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AMERICAN MUNICIPAL POWER, INC., et al., Petitioners v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent American Transmission Systems Incorporated, et al., Intervenors
Petitioners, consisting of transmission owners, consumer-side stakeholders, state public utility commissions, and other entities located within the service territory of the PJM Interconnection, LLC (PJM), filed petitions, now consolidated, seeking review of seven underlying orders of the Federal Energy Regulatory Commission (the Commission). These orders address a series of issues flowing from an initial request by PJM to revise Attachment M-3 of its Open Access Transmission Tariff (Tariff) to provide for the identification and inclusion of asset management projects with specific reference to the planning and implementation for “end-of-life” (EOL) needs. First and foremost, Stakeholder Petitioners challenge the Commission's acceptance of the Attachment M-3 revision, but also contend that many other aspects of the Commission's decisionmaking was arbitrary and capricious, including its rejection of a Stakeholder-supported proposal regarding EOL transmission project planning. Separately, Transmission Owner Petitioners seek to overturn the Commission's finding of ambiguity regarding the identification of entities responsible for EOL needs as specified in the relevant governing documents.
For the reasons set forth below, the court dismisses the petition of Transmission Owner Petitioners and denies Stakeholder Petitioners’ petitions for review.
The Federal Power Act of 1920, 16 U.S.C. §§ 791a–828c (the Act), vests the Commission with regulatory authority over the “transmission of electric energy in interstate commerce and ․ the sale of electric energy at wholesale in interstate commerce,” id. § 824(b)(1), and requires all rates subject to the Commission's jurisdiction to “be just and reasonable,” id. § 824d(a).
Regional transmission organizations, or RTOs, “are independent organizations that manage the transmission of electricity over the electric grid and ensure electricity is reliably available for consumers.” Advanced Energy Mgmt. All. v. FERC, 860 F.3d 656, 659 (D.C. Cir. 2017). RTOs “serve several functions, including operating the electrical grid in a defined geographic area, balancing energy supply and demand, establishing markets for the sale and purchase of electricity, and ensuring the reliable transmission of electricity.” Citadel FNGE Ltd. v. FERC, 77 F.4th 842, 848 (D.C. Cir. 2023) (citation omitted). Using its authority under the Act, the Commission has encouraged the creation of RTOs by requiring all transmission facilities “to participate in an RTO or to explain their failure to do so.” Braintree Elec. Light Dep't v. FERC, 550 F.3d 6, 8 (D.C. Cir. 2008) (per curiam) (citing, e.g., Regional Transmission Organizations, 65 Fed. Reg. 810, 812 (Jan. 6, 2000) (Order No. 2000)).
PJM is a familiar party to this court. “Formed in 1927, PJM is the oldest and largest” RTO. Pub. Serv. Elec. & Gas Co. v. FERC, 783 F.3d 1270, 1271 (D.C. Cir. 2015) (citation omitted). Today, PJM “oversees [an] electric grid covering all or parts of thirteen Mid-Atlantic and Midwestern states and the District of Columbia.” Advanced Energy Mgmt., 860 F.3d at 659. “PJM takes its name from Pennsylvania, New Jersey, and Maryland, the first three states in which it operated, but its territory now extends as far west as Illinois.” Long Island Power Auth. v. FERC, 27 F.4th 705, 709 (D.C. Cir. 2022). “As an RTO, PJM coordinates the movement of electricity across the region” and “operates transmission facilities owned by member utilities, approves the construction of new facilities, and files tariffs allocating among its members the costs of the facilities.” Id.
PJM carries out its duties in conformity with policies set forth in its governing agreements, which include PJM's Operating Agreement, the Consolidated Transmission Owners Agreement (Owners Agreement), and the Tariff on file with the Commission. See Pub. Serv. Elec., 783 F.3d at 1271. PJM's authority to oversee and operate the electrical grid is limited to that granted to it by transmission owners in the Owners Agreement. Transmission owners are “Member[s] that own[ ] or lease[ ] with rights equivalent to ownership Transmission Facilities and is a signatory to the ․ Owners Agreement.” Tariff, OATT Definitions — T — U — V (J.A. 2254). Transmission owners expressly retain all “[r]ights not specifically transferred ․ to PJM pursuant to [the Owners] Agreement or any other agreement.” Owners Agreement § 5.6 (J.A. 2359).
