
    EAST TENNESSEE NATURAL GAS COMPANY, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent.
    No. 89-1506.
    United States Court of Appeals, District of Columbia Circuit.
    Argued Jan. 28, 1991.
    Decided Jan. 24, 1992.
    
      Petition for Review of Orders of the Federal Energy Regulatory Commission.
    Ronald N. Carroll, with whom James T. McManus, Linda Portasik, Washington, D.C., and Thomas E. Midyett, Jr., Knoxville, Tenn., were on the brief for petitioner. Robert H. Benna, Washington, D.C., also entered an appearance for petitioner.
    Dwight C. Alpem, Atty., F.E.R.C., with whom William S. Scherman, Gen. Counsel, and Joseph S. Davies, Deputy Sol., F.E.R.C., Washington, D.C., were on the brief for respondent.
    Before MIKVA, Chief Judge, and EDWARDS and THOMAS, Circuit Judges.
    
      
       Former Circuit Judge Thomas, now an Associate Justice of the Supreme Court of the United States, was a member of the panel when the case was argued but did not participate in this opinion.
    
   Opinion for the Court filed PER CURIAM.

PER CURIAM:

East Tennessee Natural Gas Company (“East Tennessee”) seeks review of a Federal Energy Regulatory Commission (“FERC” or “Commission”) order denying its proposal to reduce the rate of its Authorized Overrun Sales (AOS) service. East Tennessee also challenges the Commission’s award of refunds to customers putatively injured by the lower AOS rates. Because the Commission acted without any reasonable basis in rejecting East Tennessee’s tariff filing, we vacate the orders under review and remand the case for further proceedings.

I. Background

East Tennessee operates an interstate natural gas pipeline system in Tennessee and Virginia. In 1984, at the time of the contested tariff filing, the system served thirty-five gas distribution companies, thirty-three of whom were full-requirements customers. Two of the companies, Chattanooga Gas Company and Roanoke Gas Company, were partial requirements customers. East Tennessee purchased almost all of its gas from the Tennessee Gas Transmission Corporation (“Tennessee”). Transcript (“Tr.”) at 96, 136, 173 (Testimony of Robert H. Patterson), reprinted in Joint Appendix (“J.A.”) 6, 18, 38.

Most of East Tennessee’s sales services were non-interruptible (“firm”) services, which entitled customers to reserve a specific quantity of gas that they could purchase over a set time period. See East Tennessee Natural Gas Co. v. FERC, 863 F.2d 932, 935 (D.C.Cir.1988). The AOS service at issue here, however, was an inter-ruptible service. On any given day, a firm service customer that had satisfied its daily contract demand could purchase additional gas, when it was available, at the AOS rates. Because of its overrun requirement and fluctuating availability, AOS gas was East Tennessee’s lowest priority service. Testimony of Lawrence G. Williams at 359, 368, reprinted in J.A. 120, 129.

Three components comprised East Tennessee’s sales rate for firm sales: a demand charge, which was a fixed monthly charge that included Tennessee’s demand charges to East Tennessee and fifty percent of East Tennessee’s own fixed costs; a commodity charge, which was a variable charge (per-unit of gas sold) that included East Tennessee’s variable non-gas costs and the other fifty percent of its fixed costs; and the gas charge, which included Tennessee’s commodity and gas charges. Id. at 361-62, reprinted in J.A. 121-22. The AOS rate, in contrast, consisted of a single, volume-based charge known as a “100 percent load factor rate.” This rate equaled the total per-unit charge paid by a firm sales customer that purchased its maximum capacity each day.

East Tennessee adjusted its rates semiannually through its Purchased Gas Adjustment Clause (PGA). Every six months, the PGA provision automatically changed East Tennessee’s gas charges in response to changes in Tennessee’s gas and commodity charges; and East Tennessee’s demand charges in response to changes in East Tennessee’s purchased gas demand costs (Tennessee’s demand charges to East Tennessee). When necessary, the PGA provision also charged customers for East Tennessee’s minimum bill deficiency. This occurred when East Tennessee had not sold enough gas to cover its minimum bill obligation to Tennessee, which it had to pay regardless of how much gas it had actually used. All PGA adjustments were apportioned among all rate schedules, including the AOS schedule. Id. at 362, 365, reprinted in J.A. 123, 126.

