Opinion for the Court filed by Circuit Judge GRIFFITH.
GRIFFITH, Circuit Judge.In petition for review, customers of a public utility challenge a decision of the Federal Energy Regulatory Commission (“FERC” or the “Commission”) that approved new charges for electricity service. Petitioners argue that the Commission’s decision to approve the charges was arbitrary and capricious because the services for which the charges were assessed are already covered in existing contracts that shield them from new charges unless they are for “new services.” Petitioners further argue that the Commission did not engage in reasoned decisionmaking because its conclusion is inconsistent with previous determinations it has made with regard to the same charges. FERC responds that the services for which new charges are assessed are “new services,” and distinguishes its conclusions in previous proceedings by arguing that the utility owners (intervenors in support of FERC) had failed to demonstrate that the services were not already covered by existing rates.
Under our particularly deferential standard of review for the Commission’s decisionmaking, we conclude that FERC considered substantial evidence that the proposed tariff was assessed to collect charges associated with new services and that its decision to approve that tariff was rational. We also find that FERC’s conclusion was not inconsistent with its prior determinations because, as the Commission has explained, new evidence was before it. We therefore deny the petition.
I.
In 1996, FERC introduced electric utility companies operating under its authority to a brave new regulatory world with its vanguard Order No. 888, whose aspiration*466al title made up in optimism what it lacked in literary flair. See Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities, FERC Stats. & Regs. ¶ 31,036, 61 Fed.Reg. 21,540 (1996) (“Order No. 888”). Promulgated in response to the anti-competitive effects of vertical integration and, in particular, the unlawful practice of some electric utilities to provide third-party wholesalers of electric power inferior access or no access at all to their transmission networks, see Order No. 888 at 31,682-84, this remedial order required the “functional unbundling” of wholesale generation and transmission services. Id. at 31,654. If vertical integration (the predecessor to functional unbundling) offered a prix fixe menu of utility services, functional unbundling required the a la carte alternative: Under the new system, previously integrated utilities were now required to maintain a wholesale marketing function separate from them transmission functions. Both would deal with one another at arm’s length. Utilities were required to state separate rates for their generation, transmission, and ancillary services and, when providing any of those services for themselves (or their affiliates), do so under the same terms and with the same priority as those available to other market participants. The purpose was to prevent a utility from gaining special access to service or special price deals by virtue of its integration of functions.
In addition to the unbundling requirements that it imposed, Order No. 888 encouraged, but did not demand, the formation of Regional Transmission Organizations (“RTOs”): multi-utility entities that could manage all transmission services for a particular region. By consolidating control (but not ownership) of the now unbundled transmission services, FERC hoped to preserve the efficiencies produced by vertical integration while forestalling its anti-competitive effects. Wholesale competition would be encouraged over broad geographic areas, Order No. 888 at 31,730-32, see also Public Util. Dist. No. 1 of Snohomish County v. FERC, 272 F.3d 607, 610-11 (D.C.Cir.2001), while operational redundancies would be reduced or eliminated. Regional transmission reliability would also be enhanced. See Order No. 888 at 31,730-32.
Familiar with the influence on utilities of the powerful incentives to avoid regulations that limit monopolistic advantages, FERC suggested a further improvement to the novel system it envisioned. The multi-utility RTO would cede operational control of its collectively run transmission facilities to an Independent System Operator (“ISO”), which would have no financial interest in generation services and therefore no incentive to thwart FERC’s goals of efficiency, competition, and improved reliability. See id. at 31,654, 31,730-32 (announcing certain principles to guide further consideration of ISO proposals).
Predictably, not all shared FERC’s vision of how energy markets should function. Most utilities declined the Commission’s invitation to voluntarily embrace a future of robust competition in the wholesale electricity market. And because FERC had required only unbundling, and not the formation of RTOs, utility companies were free to sit out that particular dance. FERC, anxious to see greater participation than had been achieved through mere suggestion, issued another order, directing transmission-owning utilities either to participate in an RTO or to explain their refusal to do so. See Regional Transmission Orgs., Order No. 2000, FERC Stats. & Regs. ¶ 31,089 (1999), 65 Fed.Reg. 810 (2000) (“Order No. 2000”); see also Pub. Util. Dist. No. 1, 272 F.3d at 612. And while participation was still voluntary *467(FERC apparently favored gradual steps in advancing its goals), see id. at 616, electric utilities took the Commission’s cue and began to form RTOs and transfer operational control of their transmission facilities to ISOs.