On June 12, 2020, the Transmission Owners Agreement Administrative Committee (TOA-AC) filed a proposal (June Proposal), accompanied by a cover letter written by counsel, with the Commission on behalf of certain transmission owners pursuant to § 205 of the Act, 16 U.S.C. § 824d. The transmission owners sought to revise and expand the scope of Attachment M-3 of the Tariff, which
sets forth the procedures that the Transmission Owners employ to plan Supplemental Projects, which are expansions and enhancements to the Transmission System that are not required to satisfy certain PJM regional planning criteria, in a manner that satisfies the requirements of Order No. 890 for openness and transparency.1
Cover Letter of June Proposal at 2–3 (J.A. 0003). Through counsel, the transmission owners explained the revision to Attachment M-3 would expand it “from solely prescribing procedures governing the planning of Supplemental Projects,” id. at 2 (J.A. 0002), to also include “planning procedures [for] asset management projects that affect PJM's modeling of the transmission system, which will enhance transparency and the opportunity for stakeholder review of these projects,” id. at 11 (J.A. 0011).
In the June Proposal, “asset management projects” were defined as
any modification or replacement of a Transmission Owner's Transmission Facilities that results in no more than an Incidental Increase in transmission capacity undertaken to perform maintenance, repair, and replacement work, to address an EOL Need, or to effect infrastructure security, system reliability, and automation projects the Transmission Owner undertakes to maintain its existing electric transmission system and meet regulatory compliance requirements.
J.A. 32. Relevant to this definition, an “Incidental Increase” was defined as “an increase in transmission capacity achieved by advancements in technology and/or replacement consistent with current Transmission Owner design standards, industry standards, codes, laws or regulations, which is not reasonably severable from an Asset Management Project.” J.A. 33. However, “[a] transmission project that results in more than an Incidental Increase in transmission capacity is an expansion or enhancement of Transmission Facilities.” J.A. 33.
The transmission owners’ counsel conveyed that asset management projects included, but were not limited to:
(i) maintenance, repair and replacement activities, including but not limited to capital additions; (ii) work on infrastructure at the end of its useful life; (iii) work to satisfy compliance requirements; (iv) infrastructure security; (v) system reliability and automation; (vi) information technology; (vii) work requested by others (including generator interconnection); and (viii) increases in transmission capacity that are incidental to, and not reasonably severable from, the asset management project or activity.
Cover Letter of June Proposal at 5 (J.A. 0005) (citation omitted).
The transmission owners also sought to address in the June Proposal the coordination of EOL needs with the Regional Transmission Expansion Plan (RTEP), as outlined in Schedule 6 of the Operating Agreement, “when a single solution would address both the EOL need and the need to plan for a Required Transmission Enhancement under the RTEP Planning Process.” Cover Letter of June Proposal at 2 (J.A. 0002). EOL needs were defined to
mean a need to replace a transmission line between breakers operating at or above 100 kV or a transformer, the high side of which operates at or above 100 kV and the low side of which is not connected to distribution facilities, which the Transmission Owner has determined to be near the end of its useful life, the replacement of which would be an Attachment M-3 Project.
Less than a week after the June Proposal was filed, two other transmission owners moved the Commission to dismiss the June Proposal on the basis that it was filed by the TOA-AC without proper notice under the Owners Agreement. Mot. to Dismiss June Proposal at 1–2, 5–7 (J.A. 0107–0108, 0111–0113). In addition, several interested parties filed a protest to the June Proposal (IP Protest), citing the notice issue and advocating that the Commission should instead accept a separate joint stakeholder proposal dated July 2, 2020. IP Protest at 10–11 (J.A. 0129–0130).
On August 11, 2020, the Commission accepted the June Proposal and its Tariff Attachment M-3 revisions. Order Accepting Proposed Tariff Revisions, 172 FERC ¶ 61,136 (Aug. 11, 2020) (Acceptance Order) (J.A. 0420–55). The Commission found that transmission owners retained “exclusive rights” under the Owners Agreement to make filings related to the planning activities at issue, and they had complied with the terms of the Owners Agreement in so doing. Id. at P 81 (J.A. 0449–50). The Commission further found that asset management project planning had not been transferred to PJM because such projects “relate solely to maintenance of existing facilities” and “are solely projects that maintain the existing infrastructure by repairing or replacing equipment.” Id. at P 83 (J.A. 0450). The Commission explained that the Owners Agreement only granted PJM “the right to plan for ‘expansion’ or ‘enhancement’ of the grid as part of the RTEP.” Id. at P 86 (J.A. 0451). As a result, outside of EOL needs included in Form No. 715, PJM's transmission owners “did not transfer the planning responsibility for all end[-]of[-]life criteria to PJM.”2 Id. Soon thereafter, the Commission denied a request for rehearing by parties protesting acceptance of the June Proposal by operation of law, see Notice of Denial of Rehearing by Operation of Law and Providing for Further Consideration, 173 FERC ¶ 62,021 (Oct. 13, 2020) (J.A. 0552).
