BARKSDALE, Circuit Judge:

Gulf States Utilities Company (GSU) challenges the Federal Energy Regulatory Commission’s denial of both its request to correct, retroactively and prospectively, claimed billing errors, and its application for a waiver of related filing requirements, arising from its contract with Cajun Electric Power Cooperative, involving GSU’s high-voltage electricity transmission system, owned in part by Cajun. We REVERSE and REMAND.

GSU is a utility company servicing customers in Louisiana and Texas; and, under a Power Interconnection Agreement executed in 1978, it provides electricity transmission services to Cajun, a government-funded rural electric cooperative in Louisiana. Because Cajun’s cost of capital is less than GSU’s, due to Cajun’s government-funded status, GSU and Cajun executed Service Schedule CTOC in 1980 (the CTOC agreement), which provided that the two companies would establish a co-owned Integrated Transmission System (ITS) comprised of qualified high-voltage transmission facilities (QTFs). 1 In exchange for its investment in the ITS, Cajun would not be billed for its use of the ITS to the extent of that investment. In essence, the plan allowed Cajun to invest in the ITS in lieu of paying a portion of the bill that would otherwise be payable to GSU.

The CTOC agreement established a rather complex billing mechanism with regard to the ITS. In order to credit Cajun for its investment, GSU was to deduct GSU’s revenue requirements associated with the ITS from Cajun’s monthly general transmission charges, in the form of “CTOC credits”. The CTOC credits were to be “determined on the basis of the methodology, procedures and data used as the basis for GSU’s transmission service rates most recently approved or accepted for filing by FERC ... ”.

Additionally, in the event that Cajun’s investment in the ITS was not proportionate to its relative use, an equalization charge would be imposed. The equalization charge was to be calculated by multiplying the amount of Cajun’s investment deficiency by a percentage referred to as “Factor APM”. Factor APM is computed by dividing GSU’s annual revenue requirement associated with the ITS by its total investment in the ITS. For example, if GSU invested a total of $100 million in the ITS, and its annual revenue requirements for the ITS were $20 million, Factor APM would be 20% for that year. Accordingly, Cajun’s yearly equalization charge would be 20% of the amount of its *290 investment deficiency. Because the monthly equalization charges were to be based on estimates, the CTOC agreement also provided for annual “true-ups” once the actual figures became available.

In early 1981, GSU submitted the CTOC agreement for FERC approval. In response to FERC’s request for additional information, GSU specified, inter alia, the Factor APM to be used initially. FERC accepted the agreement for filing that August, but advised GSU that “any changes in the applicable Equalizing Charge resulting from the use of a Factor APM different from that specified in your instant filing, must be timely filed ... as a change in rate schedule in accordance with [regulations]”. FERC did not similarly direct GSU to file changes to the CTOC credits, and the CTOC agreement did not specify how such changes were to be initiated or implemented. Accordingly, until GSU’s filing in the present proceeding, CTOC credits (as a component of the stated rate) were never filed with FERC.

The CTOC agreement billing provisions took effect January 1, 1982, when Cajun acquired two high-voltage transmission lines— QTFs — from GSU. At that time, GSU computed Cajun’s CTOC credits from the data filed with FERC in GSU’s most recent general transmission rate filing, submitted in 1980. It used the specified Factor APM (24.4047%), which was also based on that data.

In July 1982, GSU submitted new general transmission rates for filing. FERC approved a settlement in that case in June 1983, with the new rates made effective July 1982. See Gulf States Utils. Co., 25 F.E.R.C. ¶ 61,131 (1983).

GSU again submitted new general transmission rates in July 1985. In January 1987, FERC approved a settlement of that case, which provided for two new rates — one effective July 1985, and a superseding rate effective July 1986. See Gulf States Utils. Co., 38 F.E.R.C. ¶ 61,048 (1987). Cajun intervened in the second (1985) rate case to protest GSU’s designation of the QTFs under the CTOC agreement (QTF dispute), 2 but the 1987 settlement agreement expressly excluded any resolution of that dispute. 3

As noted, in neither its 1982 nor its 1985 filing did GSU separately designate revised CTOC credits or Factors APM. However, upon each filing, it recalculated both, based on the new data submitted, and billed Cajun accordingly. FERC accepted GSU’s refund compliance filings for each case in May 1984 and September 1987, respectively.