In the early 1980s, competition in the marketplace rendered the AOS service relatively unmarketable. Columbia Gas, one of East Tennessee’s major competitors, implemented several discount sales programs that permitted Columbia to market gas at prices considerably below the AOS rates. Testimony of Robert H. Patterson at 339, reprinted in J.A. 101; see also CD-I and AOS Rates, reprinted in J.A. 132. Responding to Columbia’s lower prices, Roanoke, which previously had been the largest subscriber to the AOS service, virtually stopped purchasing AOS gas and dropped some of its baseload service with East Tennessee. See Monthly Deliveries to Roanoke Gas Co., reprinted in J.A. 113. At the same time, competition from Southern Natural Gas Company caused East Tennessee’s other partial requirements customer, Chattanooga, to forgo purchases of AOS gas in 1982, 1983 and 1984. Tr. at 170 (Testimony of Robert H. Patterson), reprinted in J.A. 35. Since full-requirements customers generally purchased AOS gas only on cold days or for emergency purposes, East Tennessee lost approximately one third of its AOS business to Columbia and Southern. Coinciding with this decline in AOS sales was a similarly dramatic increase in East Tennessee’s minimum bill exposure. Testimony of Robert H. Patterson at 344-45, reprinted in J.A. 106-07; Testimony of Joseph A. Gregorini at 492, reprinted in J.A. 193.

On December 11, 1984, in an effort to regain some of its lost business, East Tennessee filed a tariff change to eliminate the 100 percent load factor method of calculating AOS rates and to replace it with a rate equaling only the sum of the commodity and gas charges. See East Tennessee Natural Gas Co. Tariff Filing, reprinted in J.A. 200-11. The proposed rate design thus excluded both East Tennessee’s demand costs and the purchased gas demand costs that East Tennessee paid to Tennessee. Since East Tennessee could not reallocate its own fixed costs absent a general rate-making proceeding, it agreed to absorb its demand costs in the interim. Testimony of Lawrence G. Williams at 367, reprinted in J.A. 128. East Tennessee’s purchased gas demand costs, on the other hand, were Tennessee’s fixed costs, which were incorporated into the gas price that Tennessee charged East Tennessee. The PGA mechanism tracked these costs so that East Tennessee recovered neither more nor less than it had actually paid; any purchased gas demand costs not collected from AOS customers were automatically included in the PGA rates assessed other customers. Testimony of Joseph A. Gregorini at 486, 488, reprinted in J.A. 187, 189. Under the proposal, therefore, non-AOS customers would automatically bear the purchased gas demand costs previously borne by AOS customers. Despite this cost reallocation, none of East Tennessee’s customers opposed the proposal.

The proposed rate was implemented effective June 11, 1985, subject to refund. East Tennessee Natural Gas Co., 30 F.E.R.C. ¶ 161,008, at 61,013, reh’g denied, 30 F.E.R.C. ¶ 61,304, at 61,607 (1985). Columbia protested and was permitted to intervene in the proceedings before the Commission. Id. Pursuant to Commission orders, the case was scheduled for hearing before an administrative law judge (“ALJ”).

Following a full hearing on the issue, the ALJ concluded that the proposed rate change was just and reasonable. See East Tennessee Natural Gas Co. (“ALJ Opinion”), 34 F.E.R.C. ¶ 63,089, at 65,319 (1986). The ALJ explained that demand charges were properly excluded from AOS prices because such charges were incurred to reserve pipeline capacity for firm-service customers. Because AOS service was available only on a day-to-day basis to the extent the pipeline had excess capacity, it should not reflect a charge based upon a right to demand capacity. Id. at 65,312-13. The ALJ found that, in any event, the rate was necessary to meet competition in the marketplace. Id. at 65,315-16. The ALJ also discredited the Commission staff’s “flawed” prediction that the rate would result in a cost shift of $255,400. Id. at 65,317. The more accurate figure, according to the ALJ, was $85,109, an amount found to be de minimis. Id. Finally, the AU concluded that the lower rates would spur more purchases, resulting in minimum bill savings and the recovery of more fixed costs through the AOS rate’s commodity charge. Id. at 65,317-18.

On April 5, 1989, the Commission reversed the AU’s decision, finding that there was no basis for any departure from the 100 percent load factor rate. See East Tennessee Natural Gas Co. (“Order ”), 47 F.E.R.C. ¶ 61,011, at 61,029-33 (1989). The Commission further concluded that since the proposed change resulted in non-AOS customers paying purchased demand costs that AOS customers had previously borne, and since there was no concrete proof that the reduced AOS rate would increase gas sales, East Tennessee had failed to demonstrate that its proposal would not result in a discriminatory cost shift to non-AOS customers. Id. at 61,033. The Commission thus ordered East Tennessee to reinstate the 100 percent load factor rate on a prospective basis and to give refunds to those customers that had paid purchased demand costs that otherwise would have been allocated to the AOS rate.