Two months later, the Commission addressed the protesting parties’ arguments for rehearing and reached the same result. Order Addressing Arguments Raised on Rehearing, 173 FERC ¶ 61,225 (Dec. 17, 2020) (PP Reh'g Order) (J.A. 0560–91). However, the Commission modified the Acceptance Order with additional explanations to support the decision. Of note, the Commission expressly rejected the protesting parties’ contentions that the Owners Agreement required a vote to initiate the § 205 filing process, and it disagreed that the proposed Attachment M-3 revisions were inconsistent with the Operating Agreement, shifted planning for asset management projects from PJM to the transmission owners, created a new federal right of first refusal in violation of the Commission's decision in Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, 136 FERC ¶ 61,051 (July 21, 2011) (Order No. 1000),3 or generally violated Order No. 2000.
On the same day it issued the Protesting Parties Rehearing Order, the Commission rejected the joint stakeholders’ July Proposal. Order Rejecting Proposed Tariff Revisions, 173 FERC ¶ 61,242 (Dec. 17, 2020) (Rej'n Order) (J.A. 1940–69). The Commission found the July Proposal “goes beyond the scope of planning responsibilities delegated to PJM” in the Operating Agreement because EOL needs “involve decisions regarding retirement and maintenance of existing equipment,” which are responsibilities expressly retained by transmission owners. Id. at P 54 (J.A. 1962–63). The Commission explained that its decision was consistent with its prior decisions on the scope of RTO planning because PJM did “not have the authority to perform the[ ] planning activities” specified by the joint stakeholders. Id. at P 57 (J.A. 1964). The Commission denied the joint stakeholders’ request for rehearing, see Notice of Denial of Rehearing by Operation of Law and Providing for Further Consideration, 174 FERC ¶ 62,111 (Feb. 19, 2021) (J.A. 2021), and issued an order explaining the reasons for its denial, Order Addressing Arguments Raised on Rehearing, 176 FERC ¶ 61,053 (July 29, 2021) (Stakeholder Reh'g Order) (J.A. 2024–64). In the Stakeholder Rehearing Order, the Commission reached the same result, but a Commission majority found for the first time that the Owners Agreement was ambiguous regarding whether projects addressing EOL needs were entrusted to PJM. Relying on extrinsic evidence, the Commission majority still interpreted the Owners Agreement as not transferring consideration of EOL needs to PJM. Id. at P 17 (J.A. 2032). A few months thereafter, the Commission denied requests for rehearing as to the Stakeholder Rehearing Order by operation of law. See Notice of Denial of Rehearing by Operation of Law, 176 FERC ¶ 62,158 (Sept. 30, 2021).
Petitioners from both the stakeholders and the transmission owners responded by filing in this court six timely petitions for review of the Commission's orders.
Before turning to the merits of Stakeholder Petitioners’ claims, we first address the Commission's challenge to Transmission Owner Petitioners’ standing to contest the Stakeholder Rehearing Order. The Commission disputes whether Transmission Owner Petitioners “have suffered any concrete injury sufficient for Article III standing purposes.” Comm'n Br. 57. In this regard, the Commission asserts that not only did it accept Transmission Owner Petitioners’ June Proposal, but the ambiguity finding in the Stakeholder Rehearing Order does not create sufficient harm to constitute an injury in fact. In response, Transmission Owner Petitioners contend that they have standing because the “uncertainty” in the project planning process “where it did not previously exist,” Transmission Owners Pet'rs. Br. 21, add. 8 ¶ 13, and the uncertainty regarding their “ongoing rights and responsibilities under the Owners Agreement,” id. at add. 8 ¶ 14, are cognizable injuries.
“It is well established that a federal court cannot act in the absence of jurisdiction,” and “[i]t is equally well established that Article III standing is a prerequisite to federal court jurisdiction.” Am. Libr. Ass'n v. FCC, 401 F.3d 489, 492 (D.C. Cir. 2005) (citations omitted). Transmission Owner Petitioners have standing if they “have (1) an injury in fact, (2) fairly traceable to the challenged agency action, (3) that will likely be redressed by a favorable decision.” Kan. Corp. Comm'n v. FERC, 881 F.3d 924, 929 (D.C. Cir. 2018) (citation omitted). “An injury in fact is an ‘invasion of a legally protected interest which is (a) concrete and particularized, and (b) actual or imminent, not conjectural or hypothetical.’ ” Id. (citation omitted).