In July 1987, Cajun renewed its claims with FERC regarding the QTF dispute, among others. GSU answered, and filed its own action with FERC, proposing to cancel the CTOC agreement. FERC denied GSU’s request to cancel, see Cajun Elec. Power Corp., Inc. v. Gulf States Utils. Co., 41 F.E.R.C. ¶ 61,136 (1987), and affirmed the denial on rehearing, see Gulf States Utils. Co., 42 F.E.R.C. ¶ 61,163 (1988).

Meanwhile, GSU allegedly discovered that it had erred all along in calculating the CTOC credits. In November 1987, after the denial of its request to cancel the CTOC agreement, GSU began billing Cajun using revised (lowered) CTOC credits, resulting in an annual increase in the billings to Cajun of approximately $4 million. Cajun has paid those increased charges. Additionally, as noted, GSU had never filed, as directed, the changes to Factor APM from the figure initially filed in 1981. Accordingly, on June 20, 1988, GSU submitted for filing retroactive and prospective revisions to the CTOC credits and Factors APM, requesting a waiver of the Factor APM filing requirement for good cause.

In August 1988 (Initial Order), FERC rejected GSU’s proposed retroactive changes to *291 the CTOC credits, holding that those credits had been at issue in, and resolved by, the settlements of the 1982 and 1985 rate cases in 1983 and 1987, respectively. See Cajun Elec. Power Corp., Inc. v. Gulf States Utils. Co., 44 F.E.R.C. ¶ 61,259, 61,972 (1988) [hereinafter 44 F.E.R.C. at -]. In addition, it denied GSU’s request for a waiver of the Factor APM filing requirement. Id. at 61,970-71. For prospective application only, FERC accepted GSU’s proposed Factor APM, based on the 1986 rate, and set that matter for hearing. Id. Finally, for purposes of hearing and decision, FERC consolidated GSU’s proceeding with Cajun’s involving the QTFs. Id. at 61,972. With respect to the CTOC credits, both GSU and Cajun requested clarification or, in the alternative, rehearing.

Pending that rehearing, an ALJ held a hearing on the consolidated matters, and issued a decision in May 1989. See Cajun Elec. Power Corp., Inc. v. Gulf States Utils. Co., 47 F.E.R.C. ¶ 63,024 (1989). The ALJ interpreted FERC’s Initial Order to address only pre-July 26, 1985, CTOC credits (the effective date of the settled 1985 rate case). Id. at 65,057. Accordingly, he proceeded to address the post-July 26, 1985, CTOC credit dispute, and held in GSU’s favor on the alleged errors. Id. at 65,057-58. He stated: “[Wjith the understanding that [GSU’s] calculations have been somewhat erroneous in the past, I conclude that the methodology and figures computed by [GSU’s witness] now accurately project the CTOC credits Id.

In April 1992, nearly four years after its Initial Order, FERC again rejected the proposed retroactive CTOC credits and Factors APM, and denied the requested waiver of the Factor APM filing requirement (Rehearing Order). See Cajun Elec. Power Corp., Inc. v. Gulf States Utils. Co., 59 F.E.R.C. ¶ 61,041, 61,137-41, 61,143 (1992) [hereinafter 59 F.E.R.C. at -]. It upheld the ALJ’s determination regarding the Factor APM, based on the 1986 rates, to be applied prospectively (from August 1988), id. at 61,143, but reversed his finding with regard to post-July 1985 CTOC credits, holding that that dispute was not properly before the ALJ in light of FERC’s Initial Order, id. at 61,138.

Reiterating that the CTOC credits for July 1985 forward had been settled with the 1985 rate case, FERC ordered GSU to refund amounts relating to revised CTOC credits which had been billed since November 1987 using the allegedly correct method (as noted, approximately $4 million annually). Id. at 61,141. Finally, “[t]o reduce future confusion and uncertainty”, FERC directed GSU in each subsequent general transmission rate filing to delineate specifically the CTOC credits. Id. at 61,137. GSU timely filed its petition for review of the rulings on the CTOC credits and Factors APM; the QTF dispute is not before us.

II.