One such ISO created in the wake of Order Nos. 888 and 2000 was the Midwest ISO (“MISO”), approved by FERC in 1998 to organize as a non-profit, non-stock corporation. See Midwest Indep. Transmission Sys. Operator, Inc., 84 FERC ¶ 61,231, at 62,138-39 (1998). The utilities that organized the MISO retained ownership and the physical operation and maintenance of their own transmission facilities, but the MISO was responsible for functional control over the transmission system, which included managing transmission availability and capacity, requests for transmission service, available ancillary services, and security. FERC conditionally approved a transmission tariff that provided a universal rate for all customers receiving these services from the MISO system. That tariff would be paid immediately by customers of all new wholesale and existing unbundled retail transmission service, id. at 62,167, and even though customers of existing wholesale services would now receive them through the MISO, they were afforded the benefit of their rates under existing agreements (“grandfathered agreements”) and exempted from the MISO transmission tariff for six years. Id. The question before us is whether petitioners, who are customers of these grandfathered agreements and do not yet pay MISO service rates (the transmission tariff), must nonetheless pay the administrative costs associated with managing the MISO (an administrative tariff), from which they receive their transmission service.
This is not our first review of a dispute involving MISO tariffs and parties to agreements grandfathered into the MISO system. In Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361 (D.C.Cir.2004), we were asked to determine whether FERC may require the transmission owners to pay the MISO’s administrative costs (the same costs at the center of the petition now before us) for service provided to customers of grandfathered agreements. Id. at 1367. The transmission owners argued that FERC violated the principle of “cost causation,” which we had described as “requir[ing] that all approved rates reflect to some degree the costs actually caused by the customer who must pay them.” Id. at 1368 (quoting KN Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C.Cir.1992)). The transmission owners argued that the costs imposed upon them for MISO service offered to customers of grandfathered agreements outweighed the benefits to those customers who, while receiving service under the MISO system, did not pay the MISO’s universal transmission rate for the six-year transition period and therefore, according to the transmission owners’ argument, did not “use” the ISO. See id. at 1369. Noting that the administrative charges in dispute covered “the costs of having an ISO,” and that “the [Transmission] Owners ... benefit from having an ISO,” id. at 1371, this Court concluded that “FERC correctly determined that they should share the cost of having an ISO,” id., even for bundled and grandfathered loads that deliver the same benefits afforded customers who are actually using an ISO (i.e., receiving electric service under a universal transmission rate), see id. The transmission owners were thus responsible for paying the administrative costs (now in dispute before us) on behalf of all of their customers, including those customers who do not use (ie., do not pay the universal transmission rate for service under) the ISO.
*468Faced with this Court’s decision, and having thus exhausted their attempts to avoid paying the disputed charges altogether, the transmission owners proposed to pass the bill on to their customers by assessing additional charges (under “Schedule 23”) to collect the MISO administrative costs they now owed on grandfathered loads. FERC’s order conditionally accepting the owners’ proposal to collect those costs from customers is the subject of the petition for review currently before us.
The transmission owners’ attempt to pass the MISO’s administrative costs to customers of grandfathered agreements is not their first. They had previously proposed the imposition of two sets of administrative charges: Schedule 10 charges, which recover the costs of running the MISO itself, and Schedule 17 charges, which recover the costs of developing and running the MISO’s energy markets. But this prior attempt failed when FERC ruled that the transmission owners had not demonstrated that the existing rates paid by customers taking service under the grandfathered agreements did not already include Schedule 10 charges, see Midwest Indep. Transmission Sys. Operator, Inc., 102 FERC ¶ 61,192, at 61,533-34 (2003); Midwest Indep. Transmission Sys. Operator, 104 FERC ¶ 61,012, at 61,031 (2003), and Schedule 17 charges, see Midwest Indep. Transmission Sys. Operator, Inc., 108 FERC ¶ 61,236, at 62,322 (2004). The Commission did note, however, that the transmission owners could ultimately pass through these costs as “new services,” id., if they could demonstrate that the services were indeed “new.”