In New England Power Generators Ass'n v. FERC, this court, in addressing an argument regarding the chilling effect of a decision by the Commission, stated that “broad-based market effects stemming from regulatory uncertainty are quintessentially conjectural, and it is difficult to imagine a FERC action that would not confer standing under this theory.” 707 F.3d 364, 369 (D.C. Cir. 2013) (citation omitted). The court further reasoned that “[i]t would be a strange thing indeed if uncertainty were a sufficiently certain harm to constitute an injury in fact.” Id. Here, Transmission Owner Petitioners present a similar injury of uncertainty and, therefore, we find they are unable to establish injury in fact. Accordingly, we do not address the merits of Transmission Owner Petitioners’ challenge to the Commission's finding of ambiguity in the Stakeholder Rehearing Order. The court will later address the question of ambiguity in regard to Stakeholder Petitioners’ challenge to the Commission's interpretation of the Owners Agreement, as Stakeholder Petitioners are able to establish injury in fact.
This court has jurisdiction to review the Commission's orders pursuant to § 313(b) of the Act. 16 U.S.C. § 825l(b) (“Any party to a proceeding ․ aggrieved by an order issued by the Commission ․ may obtain a review of such order in the United States court of appeals” and “[u]pon the filing of such petition such court shall have jurisdiction.”). The court reviews the Commission's orders under the familiar arbitrary and capricious standard of the Administrative Procedure Act. See Entergy Servs., Inc. v. FERC, 568 F.3d 978, 981 (D.C. Cir. 2009) (citing 5 U.S.C. § 706(2)(A)). The court is empowered “to reverse any agency action that is ‘arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.’ ” Hoopa Valley Tribe v. FERC, 913 F.3d 1099, 1102 (D.C. Cir. 2019) (citation omitted). However, the court will uphold the Commission's determination if it “examine[d] the relevant data and articulate[d] a satisfactory explanation for its action including a ‘rational connection between the facts found and the choice made.’ ” Motor Vehicle Mfrs. Ass'n of U.S. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43, 103 S.Ct. 2856, 77 L.Ed.2d 443 (1983) (quoting Burlington Truck Lines, Inc. v. United States, 371 U.S. 156, 168, 83 S.Ct. 239, 9 L.Ed.2d 207 (1962)). The Commission “must ‘demonstrate that it has made a reasoned decision based upon substantial evidence in the record, and the path of its reasoning must be clear.’ ” Seminole Elec. Coop., Inc. v. FERC, 861 F.3d 230, 234 (D.C. Cir. 2017) (citations omitted). “So long as any change is reasonably explained, it is not arbitrary and capricious for an agency to change its mind in light of experience, or in the face of new or additional evidence, or further analysis or other factors indicating that the agency's earlier decision should be altered or abandoned.” New Eng. Power Generators Ass'n v. FERC, 879 F.3d 1192, 1201 (D.C. Cir. 2018) (citation omitted).
Stakeholder Petitioners make several challenges to the Commission's orders. None persuade us.
First, Stakeholder Petitioners argue the Commission acted arbitrarily and capriciously by not rejecting the June Proposal because it contained a planning provision that was outside the scope of the transmission owners’ retained filing rights and the Owners Agreement required a vote prior to any action taken by the TOA-AC. Stakeholder Petitioners support this argument by first explaining that Tariff § 9.1 limited transmission owners to unilateral § 205 filings addressing rate and revenue issues. Because the revisions in the June Proposal related to transmission planning, the transmission owners did not have authority under either the Tariff or the Owners Agreement to file the June Proposal with the Commission. Stakeholder Petitioners also contend the Commission was obligated to dismiss the June Proposal because the Owners Agreement § 8.5 required a combination of two votes before the TOA-AC could act and “[n]o such vote[s] occurred.” Pet'rs. Br. 34.
The Commission's decision to accept the June Proposal was not unreasonable, as Tariff § 9.1 did not limit filings to only rate and revenue issues or otherwise revoke the principle that transmission owners “reserve all rights not specifically granted to PJM.” Owners Agreement § 5.6 (J.A. 2359). In Monongahela Power Co., 164 FERC ¶ 61,217 (Sept. 26, 2018), the Commission explained that PJM transmission owners “remain responsible for planning Supplemental Projects” and it was further “just and reasonable for the PJM [t]ransmission [o]wners to establish the process for planning ․ transmission projects and to initiate [them] under section 205 [for] any proposed revisions.” Id. at P 14. Consistent with its reasoning in Monongahela Power Co., the Commission reasonably concluded that all § 205 filings have not been ceded to PJM, and without an unambiguous ceding of filing rights to PJM, the transmission owners still retained them.