GSU contends that FERC erred in (1) denying GSU a waiver of the Factor APM filing requirement; (2) rejecting retroactive (pre-August 21, 1988) changes to the CTOC credits; and (3) rejecting CTOC credits for prospective effect (post-August 21, 1988). 4

We will reverse a FERC order “only if [its] decision is arbitrary, capricious, or otherwise not in accordance with law”. Monsanto Co. v. FERC, 963 F.2d 827, 830 (5th Cir.1992) (internal quotation omitted). This includes a determination of “whether each of the order’s essential elements is supported by substantial evidence”, and whether FERC “abused or exceeded its authority”. In re Permian Basin Area Rate Cases, 390 U.S. 747, 790, 792, 88 S.Ct. 1344, 1372, 1373, 20 L.Ed.2d 312 (1968); see also 5 U.S.C. § 706(2) (governing scope of judicial review of agency decisions). “The ‘ultimate issue in judicial review of [FERC’s] determinations’ is the requirement of ‘reasoned consideration’ ”. See Borden, Inc. v. FERC, 855 F.2d 254, 258-59 (5th Cir.1988). Furthermore, “[n]o objection to the order of the Commission shall be considered by the court unless such objection shall have been urged before *292 the Commission in the application for rehearing unless there is reasonable ground for failure so to do”. 16 U.S.C. § 825l(b); see United Gas Pipe Line Co. v. FERC, 824 F.2d 417, 433-34 (5th Cir.1987).

For use with the rates that became effective in 1982, 1985, and 1986, GSU requested approval of Factors APM different from that approved in 1981. Prior to 1988, as a result of using Factors APM different from that approved in 1981, GSU collected approximately $3.8 million more than it would have using the approved factor. It has been ordered to refund that amount to Cajun. GSU contends that “[without any explanation, [FERC] ignored [GSU’s] showing of good cause” for the waiver of the requirement that Factor APM changes be filed as rate changes. Section 205(d) of the Federal Power Act (FPA), 16 U.S.C. § 824d(d) provides:

Unless the Commission otherwise orders, no change shall be made by any public utility in any [rates subject to FERC’s jurisdiction] except after sixty days’ notice to the Commission.... The Commission, for good cause shown, may allow changes to take effect without requiring the sixty days’ notice....

Because the waiver provisions are committed to FERC’s discretion, GSU must show an abuse of that discretion. Hall v. FERC, 691 F.2d 1184, 1191 (5th Cir.1982), cert. denied, Arkla, Inc. v. Hall, 464 U.S. 822, 104 S.Ct. 88, 78 L.Ed.2d 96 (1983).

In the Initial Order denying the waiver, FERC explained that (1) GSU’s failure to comply with the filing requirements was not excused by the ongoing billing dispute with Cajun, because that dispute involved the QTFs, not Factor APM; (2) contractual provisions that fairly implied “some waiver of the notice requirements” by Cajun did not contemplate GSU’s lengthy delay in filing the changes; and (3) GSU had been directed to file any changes to Factor APM. See 44 F.E.R.C. at 61,970-71. In its Rehearing Order, FERC noted GSU’s contentions that denial of a waiver would produce a windfall to Cajun, contrary to the contractually established rates, and that Cajun, in the CTOC agreement, impliedly waived any notice requirements. See 59 F.E.R.C. at 61,142. FERC summarily concluded, however, that it did “not find good cause to grant [GSU’s] request for waiver”, explaining only that GSU “failed to abide by the notice requirement” of which it had been expressly advised. Id. at 61,143.

GSU disputes FERC’s determination, and contends that FERC wholly failed to address its good cause arguments; particularly, that Cajun had notice of increases and, without protest, paid the bills containing those increases. Additionally, GSU emphasizes that the CTOC agreement provided for the increases and for some waiver of the notice requirements (which, as noted, was acknowledged by FERC), and that FERC already had approved the general transmission rates upon which the Factor APM changes were directly based.

FERC is vested with discretion in deciding whether to grant the requested waiver; to find an abuse of that discretion requires most substantial justification. We find it here. GSU has shown good cause for the waiver, and FERC’s summary discussion of the reasons for its denial does not “set out clearly the ground that forms the basis for the denial of discretionary relief’, Columbia Gas Dev. Corp. v. FERC, 651 F.2d 1146, 1160 n. 18 (5th Cir.1981), such that we can determine whether it gave reasoned consideration to GSU’s assertions of good cause.