The transmission owners took the hint. They proposed charges for new services and FERC, in its March 24, 2005 order (now under review before us), conditionally allowed the owners to impose Schedule 23 charges, which recover both Schedule 10 and Schedule 17 charges. Transmission Owners of the Midwest Indep. Transmission Sys. Operator, Inc., 110 FERC ¶ 61,339 (2005) (“Initial Order”). The Commission’s reasoning resembled our own in Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361 (D.C.Cir.2004): the Schedule 10 and Schedule 17 charges to be collected under Schedule 23 would recover the costs associated with benefits (including regional transmission pricing, regional transmission system planning, and improved grid reliability and efficiency) provided to all customers receiving service under the MISO, including customers of grandfathered agreements. See Initial Order at 62,348-50. In response to arguments that the benefits identified by the Commission in its proposal are not enjoyed by customers to grandfathered agreements because those customers do not use MISO’s energy markets or because the grandfathered agreements already provide such benefits, the Commission concluded that the MISO provides fundamentally new services and benefits that are different than those provided under the grandfathered agreements. See id at 62,350.
In response to parties’ assertions that the Commission had already denied recovery of Schedule 10 and 17 charges from customers to grandfathered contracts in its previous orders, the Commission noted that earlier proposals to collect those charges failed to demonstrate that the grandfathered contracts did not already include a mechanism for assessing the administrative charges in dispute. Id. In reviewing the transmission owners’ latest proposal, however, the Commission found that the deficiencies in earlier proposals had been addressed and corrected. The transmission owners had, according to FERC, ultimately demonstrated by argument and evidence what they had previously failed to demonstrate: the grandfa*469thered agreements did not, in fact, provide a mechanism for the recovery of charges associated with the administration of the MISO, which provided new benefits even to customers receiving service governed by grandfathered agreements. The Commission further concluded that, because the administration of the MISO provided new benefits to these customers, the transmission owners would not run afoul of the Federal Power Act (“FPA”) by charging their customers an administrative tariff— the Schedule 10 Cost Adder this Court previously required the owners to pay on their customers’ behalf.
FERC denied requests to rehear the Initial Order, reiterating its conclusion that the benefits provided by the MISO “could not have been provided by the MISO [transmission owners] to the customers [of grandfathered agreements] pri- or to the advent of the MISO,” and, therefore, the costs of providing those benefits, collected under Schedule 23, “are separate and distinct from the costs that the [transmission owners] recover under current provisions [of grandfathered agreements].” Transmission Owners of the Midwest Indep. Transmission Sys. Operator, Inc., 113 FERC ¶ 61,122, at 61,476 (2005) (“Rehearing Order”).
II.
We begin our analysis by addressing a jurisdictional challenge asserted by intervenors in support of petitioners. They do not dispute that we have jurisdiction over this matter, but instead argue that FERC lacked jurisdiction to approve Schedule 23, the proposed tariff, because it assesses the MISO’s costs on municipal and cooperative entities not subject to FERC’s jurisdiction. Intervenors’ Br. at 4-17. Petitioners do not raise this argument. And as we have previously noted, “absent extraordinary circumstances, intervenors ‘may join only on a matter that has been brought before the court’ by a petitioner.” Cal. Dep’t of Water Res. v. FERC, 306 F.3d 1121, 1126 (D.C.Cir.2002) (quoting Ala. Mun. Distrib. Group v. FERC, 300 F.3d 877, 879 (D.C.Cir.2002)). Although we must address intervenors’ claim when the issue they raise was preserved in their requests for Commission rehearing, see id. at 1126, neither of these intervenors before us filed a petition for review “within sixty days after the order of the Commission upon the application for rehearing,” as required by Section 313(b) of the FPA, 16 U.S.C. § 825Z (b), and thus have failed to satisfy a statutory requirement to guarantee judicial review of their claim, see Cal. Dep’t of Water Res., 306 F.3d at 1126-27. We may, nevertheless, exercise our discretion to consider intervenors’ claims, even absent extraordinary circumstances. Synovus Fin. Corp. v. Bd. of Governors of Fed. Res. Sys., 952 F.2d 426, 433 (D.C.Cir.1991) (permitting reviewing court to consider intervenor’s challenge to agency authority “consistent with this court’s traditionally flexible approach toward appellate procedure”). Because we believe that intervenors challenge an “essential predicate” to the issue on review, see id. at 434 (internal quotation marks and citation omitted), we consider their jurisdictional argument, but conclude that it is without merit.