Moreover, the Commission sufficiently explained why the two-vote requirement to initiate the filing process for the June Proposal was unnecessary. The Commission identified and described the relevant provisions at issue—§§ 7.3.2 and 8.5 of the Owners Agreement and § 9.1(b) of the Tariff. The Commission further explained that these provisions did not require either (1) a vote to initiate the consultative process or (2) a formal prerequisite to initiate consultation with PJM and the PJM Members Committee. See, e.g., Acceptance Order at P 79 (J.A. 0449) (“However, section 8.5 of the CTOA does not require a vote to initiate the consultative process ․ Neither section 7.3.2 of the CTOA nor section 9.1(b) of the Tariff require any formal prerequisite for initiating the consultation with PJM and the PJM Members Committee.”). As a result, the Commission's consideration of the express language of these provisions and the stated rationale behind its interpretation support reasoned decisionmaking. Cf. FERC v. Elec. Power Supply Ass'n, 577 U.S. 260, 292, 136 S.Ct. 760, 193 L.Ed.2d 661 (2016) (“A court is not to ask whether a regulatory decision is the best one possible or even whether it is better than the alternatives.”).
Stakeholder Petitioners next argue that the Commission's finding that transmission owners always retained authority to plan the new category of “Asset Management Projects” is arbitrary and capricious because some of these projects fall within PJM's authority to plan the existing category of “enhancement[s] and expansion[s].” Pet'rs. Br. 37 (citation omitted). Stakeholder Petitioners contend that the Commission applied a narrow definition of “enhance” and “enhancement” when the dictionary definition of these terms would have established that EOL needs have regional benefits subjecting them to PJM's regional planning authority.
Succinctly, the Commission advanced counterarguments, which preclude a finding that its decisionmaking was arbitrary or capricious. As the Commission interpreted the Owners Agreement and Operating Agreement, the categories of asset management projects and enhancements did not overlap. The Commission said the “current division of responsibilities,” that is, the dividing line between these two categories, was “consistent with the California Orders,” decisions issued by the Commission in Southern California Edison Co. Local Transmission Planning Within the California Independent System Operator Corp., 164 FERC ¶ 61,160 (Aug. 31, 2018) (S. Cal. Edison Co.), and California Public Utilities Commission v. Pacific Gas and Electric Co., 164 FERC ¶ 61,161 (Aug. 31, 2018) (Cal. Pub. Utils. Comm'n). Stakeholder Reh'g Order at P 20 (J.A. 2034).
The Commission provided the following explanation as to why the California Orders had relevance in this matter:
In the California Orders, the Commission determined that “asset management” projects do not fall under Order No. 890 planning principles and therefore do not have to go through the Order No. 890 process. ․ [A]s the PJM Transmission Owners voluntarily have included Asset Management Projects under their Order No. 890 protocols, the Commission found that the definition of “asset management” projects in the California Orders supported its determination that the Asset Management Projects in the PJM Transmission Owners’ proposal fell under the filing rights that the PJM Transmission Owners retained. In the California Orders, the Commission found that “asset management” projects “do not, as a general matter, expand the California Independent System Operator (CAISO) grid. Rather, these asset management projects and activities include such items as maintenance, compliance, work on infrastructure at the end-of-useful life, and infrastructure security, that SoCal Edison undertakes to maintain its existing electric transmission system and meet regulatory compliance requirements.” The Asset Management Projects included in Attachment M-3 Revisions in this proceeding are consistent with this definition as they do not expand the PJM grid, but encompass maintenance and replacement of infrastructure.
PP Reh'g Order at P 20 (J.A. 570–71) (citations omitted). In the California Orders, the Commission recognized that some replacements with incidental increases in capacity were still replacements, rather than new transmission capacity. See S. Cal. Edison Co., 164 FERC ¶ 61,160 at P 33 (“We find that this type of incidental increase in transmission capacity that is a function of advancements in technology of the replaced equipment, ․ would not render the asset management project or activity in question a transmission expansion that is subject to the transmission planning requirements of Order No. 890.”); see also Cal. Pub. Utils. Comm'n, 164 FERC ¶ 61,161 at P 68. Under our circuit's Chevron-like deference, the Commission's interpretation of both categories was reasonable. NextEra Desert Ctr. Blythe, LLC v. FERC, 852 F.3d 1118, 1121 (D.C. Cir. 2017) (“First, we consider de novo whether the relevant language unambiguously addresses the matter at issue. If so, the language controls ․ If, however, there is ambiguity, we defer to the Commission's construction ․ so long as that construction is reasonable.”) (cleaned up).