On June 23, 1989, the Commission granted East Tennessee’s request for clarification and granted in part and denied in part East Tennessee’s request for rehearing. See East Tennessee Natural Gas Co. (“Order on Rehearing ”), 47 F.E.R.C. ¶ 61,447, at 62,388 (1989). The Commission admitted “that the appropriateness of a 100 percent load factor rate [was] open to review,” but explained that East Tennessee had failed to demonstrate that “there would be a net public gain from the modified AOS rates.” Id. at 62,391. “One of the principal] reasons for [its] conclusion,” the Commission noted, “was the lack of any persuasive evidence that the reduced AOS rate was likely to generate the new business and increased volumes that East Tennessee claimed.” Id. On the other hand, the Commission pointed out, “[discriminatory] cost shifting would occur among AOS and non-AOS customers ... because the upstream demand costs charged [to] East Tennessee and removed from the AOS rates would be recovered from non-AOS customers under the operation of [the] PGA mechanism.” Id. at 62,390. The Commission did, however, grant East Tennessee’s request to deduct from its refund obligations any monetary benefits that the affected customers had received from the lower AOS rates. Id. at 63,389.

II. Discussion

We review the Commission’s decision to determine whether it is supported by substantial evidence and whether it is “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.” See Maryland People’s Counsel v. FERC, 761 F.2d 768, 774 (D.C.Cir.1985) (Maryland People’s Counsel I). Though deferential, our review is not perfunctory; we will affirm the Commission only if we are satisfied that it has “examine[d] the relevant data,” Motor Vehicle Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43, 103 S.Ct. 2856, 2866, 77 L.Ed.2d 443 (1983), found facts supported by substantial evidence, see 15 U.S.C. § 717r(b), and “articulate[d] a satisfactory explanation for its action including a ‘rational connection between the facts found and the choice made,’ ” State Farm, 463 U.S. at 43, 103 S.Ct. at 2866 (citation omitted).

In its Order and Order on Rehearing, the Commission disagreed with the theory underlying and competitive justification for the lower AOS rate. The Commission ultimately rejected East Tennessee’s proposal on narrower grounds, however. Although “the appropriateness of a 100 percent load factor rate is open to review,” the Commission explained, departure from that rate was inappropriate here, because “East Tennessee simply [had] not established] that the discriminatory cost shift, which was the central concern of the Commission’s [Order ], would be offset by ... additional revenue gains.” Order on Rehearing, 47 F.E.R.C. at 62,391. On the record before us, we can find no reasoned basis to support the “central concern” underlying the Commission’s decision; therefore, we hold that FERC’s decision, lacking any “rational connection between the facts found and the choice made,” must be rejected as arbitrary and capricious.

The Commission argues that East Tennessee did not sustain its burden because the proposed AOS rate is a discriminatory discount that targets only East Tennessee’s partial requirements customers (Roanoke and Chattanooga). Full-requirements customers would not benefit from the proposal, according to the Commission, because they rarely buy enough gas to become eligible for the AOS service. The Commission asserts that this court’s decision in Maryland People’s Counsel I forbids such selective discounting. 761 F.2d at 776.

Maryland People’s Counsel I and its companion case, Maryland People’s Counsel v. FERC, 761 F.2d 780 (D.C.Cir.1985) (Maryland People’s Counsel II), are inap-posite here. In Maryland People’s Counsel I, the Commission had approved a Special Marketing Program (“SMP”) that expressly excluded captive customers from the list of customers eligible to purchase the program’s cheaper gas. We held that the Commission had not justified its exclusion of that customer class. Id. at 779. In Maryland People’s Counsel II, we reviewed the Commission’s approval of blanket certificate orders authorizing pipelines to transport natural gas that producers sold directly to end users. Though the orders were facially neutral, we observed that they were not “condition[ed] ... on the nondiscriminatory provision of service to captive and noncaptive consumers alike.” 761 F.2d at 785. Accordingly, “pipelines [could] transport producers’ reasonably priced gas to fuel-switchable end users, thus dissuading those users from leaving the gas market, while refusing to provide the same service to — and instead continuing to collect monopoly rents from — captive customers.” Id. We therefore held that the Commission did not adequately explain its refusal to prevent these potential consequences by conditioning the orders on nondiscriminatory service. Id. at 788-89.

Here, by contrast, the Commission has expressly recognized that “[b]oth before and after the filing of the instant case, AOS service was an interruptible service available to all East Tennessee’s customers [that] have contracted with East Tennessee for firm sales service.” Order, 47 F.E.R.C. at 61,028. Unlike a special discounting program which is offered selectively, the proposed reduction in the AOS rate by definition applies to all customers, whether full requirement or partial requirement purchasers. Thus, the proposed AOS rate has none of the discriminatory attributes that this court disapproved in Maryland People’s Counsel I and II.