As FERC has argued, see Respondent’s Br. at 35, Section 201(b) of the FPA, 16 U.S.C. § 824(b), grants FERC “jurisdiction over all rates, terms and conditions of electric transmission service provided by public utilities in interstate commerce, as well as over the sale of electric energy at wholesale.” Me. Pub. Util. Comm’n v. FERC, 454 F.3d 278, 282 (D.C.Cir.2006) (citations and internal quotation marks omitted). Although the FPA exempts certain governmental and cooperatively-*470owned entities from FERC regulation, see 16 U.S.C. § 824(f) (as amended by the Energy Policy Act of 2005, Pub.L. No. 109-58, § 1291(c), 119 Stat. 594, 985 (2005)), that exemption applies only to the provision of transmission services by the exempted entity, not to their receipt of services from regulated entities. See Initial Order at 62,350; Rehearing Order at 61,480. FERC’s jurisdiction over services provided by the MISO, a public utility providing interstate electric transmission service, does not depend on the identity of the MISO’s customers. As our sister circuit has held,
It would be inconsistent with the policy of [the FPA], as well as with certain of its provisions ... to hold that ... [exempted entities] are excluded from the benefits of the regulation of the utilities from which they buy. The entire thrust of Part II [of the FPA] is toward the seller at wholesale, not the buyer.
Cal. Elec. Power Co. v. FPC, 199 F.2d 206, 209 (9th Cir.1952); see also United States v. Pub. Util. Comm’n of Cal., 345 U.S. 295, 314-15, 73 S.Ct. 706, 97 L.Ed. 1020 (1953) (noting that Federal Power Commission’s “long assertion that it has authority over rates of sales to municipalities has probably risen to the dignity of an agency policy,” and was entitled to deference). We agree.
Having satisfied ourselves that FERC had jurisdiction to approve the challenged tariff, we next review FERC’s order under the familiar arbitrary and capricious standard. See 5 U.S.C. § 706(2)(A); Entergy Servs., Inc. v. FERC, 319 F.3d 536, 541 (D.C.Cir.2003). We accept the Commission’s factual findings if they are supported by substantial evidence, see 16 U.S.C. § 8251 (b), and affirm its orders where FERC has “examine^] the relevant data and articulate[d] a ... rational connection between the facts found and the choice made.” Motor Vehicle Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43, 103 S.Ct. 2856, 77 L.Ed.2d 443 (1983) (internal quotation marks and citation omitted). “[A]n agency must conform to its prior practice and decisions or explain the reason for its departure from such precedent,” United Mun. Distrib. Group v. FERC, 732 F.2d 202, 210 (D.C.Cir.1984) (citation omitted), and must provide “reasoned analysis indicating that prior policies and standards are being deliberately changed, not casually ignored.” Greater Boston Int’l Television Corp. v. FCC, 444 F.2d 841, 852 (D.C.Cir.1970). We are “particularly deferential” when FERC is involved in the highly technical process of ratemaking. Ass’n. of Oil Pipe Lines v. FERC, 83 F.3d 1424, 1431 (D.C.Cir.1996) (citing Time Warner Entertainment Co. v. FCC, 56 F.3d 151, 163 (D.C.Cir.1995) (“Because agency ratemaking is far from an exact science and involves policy determinations in which the agency is acknowledged to have expertise, our review thereof is particularly deferential.”)). See also Permian Basin Area Rate Cases, 390 U.S. 747, 790, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968) (“[T]he breadth and complexity of the Commission’s responsibilities demand that it be given every reasonable opportunity to formulate methods of regulation appropriate for the solution of its intensely practical difficulties.”).
HI.
We are asked in this case to determine whether the Commission’s decision to approve a disputed tariff meets the minimum standards for reasoned decisionmaking required by the Administrative Procedure Act (“APA”). See 5 U.S.C. § 706(2)(A). We conclude that it does. As we have already noted, the MISO’s costs may reasonably be assessed on all *471transmission loads delivered under the MISO grid, including those loads governed by grandfathered agreements, because the benefits of an ISO flow to all who transact on the grid. See Midwest ISO Transmission Owners, 373 F.3d at 1368-71. The question now before us is whether FERC’s approval of the method proposed to collect these costs from customers was unreasoned. We need only inquire whether FERC has examined the relevant data and articulated a rational connection between the facts found and the choice made. See Motor Vehicles Mfrs. Ass’n, 463 U.S. at 43, 103 S.Ct. 2856. We find that it has, especially in light of the particular deference afforded the Commission’s determination in this case, see Ass’n of Oil Pipe Lines, 83 F.3d at 1431.