Whether an “enhancement” includes a replacement that adds no more than an incidental increase is ambiguous. The Commission's interpretation that it does not was reasonable.
However, whether the transmission owners’ Attachment M-3 amendment is consistent with the California Orders is a closer call, yet the Commission's interpretation is still reasonable. Despite using the same phrase as the California Orders, the amendment defines an “Incidental Increase” to include actions that arguably go beyond the California Orders, such as improvements up to “current Transmission Owner design standards.” J.A. 0033. Similar to the California Orders, however, the amendment specifies that the improvements must not be “reasonably severable” from the asset management project.4 J.A. 33. This definition does not unambiguously answer the interpretive question. We do not need to determine that the Commission's narrow interpretation of “Incidental Increase” in the amendment is synonymous with “incidental increase” in the California Orders is the best reading; we ask only whether it is a reasonable one. NextEra Desert Ctr. Blythe, LLC, 852 F.3d at 1121. The transmission owners’ submission confirms that they intended to import the California Orders’ concept of incidental increase. In their cover letter summarizing the proposed amendment, the transmission owners described their definition as “based on” those orders. Cover Letter of June Proposal at 14 (J.A. 0014). As a result, the Commission's rationale behind its interpretation was reasonable.
Third, Stakeholder Petitioners maintain that the Commission's use of the California Orders to support its interpretation of the Owners Agreement was arbitrary and capricious. Stakeholder Petitioners assert that because there were differences in contractual terms, facts, and agreements under review, the Commission's reliance on the California Orders was unwarranted in “determining PJM's planning authority under the Owners Agreement” and accepting the June Proposal. Pet'rs. Br. 47–48. For example, Stakeholder Petitioners argue that the difference in how the Commission defined a term like “asset management” in the California Orders, in the context of Order No. 890, should have no bearing here because that term does not appear in the Owners Agreement. Pet'rs. Br. 48 (referencing 164 FERC ¶ 61,161 at P 65 n.119 (“While the definitions ․ vary slightly, they all encompass the maintenance, repair, and replacement work done on existing transmission facilities as necessary to maintain a safe, reliable, and compliant grid based on existing topology.”)).
The Commission provided a sufficient explanation as to why Stakeholder Petitioners’ arguments overstate the influence of the California Orders on the acceptance of the June Proposal. The Commission responded that it never even considered whether the asset management projects specified in the June Proposal had to comply with Order No. 890 because the revision to Attachment M-3 included its own criteria for asset management projects. The Commission further reasoned that it did not have to either agree with the California Orders, although it did in the Acceptance Order, or find that asset management projects avoid Order No. 890 scrutiny, to approve the June Proposal. In this respect, the Commission maintains that its acceptance of the June Proposal was “based [on] its determination on the planning rights reserved by the PJM Transmission Owners in the [Owners Agreement] and in the PJM Operating Agreement” and not in reliance on Order No. 890 or the California Orders. PP Reh'g Order at P 35 (J.A. 0577).
Fourth, Stakeholder Petitioners contend that the Commission's assignment of EOL needs to individual transmission owners is arbitrary and capricious because it “violates the regional transmission organization planning requirements of Order No. 2000 and the regional planning requirements of Order No. 1000.” Pet'rs. Br. 49 (citation omitted). Stakeholder Petitioners complain the Commission's orders allow transmission owners “to locally dictate the future of the Transmission Facilities and system that PJM administers.” Pet'rs. Br. 51.
In response, the Commission provided a reasonable explanation for why its acceptance of the June Proposal did not violate either Order No. 1000 or Order No. 2000, and was therefore reasoned, principled, and based upon the record. Firstly, the Commission explained why acceptance of the June Proposal did not violate Order No. 1000. The proposed revisions to Attachment M-3 were “limited to those transmission projects that PJM cannot plan for as the PJM Transmission Owners retained the planning rights for these projects.” PP Reh'g Order at P 37 (J.A. 0578). With this starting point, the Commission then reminded that the projects retained by transmission owners were the non-regional transmission projects described in the Attachment M-3 revision. Id. Because Order No. 1000 only applies to regional transmission plans, id., the Commission found there could be no violation of the requirement to eliminate the right of first refusal. See Order No. 1000 at P 313.