The Commission argues nonetheless that the practical effect of East Tennessee’s proposal would be discriminatory because full-requirements customers cannot take advantage of the AOS service. Since full-requirements customers cannot pick and choose among gas suppliers, the Commission contends, they must reserve more gas in their firm service contracts than they can use on any particular day. But the Commission’s theory does not explain why one-third of East Tennessee’s full-requirements customers did make use of the AOS service in 1984. See Testimony of Robert H. Patterson at 385, reprinted in J.A. 146; see also Order, 47 F.E.R.C. at 61,031 (recognizing that “East Tennessee was able to make considerable AOS sales” in 1984, despite having lost most of the Roanoke business). Nor does it explain how the full-requirements customers that have taken advantage of the AOS service are situated any differently from those who have not. In Tennessee Gas Pipeline Co. v. FERC, 860 F.2d 446, 458 (D.C.Cir.1988), we rejected the Commission’s unsupported assumptions about the marketplace options of full-requirements customers:

The Commission cites no examples of GS customers that have been precluded from switching to the partial requirements schedule; nor does it adequately explain the basis for its prediction that size and load factor will preclude switching. The Commission devotes greater attention to the fact that Tennessee’s customers are captive customers, apparently to emphasize that if unable to switch to partial requirements, GS customers are precluded from transporting entirely for they cannot abandon Tennessee as their supplier. This fact on its own, however, obviously cannot be used to prove that the partial requirements rate is effectively unavailable to GS customers.

Here too, we find inadequate the Commission’s bare assertion that AOS gas is effectively unavailable to full-requirements customers.

The Commission further argues that even if the proposed AOS rate is not discriminatory per se, East Tennessee has failed to prove that the rate would not result in an unacceptable cost shift from AOS customers to non-AOS customers. The Commission points out that under East Tennessee’s old PGA provision, rates were apportioned among all of East Tennessee’s rate schedules, including the AOS schedule. Under the proposed PGA provision, on the other hand, purchased demand costs that were previously included in the AOS rate would be reapportioned among the other rates.

Before the AU, the Commission’s staff had estimated that the cost shift would amount to $255,400. The ALJ rejected that estimate because it was based on “the 1984 actual AOS sales of 400,000 Mcf [metric cubic feet] to full requirements customers, plus the 1983 actual AOS sales to Roanoke of 800,000 Mcf.” ALJ Opinion, 34 F.E.R.C. at 65,317. The ALJ explained that the staff should not have included the 800,000 Mcf in its calculation because that figure reflected Roanoke’s purchases from East Tennessee before East Tennessee lost the Roanoke business to Columbia in 1984. Id. Excluding that figure left a projected shift of $85,109, “a mere 0.3 percent of East Tennessee’s total purchased gas demand costs.” Id. In the AU’s view, this figure was de minimis, especially since it was based on AOS sales to full-requirements customers in 1984, “a year when such sales were atypically high and not representative of reasonably anticipated future sales levels.” Id.

Without explanation, the Commission dismissed the AU’s projected cost shift of $85,109 as an “unsupported forecast,” and failed even to consider whether such a shift would be de minimis. See Order on Rehearing, 47 F.E.R.C. at 62,391. Nor did it address the AU’s prediction that the level of AOS sales in 1984 would not recur. The Commission might have disagreed with the AU’s prediction that Roanoke would no longer buy AOS gas at the 100 percent load factor rate. Or the Commission might have viewed $85,109 as more than a de minimis amount. Judicial conjecture, however, is an inadequate substitute for agency exposition. Because the ALJ relied on substantial evidence in the record, coupled with a well-reasoned and highly sensible analysis, in reaching a conclusion on the cost-shifting issue, we can find no basis upon which to accept the Commission’s unsupported and ill-reasoned conclusion to the contrary. See Panhandle Eastern Pipe Line Co. v. FERC, 881 F.2d 1101, 1116 (D.C.Cir.1989) (“An agency’s ‘departure from the AU’s findings is vulnerable if it fails to reflect attentive consideration to the AU’s decision.’ ”) (citation omitted).