A principal purpose of the filing provisions of the FPA is “to give advance notice of proposed rate changes” to the customer. Union Texas Prods. Corp. v. FERC, 899 F.2d 432, 433 (5th Cir.1990) (reversing the denial of a waiver where, inter alia, the needed information appeared elsewhere in the general transmission rate filings). It does not appear that FERC gave consideration to whether that purpose was satisfied here. Not only did Cajun have actual notice of increases in Factor APM, but there appears to be no dispute that the proposed changes are provided for by the CTOC agreement. Therefore, the emphasis by FERC on GSU’s delay of several years in *293 filing for a different factor is greatly ameliorated. In short, the filing could not have come as a surprise to Cajun.

In the final analysis, FERC’s principal reason for denying the waiver appears to be the fact that GSU failed to make the required filings. But, needless to say, if this were the criteria for denying a filing waiver, waiver would never be granted. Additionally, GSU’s failure to follow FERC’s express instructions to file Factor APM changes does not justify the $3.8 million penalty which FERC, in effect, seeks to impose for the error. In Union Texas, our court stated that “the Commission’s punctilious insistence that the failure to follow its directions in the minor respect here involved should result in such a disproportionately heavy penalty [$1.8 million] works a manifest injustice and constitutes an abuse of discretion”. 899 F.2d at 437. Although, arguably, the error involved in Union Texas was more minor than GSU’s, the forfeiture still is not justified.

Accordingly, we reverse the denial of the waiver. Because FERC has not passed on the correct Factor APM to be used in relation to the 1982 and 1985 rates, we remand for such further proceedings as it deems appropriate in this regard.

GSU claims that it discovered that past bills had overstated the CTOC credits. As noted, in November 1987, GSU began billing Cajun using revised (lower) CTOC credits, resulting in Cajun being charged annually approximately $4 million more; and Cajun has paid those increased billings to date. In June 1988, GSU filed the corrected credits in this proceeding. At issue are both the pre-August 21, 1988, billings (retroactive) and those billings subsequent to then (prospective).

With respect to GSU’s proposed retroactive changes to the CTOC credits, we also reverse. The dispute appears to involve highly technical questions regarding • the method of calculating CTOC credits; the parties do not explain the details in their briefs. In its Rehearing Order, FERC characterized the dispute as reflecting “substantive questions with respect to the operation of Service Schedule CTOC”, rather than simple “billing errors”. 59 F.E.R.C. at 61,137. With the exception of the ALJ’s hearing in late 1988, GSU has not been heard on the merits of these questions.

As noted, FERC’s rejection of the proposed changes rests solely on its determination that the CTOC credits were settled with the respective general transmission rate cases. Initially, FERC determined that the express exclusion of the “existing billing dispute” in the 1987 settlement did not refer to the present dispute. Id. at 61,138. It then reasoned (1) that Cajun may have reasonably expected the methodology for calculating CTOC credits to remain the same in the 1985 filing as in the 1982 filing; (2) that Cajun may have reasonably anticipated the approximate revenue impact of the settlements, including the CTOC credits; (3) that the magnitude of the proposed revisions would “completely undo[] the balancing of interests” that underlay FERC’s approval of the settlements as fair and reasonable and in the public’s interest; and (4) that particular CTOC credits were included in the general transmission rate filings as components of the “CTOC Adjustment” in the cost of service used to determine GSU’s basic rates to all of its transmission customers. Id. at 61,-140-41 & n. 74.

GSU contends that the express exclusion in the 1987 settlement, see supra note 3, did reference the present dispute. It further contends that the record is devoid of evidence that the settlements included any mention of particular CTOC credits or that they were based on any assumptions about the CTOC credits. Finally, GSU asserts that the filed rate doctrine mandates correction of the alleged errors. 5

As an initial matter, we find substantial evidence to support FERC’s conclusion that *294 the present dispute was not expressly excluded by the 1987 settlement. In making its determination, FERC closely examined the relevant evidence, including Cajun’s protest to GSU’s refund compliance report in the 1985 rate case, FERC’s letter order rejecting the initial refund compliance report, Cajun’s complaint in the QTF dispute, and GSU’s answer in that dispute. We need not restate FERC’s reasoning with respect to each; it thoroughly considered and discussed the evidence, and we find its conclusions reasonable. Perhaps most persuasive is the fact that GSU’s claimed errors were assert-edly not even discovered until after execution of the settlement in 1986, approved by FERC in January 1987. (As noted, GSU did not begin billing with the revised CTOC credits until November 1987.)