Next, the Commission explained why its acceptance of the June Proposal did not violate Order No. 2000. The Commission summarized Order No. 2000's requirements and planning guidance: “It required that the RTO (1) encourage market-motivated operating and investment actions for preventing and relieving congestion, and (2) accommodate efforts by state regulatory commissions to create multi-state agreements to review and approve new transmission facilities, coordinated with programs of existing Regional Transmission Groups (RTGs) where necessary.” PP Reh'g Order at P 39 (J.A. 0579) (citing Order No. 2000, 65 Fed. Reg. at 905). The Commission further noted that the RTO conversion process allowed for “considerable flexibility in designing a planning and expansion process that works best for its region.” Id. (citing Order No. 2000, 65 Fed. Reg. at 905). Putting aside this flexibility, PJM's Tariff, Owners Agreement, and Operating Agreement were consistent with the requirements of Order No. 2000. Id.
Stakeholder Petitioners next argue that the Commission's conclusion that the inclusion of EOL needs in a transmission owner's Form No. 715 filing is voluntary was arbitrary and capricious. Form No. 715 requires identification of “all ‘potentially available transmission capacity and known constraints,’ ” and a “description of the transmission planning reliability criteria used to evaluate system performance.” Pet'rs. Br. 54 (quoting Old Dominion Elec. Coop. v. FERC, 898 F.3d 1254, 1262–63 (D.C. Cir 2018)). Stakeholder Petitioners emphasized “[t]here is no question” that EOL needs impact these criteria and thus would be required to be included on the “Form [No.] 715, either on a regional basis or on an individual transmission owner basis.” Pet'rs. Br. 54.
In response, the Commission advanced two counterarguments, which preclude a finding that its decisionmaking was arbitrary or capricious. First, the Commission acknowledged that transmission owners transferred to PJM planning authority for criteria included on Form No. 715. See Acceptance Order at P 86 (J.A. 0451); PP Reh'g Order at P 59 (J.A. 0586). Next, the Commission called attention to the fact that the revisions to Attachment M-3 were expressly made inapplicable “to projects to address planning criteria filed by Transmission Owners in Form No. 715.” Cover Letter of June Proposal at 13 (J.A. 0013); PP Reh'g Order at P 59 (J.A. 0586). For those reasons, the Commission concluded that the transmission owners had two options available to them. They can “include [EOL] criteria in their Form No. 715 in which case PJM will continue to plan for all EOL Projects” or, alternatively, they can “choose not to include [EOL] criteria in its Form No. 715 in which case the transmission project will be planned under the Attachment M-3 Revisions.” PP Reh'g Order at P 59 (J.A. 0586–87). The Commission then noted the distinction “between the right to ‘plan’ an Attachment M-3 Project and the ability to only ‘propose’ a transmission project to address a Form No. 715 planning criteria” Id. at P 60 (J.A. 0587). “PJM will still plan transmission projects to address Form No. 715 planning criteria and if it disagrees with the PJM Transmission Owner's justification, PJM may determine that a single project resolves both the PJM Planning Criteria and the end of life criteria.” Id. In considering the totality of its explanation, the Commission conclusion was consistent with reasoned decisionmaking.
Finally, Stakeholder Petitioners assert that the Commission's failure to either address their arguments that the June Proposal was “unjust and unreasonable” or acknowledge the local cost allocation for EOL needs was arbitrary and capricious. Pet'rs. Br. 56. As to the former, Stakeholder Petitioners suggest that the Commission could not meet its obligations under § 205 without considering cost allocation and, if it had, the Commission would have rejected the June Proposal for “yield[ing] unjust and unreasonable rates.” Pet'rs. Br. 57. As to the latter, Stakeholder Petitioners declare that EOL needs provide regional benefits and require regional cost allocation.
In its initial decision, the Commission explained that the cost allocation was beyond the scope of the proceedings because it relates to Schedule 12 of the Tariff and the July Proposal did not seek to revise either Schedule 12 or cost allocation provisions. Acceptance Order at P 91 (J.A. 0453). And the Commission elaborated on its rationale, in its Protesting Parties Rehearing Order, explaining that it lacked authority under § 205 to amend cost allocation provisions of Schedule 12 to address issues only tangentially related to cost allocation. PP Reh'g Order at P 65, 66 (J.A. 0589). The Commission addressed Stakeholder Petitioners’ reliance on Old Dominion stating that the court's “dicta,” acknowledging that nothing prevents PJM from amending its governing documents, “was related to the planning for transmission projects to address Form No. 715 planning criteria, which are within PJM's planning responsibility.” Id. at P 66 (J.A. 0589) (referencing Old Dominion, 898 F.3d at 1263). However, the Old Dominion court did not create an apparatus to “enable the Commission to revise the unchanged cost allocation provisions of Schedule 12 of the PJM Tariff.” Id. Considering all the aforementioned, the Commission's reasoning for not addressing cost allocation is consistent with reasoned decisionmaking.