In the order under review, the Commission scrutinized and then accepted the transmission owners’ assertion that the costs of operating the MISO and its energy markets were not recovered under the grandfathered agreements because the benefits brought by the MISO represent “new services” not previously provided under those pre-ISO grandfathered contracts. This argument — that the benefits that flow from having an ISO constitute “new services” — is hardly new. FERC had approved a similar rate hike in another region with another ISO. See Initial Order at 62,348 (citing Cal. Indep. Sys. Operator Corp., Opinion No. 463, 103 FERC ¶ 61,114 (2003), order on reh’g, 106 FERC ¶ 61,032 (2004) (finding that proposed rate recovered the California ISO’s costs for “new services,” which included planning and operation of the transmission grid that was “significantly different” than the previous system and improved reliability and delivery of ancillary services, increased efficiency and cost-effectiveness, and created new market opportunities to customers served under grandfathered agreements)). The Commission did nothing more with respect to the MISO transmission owners’s proposal than it had done to the California ISO transmission owners’ proposal. It first set out to determine whether the grandfathered agreements in this case already provide for the MISO benefits identified by the Commission and by this Court in Midwest ISO Transmission Owners. Next, the Commission examined whether the rates under those agreements already recover the costs associated with such benefits. In so doing, the Commission reiterated the benefits provided by the MISO to customers receiving service under grandfathered agreements. Those benefits include (1) independent and regional grid planning (as opposed to utility-by-utility planning), (2) enhanced reliability, (3) increased efficiency, (4) more effective management of grid congestion to accommodate greater power flows, (5) access to spot markets, and (6) price transparency to facilitate bilateral contract formation. See Initial Order at 62,348-49; Rehearing Order at 61,477-78. On the basis of these findings, the Commission concluded that
The services associated with [S]chedules 10 and 17, as a whole, represent a monumental transformation with respect to the way that electricity is sold and distributed in the Midwest ISO region — a change that will bring substantial [new] benefits to all those transacting over the Midwest ISO grid, including ... customers [of grandfathered agreements]. These services ... could not have been provided by the Midwest ISO [transmission owners] to the ... customers [of grandfathered agreements] prior to the advent of the Midwest ISO, and the costs that the Midwest ISO [transmission owners] propose to pass through to the customers [of grandfathered agreements] under [Schedule 23 thus are separate and dis*472tinct from the costs that the Midwest ISO [transmission owners] recover under current provisions [of the grandfathered agreements].
Initial Order at 62,350 (emphasis added).
FERC reasonably rested its decision on this “new services” analysis and considered evidence that the costs to be collected under Schedule 23 are “separate and distinct from the costs collected under the grandfathered agreements.” Initial Filing of the Midwest ISO Transmission Owners (Jan. 13, 2005), Exhibit No. MISO TOs-1 (Testimony of Alan C. Heintz) at 9-10 (“Heintz Testimony”) (describing benefits and services provided by Midwest ISO that were not available when grandfathered agreements were entered into).
Petitioners next argue that FERC’s approval of Schedule 23 costs imposed on customers of grandfathered agreements constitutes an irrational departure from Commission policy and precedent, which requires that grandfathered agreements be honored without interference. See Petitioner’s Br. at 28. Citing FERC Orders No. 888 and 2000, see id. at 29, Petitioners assert that FERC has consistently (1) “held that grandfathered contracts should be honored,” id. and (2) refused to interfere with those contracts by allowing their inclusion of Schedule 10 and Schedule 17 costs. See id. (citing Midwest Indep. Transmission Sys. Operator, Inc., Opinion No. 453-A, 98 FERC ¶ 61,141 (2002) (order on rehearing) and Midwest Indep. Transmission Sys. Operator, Inc., 108 FERC ¶ 61,236, at 62322 (2004), respectively). Petitioners conclude that FERC’s order, which permits the inclusion of Schedule 10 and Schedule 17 costs through the addition of Schedule 23 to grandfathered agreements, must therefore be vacated absent FERC’s rational explanation for inconsistencies with its own precedent. See Petitioner’s Br. at 30. Intervenors offer a similar argument by alleging that the Commission violated principles of res judicata and collateral estoppel when it ignored its prior orders denying the recovery of the MISO’s costs from customers of grandfathered agreements. See Intervenor’s Br. at 17-21.