That the present dispute was not expressly excluded by the 1987 settlement, however, does not resolve whether the CTOC credits were settled (fixed) by either the 1983 or 1987 settlements. In its Rehearing Order, FERC acknowledged that “[GSU] has never been required by the terms of Service Schedule CTOC or by the Commission to explicitly file the CTOC credits”, 59 F.E.R.C. at 61,-136, and that “until the filing in this proceeding CTOC credits have never been explicitly filed with the Commission as a numerical component of the stated rate”, id. at 61,135. It would seem unlikely, therefore, that either settlement would include reference, either express or implied, to the CTOC credits in issue.

FERC’s first three reasons for holding that the CTOC credits were included in the settlements constitute mere speculation. First, FERC’s conclusion that “it is not unreasonable to conclude” that the CTOC credits would be calculated under the 1985 rates using the same method that was used to caleulate them under the 1982 rates, 59 F.E.R.C. at 61,140, does not address whether Cajun actually made or relied upon any such conclusion during the settlement negotiations. . Moreover, this logic merely bootstraps onto an assumption that changes based on the 1982 rates should be rejected. Second, FERC’s determination that “it is reasonable to assume” that Cajun, in entering into the settlements, “anticipated the approximate revenue impact, after netting of the CTOC credits”, id., similarly constitutes speculation in the absence of evidence that any such anticipation occurred or was relied upon. Finally, the bare statement that the magnitude of the proposed changes renders them inconsistent with FERC’s acceptance of the settlements, id. at 61,141, is unsupported by any evidence that assumptions regarding the amount of the CTOC credits somehow underlay the settlements, and is most questionable in light of FERC’s own explanation that CTOC credits can be determined only after the general transmission rates are fixed (settled). 6 We find no evidence, and FERC points to none, that any of these assumptions were actually made or relied upon.

The only concrete basis for FERC’s determination that the CTOC credits were settled with the rate cases is its conclusion that they were included in the settled rates as components of the CTOC Adjustment, which comprises part of GSU’s general transmission rates. In its Initial Order, FERC noted that although GSU was not required to file the CTOC credits, the data it submitted in support of its proposed general transmission rates incorporated “a Cajun rate reflecting only low voltage facilities” (i.e., the general transmission rate less the CTOC credits). 44 F.E.R.C. at 61,972. In its Rehearing Order, FERC explained that “[pjarticular CTOC credits were incorporated within the cost of *295 service associated with the proposed [general transmission] rates”, in that “the CTOC credits are a component of a ‘CTOC Adjustment’ in the cost of service used to determine [GSU’s] basic rates to all of its transmission customers”. 59 F.E.R.C. at 61,140 & n. 74 (emphasis added).

GSU asserts that only the formula for determining the CTOC Adjustment is stated. FERC explained that the CTOC Adjustment is “the difference between Cajun’s CTOC credits and Cajun’s equalization payments”— in other words, the net credit given Cajun for its ITS investment. Id. at 61,140 n. 74. GSU asserts that application of this formula in turn necessarily requires calculation of actual CTOC credits (which, as noted, can be determined only after the general transmission rates are fixed) and actual equalization charges (which, as noted, are determined only after each year-end true-up). Thus, GSU argues, the CTOC Adjustment is by definition an estimate, in that both the CTOC credits and the equalization charges are determined through formula rates.

FERC does not respond to this contention, nor does it cite any record support in its brief. The Rehearing Order cited only the testimony of GSU witness James E. Striedel, see 59 F.E.R.C. at 61,140 n. 74, which establishes only the formula described above. At the December 1988 hearing before the ALJ, Striedel was asked, “How are the CTOC credits reflected in ... the cost of service of GSU’s ... customers?” He explained the formula and replied, “That net credit or what is called the CTOC adjustment is allocated as a part of the cost of service to all customers

In his prepared testimony submitted to FERC, Striedel again was asked: “How does [GSU] reflect the CTOC credits and equalization charge payments in determining the rates to its other customers?” He replied: “The net credit received by Cajun is a transmission service cost and is included in [GSU’s] cost of service studies and allocated to all jurisdictions which utilize the integrated transmission system. This net credit given to Cajun is called the CTOC Adjustment in [GSU’s] cost of service.” He also explained that, in addition to removing GSU’s revenue requirements for the ITS, the CTOC credits “should further act to remove the CTOC Adjustment” from Cajun’s bills. As GSU points out, the testimony makes no reference to what was actually filed with FERC or included in the settlement agreements. Furthermore, no specific CTOC credits nor any methodology for determining them is mentioned.