For the foregoing reasons, Transmission Owner Petitioners fail to establish injury in fact to have standing and Stakeholder Petitioners fail to demonstrate that the Commission's orders at issue in this matter were arbitrary and capricious. Therefore, the court dismisses the petition of Transmission Owner Petitioners and denies the petitions of Stakeholder Petitioners.
1. In Order No. 890, the Commission addressed issues of unjustness, unreasonableness, discrimination, and preferential treatment in transmission service by requiring transmission providers “to establish an open, transparent, and coordinated transmission planning process that complied with nine planning principles” of coordination, openness, transparency, information exchange, comparability, dispute resolution, regional participation, economic planning studies, and cost allocation for new projects. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 51 (D.C. Cir. 2014) (per curiam) (citing Preventing Undue Discrimination and Preference in Transmission Service, 118 FERC ¶ 61,119 at P 445–561 (Feb. 16, 2007)).
2. “Form No. 715 is the Annual Transmission Planning and Evaluation [Report] filed by the individual transmission owners, and is not limited to EOL Needs.” Acceptance Order, 172 FERC ¶ 61,136 at P 86 n.139 (J.A. 0451).Form No. 715 requires each respondent (transmitting utilities that operate integrated transmission system facilities that are rated at or above 100 kilovolts), inter alia, to submit annually, by April 1, a contact person (Part 1), its base case power flow data (Part 2), transmission system maps and diagrams used by the respondent for transmission planning (Part 3), a detailed description of the transmission planning reliability criteria used to evaluate system performance for time frames and planning horizons used in regional and corporate planning (Part 4), a detailed description of the respondent's transmission planning assessment practices (Part 5), and a detailed evaluation of the respondent's anticipated system performance as measured against its stated reliability criteria using its stated assessment practices (Part 6).New Reporting Requirements Implementing Section 213(b) of the Federal Power Act and Supporting Expanded Regulatory Responsibilities Under the Energy Policy Act of 1992, and Conforming and Other Changes to Form No. FERC-714, 100 FERC ¶ 61,141 at P 2 (Aug. 1, 2002).
3. The Commission promulgated Order No. 1000 “[t]o promote more efficient coordination among electric utilities.” Old Dominion Elec. Coop. v. FERC, 898 F.3d 1254, 1256 (D.C. Cir 2018) (citation omitted). In Order No. 1000, the Commission “addressed rights of first refusal” directing “transmission owners to remove from their tariffs and agreements any provision creating a federal right of first refusal over the construction of a new facility included in a regional transmission plan.” Coal. of MISO Transmission Customers v. FERC, 45 F.4th 1004, 1010 (D.C. Cir. 2022) (citing Order No. 1000 at P 313).
4. In Southern California Edison Company Local Transmission Planning Within the California Independent System Operator Corp., the Commission described the incidental increase concept this way:We recognize that there may be instances in which a [participating transmission owners’ or] PTO's asset management project or activity may result in an incidental increase in transmission capacity that is not reasonably severable from the asset management project or activity. For example, CAISO explained that if a PTO, such as SoCal Edison, needed to replace an aging 1940-vintage transformer at the end of its useful life, a like-for-like replacement with equipment from 1940 would not be feasible. Instead, CAISO states, the PTO would likely replace the old equipment with a modern transformer, which could be of a higher capacity if the PTO has standardized transformer sizes across its system to allow for sparing should the transformer fail. Such an increase in transmission capacity would be incidental to, and not reasonably severable from, the asset management project or activity required to meet the PTO's need. We find that this type of incidental increase in transmission capacity that is a function of advancement in technology of the replaced equipment, and is not reasonably severable from the asset management project or activity, would not render the asset management project or activity in question a transmission expansion that is subject to the transmission planning requirements of Order No. 890.S. Cal. Edison Co., 164 FERC ¶ 61,160 at P 33.
Childs, Circuit Judge:
Response sent, thank you
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Docket No: No. 20-1449
Decided: November 17, 2023
Court: United States Court of Appeals, District of Columbia Circuit.
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