reserves). It should go without saying that, upon further reflection, the Commission need not adhere to its present position, but it must at all events support whatever disposition it embraces with a reasoned analysis.

B

In addition to the tax reserves issue, El Paso’s switch to NGPA pricing also raised questions with respect to the categorization of its gas for rate purposes. As we noted earlier, the maximum lawful price for gas under section 104 of the NGPA is the just and reasonable rate established by the Commission under the NGA, increased over time by an inflation factor. The NGA price thus serves as the reference point by which the new NGPA price is established.

After Mid-Louisiana, in which the Supreme Court held that pipeline-producer gas was eligible for NGPA pricing, FERC was required to incorporate pipeline producers into the NGPA scheme. In doing so, FERC interpreted the Mid-Louisiana decision as mandating identical treatment of pipeline-producer and independent-producer gas. The Commission therefore held that the NGPA baseline figure for pipeline-producer gas would be the NGPA price that would have applied to the gas if it had been sold by an independent producer. Order No. 391, 49 Fed.Reg. 33,849 (1984). Thus, the method of pricing for independent-producer gas became potentially relevant for pipeline-producer gas, and therein lay the genesis of the issue now before us.

One of the Commission’s NGA categories for independent producers was “replacement contract gas.” For a producer to qualify for the replacement contract rate, the Commission required that the gas be sold under a contract, executed within a certain window of time, which replaced a prior contract that expired by its own terms.⁷ As of October 1, 1983, the maximum lawful price for replacement contract gas was 84.9 cents per MMBtu, whereas the flowing gas rate for other gas was generally 47.5 cents. The incentive to embrace the replacement contract method of pricing was thus substantial and clear.

When El Paso elected to switch to NGPA pricing, it sought, not surprisingly, to take advantage of the more favorable replacement contract gas rate. There was a threshold difficulty, however, with El Paso’s approach; pipeline gas is not sold pursuant to a contract.⁸ To surmount this pesky hurdle, El Paso imputed sales , contracts for its gas. It assumed that the production of its various leases was subject to twenty-year contracts (a common contract term) executed on the date that production commenced on the particular lease. El Paso then applied the replacement contract rate in cases where an independent producer would have qualified for that rate on the date the imputed replacement contract was “executed.”

The Commission rejected El Paso’s creative classification scheme, reasoning that the existence of a real contract (not an imputed one) constituted an absolute prerequisite to qualification for the replacement contract rate. Consigned to the lower rate, El Paso attacks FERC’s decision, arguing that the Commission must allow it to impute a contract in order to achieve pricing parity for all sources of natural gas, regardless of the producer’s identity — a goal, according to El Paso, under-girding the NGPA and endorsed by Mid-Louisiana.

In our view, this issue is not now in an appropriate posture for resolution. The reason for our reticence to resolve this question is that in Phillips Petroleum Co. v. FERC, 792 F.2d 1165, 1170 (D.C.Cir.1986), this court held, contrary to FERC’s view of the matter, that the Supreme Court’s Mid-Louisiana decision did not mandate parity pricing treatment of pipeline-producer and independent-producer gas. Rather, as our court pointed out, the Supreme Court in Mid-Louisiana explicitly assumed that the NGA reference point for pipeline prices under the NGPA would be derived from old cost-of-service levels, not the national levels applicable to independent producers. Id. The Phillips court therefore remanded the issue for the Commission to exercise its judgment in determining the proper NGPA section 104 baseline figure for pipeline-producer gas.

On the Phillips remand, FERC may decide to base section 104 prices on the pipeline’s earlier cost-of-service rate. In that event, the replacement contract rate dispute — which assumes that independent-producer pricing controls — would disappear. On the other hand, FERC may construe section 104 as affording pipeline-producer gas the benefit of independent-producer prices. If the Commission so concludes, it is appropriate that FERC have an opportunity to reevaluate the replacement contract issue in light of its analysis of the language and policy of section 104. We therefore remand this issue to the Commission for further consideration and resolution in light of its eventual decision in the Phillips remand.

It is so ordered.

1 . Pipeline companies that produce gas from company-owned wells in addition to transporting, natural gas from production fields to consumers are commonly referred to as "pipeline producers."

2 . In 1969, the FPC decided to apply independent-producer rates to gas produced by pipeline companies from leases acquired after October 7, 1969. In 1974, the FPC extended independent-producer pricing to pipeline gas from wells drilled after January 1, 1973.

3 .For instance, intangible drilling costs, such as drilling contractor charges, drilling equipment rental, and related labor costs, are generally capitalized and amortized in the pipeline’s rates as production occurs.

4 . The courts have upheld employment of both methods. Alabama-Tennessee Natural Gas Co. v. FPC, 359 F.2d 318, 339 (5th Cir.), cert. denied, 385 U.S. 847, 87 S.Ct. 69, 17 L.Ed.2d 78 (1966) (flow-through); Public Systems II, 709 F.2d at 86 (normalization). See Memphis Light, Gas & Water Div., 707 F.2d at 568 (describing history of usage, including early decisions concluding that normalization in ratemaking was not required by the tax laws).

5 . Petitioners are Public Utilities Commission of California, ASARCO, Inc., Inspiration Consolidated Copper Company, Kennecott Copper Company, and Magma Copper Co.

6 . It is arguable that none of the three contenders — El Paso, past customers, and future customers — enjoys a superior equitable interest in the reserves. If that is the case, FERC must, of course, justify its decision to favor one of the three similarly situated sets of claimants in a reasoned manner, such as by a careful analysis of the Congressional policies informing the regulatory scheme in question.

7 . The Commission’s regulations implementing the NGPA incorporate a definition of replacement contract gas which provides in pertinent part:

"Replacement contract gas or recompletion gas” means natural gas to which this subpart applies which is

(i) Sold under a replacement contract which was executed on or after January 1, 1973, but prior to November 9, 1978, where the prior contract expired by its own terms prior to January 1, 1973; or

(ii) Sold under a replacement contract executed prior to November 9, 1978, where the prior contract expired by its own terms after January 1, 1973[.]

18 C.F.R. § 271.402(b)(4) (1986).

8 . The "sale” of pipeline-produced gas is not subject to a contract because the “sale” typically occurs in an intracorporate transfer from a pipeline’s production division to its transportation division.