The Commission, in response, argues that its orders were consistent with its prior rulings on the pass-through of the MISO’s costs to customers of grandfathered agreements and did not violate any relevant preclusion doctrines. FERC contends that it could not previously make a definitive cost recovery decision because the transmission owners had failed to provide sufficient evidence that they would be unable to recover Schedule 10 charges as a result of the Commission’s rulings. See Midwest Indep. Transmission Sys. Operator, 102 FERC ¶ 61,192, at 61,533-34. FERC offered the same reasoning to justify its denial of a proposed pass-through for Schedule 17 charges (created to cover the cost of running ISO energy markets) — the owners had failed to make a sufficient showing. See Midwest Indep. Transmission Sys. Operator, 108 FERC ¶ 61,236, at 62,322 (specifically noting that the owners had failed to provide any information regarding whether the grandfathered agreements already provided for the recovery of Schedule 17 charges). In the order under review, the Commission accepted a new tariff provision (Schedule 23) that, FERC argues, recovers Schedule 10 and 17 charges not already recovered under the grandfathered agreements. The Commission justifies its acceptance of Schedule 23 by describing evidence that its charges were associated with new services not previously provided under the agreements. See Initial Filing of Midwest ISO Transmission Owners (Jan. 13, 2005), Heintz Testimony; see also Initial Order at 62,-349-50. We agree that the Commission’s *473decision not to approve a proposed tariff under review due to insufficient evidence does not bar FERC from approving a similar tariff once sufficient evidence is proffered.
In further support of FERC’s reasoned decisionmaking, and in response to this Court’s order, intervenors on behalf of the Commission have submitted documents on file with FERC describing the “new services” for which Schedule 23 charges were proposed and approved. These tariff sheets and agreement sheets indicate, among other things, the construction of new facilities to enhance regional competition, Tariff Sheet 1833-52, as well as facilities that enhance regional transmission reliability, id.; see also Agreement Sheets 61 & 159. These record documents also describe regional services such as the calculation of available transmission capability, evaluation of transmission requests, and resolution of transmission constraints. See, e.g., Agreement Sheets 103-4a. We agree with intervenors that these documents likewise support their argument (and FERC’s conclusion) that Schedule 23 charges were assessed for “new services,” and therefore conclude that the Commission’s decision was rational and based on substantial record evidence.
Finally, petitioners argue that our review of this case must conform to the doctrine articulated in the Supreme Court’s decisions United Gas Pipe Line Co. v. Mobile Gas Serv. Corp., 350 U.S. 332, 76 S.Ct. 373, 100 L.Ed. 373 (1956), and FPC v. Sierra Pacific Power Co., 350 U.S. 348, 76 S.Ct. 368, 100 L.Ed. 388 (1956). Under the well-settled and oft-invoked Mobile-Sierra doctrine, utility providers that negotiate fixed-rate contracts with their customers may, as part of that negotiation, voluntarily relinquish “some of [the] rate-filing freedom” to which they are otherwise entitled under Section 205 of the FPA. Me. Pub. Util. Comm’n v. FERC, 454 F.3d at 283(citation omitted). Under such contracts, utility providers are prohibited from filing a new rate for services currently provided (and therefore subject to) the negotiated contract rate. Id. FERC is similarly prohibited from modifying the contract rate under the authority otherwise granted by Section 206 of the FPA, except where the modification is both required by the “public interest”1 and upon a showing that the changes are just, reasonable, and nondiscriminatory. Id. (citations omitted). We view the “public interest” standard as “much more restrictive than the FPA’s ‘just and reasonable’ standard.” Potomac Elec. Power Co. v. FERC, 210 F.3d 403, 407 (D.C.Cir.2000); see also Papago Tribal Auth. v. FERC, 723 F.2d 950, 954 (D.C.Cir.1983) (describing public interest standard as “practically insurmountable”). As discussed above, FERC has concluded that Schedule 23 imposes a new rate to recover the costs of new benefits and services received from the Midwest ISO and its energy markets by customers to grandfathered agreements. See Initial Order at 62,349-50; Rehearing Order at 61,477. The disputed Schedule 23 tariff does not “modify the rates, terms or conditions of services provided under the [grandfathered agreements],” Rehearing Order at 61,476. The Mobile-Sierra doctrine, powerful though it may be where it applies, is not implicated in this case and petitioners can therefore find no refuge in its protection.
*474IY.
For the foregoing reasons, we conclude that FERC’s order comports with reasoned decisionmaking, and we deny the petition for review.
So ordered.
. The Supreme Court has described the public interest standard as requiring modification of previously approved contracts in instances “where [the existing rate structure] might impair the financial ability of the public utility to continue its service, cast upon other consumers an excessive burden, or be unduly discriminatory.” Sierra Pac. Power Co., 350 U.S. at 355, 76 S.Ct. 368.