Given our disposition here, we need not decide whether East Tennessee proved that the lower AOS rate would increase gas sales (and thereby further minimize the cost shift). We note, however, that the Commission generally has encouraged rate proposals designed to enhance gas marketability, without requiring conclusive proof that more gas sales would ensue. Consistent with that practice, the Commission here insisted that it was requiring only “sufficient evidence,” not a “guarantee,” that “increased sales would occur.” Order on Rehearing, 47 F.E.R.C. at 62,391 n. 22. But the Commission rejected as “insufficient” ample record proof that Columbia’s discount program caused East Tennessee to lose a large part of its AOS market, see Testimony of Robert H. Patterson at 336-45, reprinted in J.A. 98-107; Actual Monthly Deliveries to Roanoke Gas Co., reprinted in J.A. 113; Testimony of Frank A. Farmer, Jr. at 469-70, reprinted in J.A. 170-71, that East Tennessee would not regain that market without lowering its AOS rate, see Tr. at 156-158 (Testimony of Robert H. Patterson), reprinted in J.A. 32-34; Tr. at 245, 257 (Testimony of Joseph A. Gregorini), reprinted in J.A. 65, 73; Testimony of Robert H. Patterson at 347-49, reprinted, in J.A. 109-11; Testimony of Robert H. Patterson at 381, reprinted in J.A. 142, and that a reduced AOS rate would increase future AOS sales volumes, see Tr. at 144-146 (Testimony of Robert H. Patterson), reprinted in J.A. 26-28; Tr. at 257 (Testimony of Joseph A. Gregorini), reprinted in J.A. 73. Given this record evidence, we find it impossible to reconcile the Commission’s asserted policies with its actions in this case; accordingly, we must vacate the Commission’s order.

III. Conclusion

The Commission acted without reasonable basis in rejecting East Tennessee’s proposal to reduce the rate of its AOS service. Accordingly, the petitions for review are granted, the Commission’s orders are vacated and this case is remanded for further proceedings consistent with this opinion.

So ordered. 
      
      .This rate design is known as the Seaboard formula. See Atlantic Seaboard Corp., 11 F.P.C. 43 (1952). On December 1, 1985, East Tennessee changed to a modified fixed-variable (MFV) rate design to enhance the competitiveness of its gas. Under the MFV design, all of East Tennessee’s fixed costs, except return on equity and related income taxes, were included in the demand charge. See East Tennessee Natural Gas Co., 40 F.E.R.C. ¶ 61,201, at 61,675, 61,683, reh’g denied, 41 F.E.R.C. ¶ 61,271 (1987), aff’d in part, 863 F.2d 932 (D.C.Cir.1988).
     
      
      . Because the demand charge component of firm rates is a fixed amount, the per-unit charge paid by a firm customer decreases as its purchase approaches 100 percent of the amount available to it under the sales contract. Testimony of Lawrence G. Williams at 360, reprinted in J.A. 121.
     
      
      . The agreement between Tennessee and East Tennessee stipulated that East Tennessee had to purchase at least 662/3 of the monthly component of its annual volumetric limitation, or be subject to a minimum charge.
     
      
      . East Tennessee’s demand costs were the fixed costs associated with its own system and were collected through rates established in general Natural Gas Act (NGA) section 4 proceedings. 15 U.S.C. § 717c (1988).
     
      
      . The parties dispute whether East Tennessee properly bore its burden of proof in this proceeding. Whatever the merits of that dispute, East Tennessee did not challenge the burden allocation in its request for rehearing before the Commission; thus, it is foreclosed from doing so on appeal. See, e.g., ASARCO, Inc. v. FERC, 777 F.2d 764, 775 (D.C.Cir.1985). We therefore assume without deciding that East Tennessee had the burden of justifying the lower AOS rate.
     
      
      . See, e.g., El Paso Natural Gas Co., 45 F.E.R.C. ¶ 61,248, at 61,729 (1988) (The Commission looks askance at “discount” proposals that charge different rates to different customers.).
     
      
      . See, e.g., Southern Natural Gas Co., 43 F.E.R.C. ¶ 61,035, at 61,099 ("The record amply supports the use of the MFV method of classification as a way to enhance Southern’s opportunity to market additional gas to the industrial sector.”), reh’g granted in part, denied in part, 44 F.E.R.C. ¶ 61,123 (1988); ANR Pipeline Co., 37 F.E.R.C. ¶ 61,263, at 61,738 (1986) (“[A] lowered commodity charge is ... an essential step in achieving our goal of allowing greater flexibility to the pipeline in facilitating the marketing of its gas supplies"), reh’g denied, 38 F.E.R.C. ¶ 61,221 (1987); Texas Eastern Transmission Corp., 30 F.E.R.C. ¶ 61,144, at 61,281 (1985) (“This Commission has the opportunity to adopt a flexible rate design structure to enable Texas Eastern not only to sell gas today but to compete in the changing market structure of the pipeline industry.”), reh’g granted in part, denied in part, 32 F.E.R.C. U61,056 (1985).
     