FERC failed to support with substantial evidence its determination that the CTOC credits in issue were included in any way in the respective settlements. Accordingly, we reverse. On remand, GSU must be accorded a determination on the merits of the “substantive questions with respect to Service Schedule CTOC” presented by its allegations that the CTOC credits were calculated erroneously prior to November 1987. The result of that determination should then be applied retroactively to January 1, 1982, when the CTOC agreement first took effect.

Our reasons for reversal with respect to retroactive changes to the CTOC credits apply with equal force to prospective (post-August 21, 1988) changes, but additional factors weigh heavily in favor of GSU on this issue. Foremost is FERC’s nearly four-year delay in resolving this dispute, which would have cost GSU approximately $16 million. 7 Although FERC’s instruction to GSU to file CTOC credit changes with its general transmission rate filings will avoid future disputes, that instruction was not in place in 1988. Moreover, the errors GSU seeks to correct allegedly are independent of the “methodology, procedures and data” used as the basis for the rates on file, such that a new general transmission rate filing would be unnecessary to correct them.

Previously, GSU had not been obligated to file CTOC credits either under the CTOC agreement or by FERC. Substantial dis *296 agreement was ongoing with respect to related aspects of the agreement; specifically, the QTF dispute. Finally, the ALJ had handed down a favorable ruling on the merits of the billing dispute in 1989. Under these circumstances, GSU had no reason to anticipate that a new filing of its general transmission rates would be required in order to resolve the present dispute. For these reasons, we reverse FERC’s refusal to consider the changes prospectively.

III.

In sum, we hold that FERC reversibly erred in denying GSU a waiver of the filing requirement with respect to the pre-1988 Factor APM changes, and in refusing to consider GSU’s requested changes, both retroactive and prospective, to the CTOC credits. The correctness of the proposed CTOC credit changes under the contract and of the proposed Factors APM in relation to the 1982 and 1985 filed rates are issues to be resolved on remand.

For the foregoing reasons, FERC’s orders are REVERSED, and the case is REMANDED for further proceedings consistent with this opinion.

REVERSED and REMANDED.

Notes

. If GSU provides service to Cajun over its entire system, part is provided over the ITS (owned in part by Cajun), and the rest is provided over GSU’s low-voltage facilities.

. In sum, Cajun contended the GSU was not including QTFs owned by Cajun, resulting in improper (excessive) equalization charges to Cajun, and denying it proper access to the ITS.

. Because of the QTF dispute, Cajun had stopped paying the true-ups, and GSU had stopped billing Cajun under the CTOC rate procedures. The settlement agreement provided: "This agreement is not intended to resolve an existing billing dispute between Cajun and [GSU] under the CTOC service schedule.... [T]his Agreement is made without prejudice to Cajun's and [GSU's] rights regarding such dispute and its ultimate resolution”.

. Retroactive changes would apply to CTOC credits for the period from initiation of the CTOC agreement until August 21, 1988 — 60 days after GSU's filing of these proceedings, see FPA § 205(d), 16 U.S.C. § 824d(d), and imposition of a one day suspension, see 44 F.E.R.C. at 61,971.

. FERC contends that because GSU failed to specify the filed rate doctrine as a basis for its position on rehearing, it is jurisdictionally barred from raising it here. We need not address this contention, because we do not rely on that doctrine as a basis for our holding.

. In its Rehearing Order, FERC explained the CTOC credit calculation process as follows:

[E]ach time a change in the basic transmission rate is accepted or approved, under Service Schedule CTOC an associated CTOC credit should be derived based upon the cost assumptions used to develop the basic transmission rate. If [GSU’s] proposed basic transmission rate is contested and subsequently modified (for example, pursuant to a settlement agree ment), under Service Schedule CTOC the CTOC credit should likewise be modified. Although ... CTOC credits are a stated amount on each month’s transmission bill sent to Cajun, until the filing in this proceeding CTOC credits have never been explicitly filed with the Commission as a numerical component of the stated rate.

59 F.E.R.C. at 61,135 (emphasis added). Thus, no CTOC credit can be determined until after the general transmission rates are fixed.

. As noted, the amount in controversy with respect to the alleged billing errors for CTOC credits is approximately $4 million annually. As also noted, since November 1987, Cajun has paid the revised CTOC credits.