The United States Court of Appeals for the District of Columbia Circuit reviewed petitions concerning orders from the Federal Energy Regulatory Commission (FERC) related to significant upgrades in the electricity transmission grid in northern New Jersey. These upgrades, authorized by PJM Interconnection, LLC, were necessary due to aging infrastructure, storm damage, and susceptibility to short circuits. The projects, which included improvements between Public Service Electric and Gas Company's (PSE&G) Bergen and Linden switching stations and repairs at the Sewaren substation, totaled approximately $1.3 billion. Initially, PJM assigned the majority of costs to entities that were rerouting electricity from northern New Jersey to the New York market. After those New York entities relinquished their rights to withdraw electricity from New Jersey, PJM reassigned the costs to PSE&G. FERC approved both the initial and subsequent cost allocations, prompting the legal challenges from Consolidated Edison Company of New York and the New Jersey Board of Public Utilities among others. The case involved multiple parties, including intervenors supporting both petitioners and respondents.
Petitions for review challenge whether cost allocations made by FERC are “just and reasonable” under the Federal Power Act, and whether FERC's decisions were “arbitrary and capricious” under the Administrative Procedure Act. The petitions involve thirteen cases against twenty FERC orders, with multiple parties and complex procedural histories. The Federal Power Act mandates that FERC regulate rates for interstate electricity transmission to ensure they reflect actual costs incurred, adhering to a cost-causation principle. FERC must approve new rates and can investigate existing rates for unfairness or undue discrimination.
The petitions stem from the relationships among utilities and the FERC-sanctioned method by which PJM allocates costs for major infrastructure projects in the mid-Atlantic region. PJM coordinates electricity transmission from North Carolina to New Jersey, with PSE&G being the primary provider in northern New Jersey. The interconnected PJM and New York Independent System Operator (NYISO) grids facilitate significant electricity flow across state lines. A key element of the case involves a "wheeling agreement" established in the 1970s between PSE&G and ConEd, which was solidified in a 2009 settlement allowing for the exchange of 1,000 megawatts of electricity, enabling efficient service delivery in New York City without constructing new transmission infrastructure.
Electricity prices on the PJM and NYISO grids can differ, leading to the establishment of merchant transmission facilities like Linden VFT, LLC and Hudson Transmission Partners, LLC, which take advantage of these price disparities by rerouting electricity from New Jersey to New York for profit. These facilities hold firm transmission withdrawal rights, allowing them to extract a specified quantity of electricity from the PJM grid at nearly any time. PJM is responsible for coordinating the development of the mid-Atlantic grid and allocating costs for major improvements among its utilities.
In 2011, FERC's Order No. 1,000 mandated that each planning region establish a method for allocating costs of new transmission projects, requiring adherence to specific principles, including cost causation (Principle 1) and limiting cost assignment to parties within the project’s planning region unless otherwise agreed (Principle 4). PJM developed an ex ante cost allocation method under this order, incorporated into its Open Access Transmission Tariff, which allocates costs for grid reliability projects using a flow-based method known as solution-based distribution-factor analysis (DFAX). This method distributes costs based on utility usage over time and models electricity flow at peak load, assigning costs proportionally among utilities in various PJM grid zones.
The DFAX method also assigns costs to entities withdrawing electricity from the PJM grid, including merchant transmission facilities like Linden and Hudson, based on their firm withdrawal rights. It assumes these facilities will withdraw their full entitled amount during peak load times and similarly allocates costs to ConEd based on its wheeling agreement with PSE&G, projecting a withdrawal of 900 megawatts during peak load.
FERC approved PJM's cost allocation method in 2013, which was utilized for two specific projects: the Bergen project and the Sewaren project. The Bergen project, initiated in 2013, involved 26 improvements to the transmission corridor between PSE&G's Bergen and Linden stations, aimed at mitigating short circuit risks rather than increasing grid capacity. PJM directed PSE&G to expand the corridor into a double-circuit line to handle higher voltages, which also provided protection against thermal overloads. Concurrently, the Sewaren project focused on upgrading aging infrastructure at PSE&G's Sewaren substation to enhance its resilience against storms, particularly following Hurricane Sandy; like Bergen, it was a reliability project and not intended to boost overall transmission capacity.
In 2014, PJM allocated costs for the Bergen and Sewaren projects in two section 205 filings, totaling $1.2 billion for Bergen ($763 million allocated) and $125 million for Sewaren. The initial cost assignments primarily charged ConEd with $629 million for Bergen, while costs for Sewaren were split between ConEd and Linden. Subsequent filings in 2015 and 2016 adjusted the cost allocations based on project design and grid-use data, with high-voltage costs allocated pro rata rather than through DFAX, which was not contested in the current petitions.
Starting in 2015, PJM altered its cost allocation method for infrastructure projects like Sewaren, ceasing DFAX assignments. This prompted protests from ConEd, Linden, Hudson, and NYPA, who claimed the DFAX method distorted cost assignments, unfairly minimizing PSE&G's financial responsibility. They argued that the rate filings violated the cost causation principle by disproportionately assigning costs to parties other than PSE&G. FERC ultimately supported PJM's filings, reaffirming DFAX as a just and reasonable cost allocation method and stating that PJM properly applied it in the contested cases.
The reasonableness of the Solution-Based DFAX methodology is not subject to scrutiny under section 205 proceedings, as established by FERC, which opted not to evaluate the modeling conventions of the DFAX method. FERC acknowledged concerns from protestors that the DFAX method systematically favors larger utilities, such as PSE&G, over smaller ones. Specific objections included the exemption of utilities with minimal flows from DFAX costs, the "netting" of positive and negative electric flows, and the reliance on peak load conditions for cost assignment. Following PJM’s 2014 filings, ConEd and Linden filed section 206 complaints, challenging the foundational assumptions of the DFAX method and its application to the Bergen and Sewaren projects.
The projects in question were categorized as "non-flow-based," addressing issues not linked to excessive electricity flows and benefiting different utilities than those utilizing the upgraded facilities. Consequently, the DFAX method was deemed inadequate in aligning project costs with their beneficiaries, conflicting with the Federal Power Act's requirements. FERC addressed ConEd's complaint, emphasizing Order No. 1,000’s aim to create a uniform cost allocation approach for infrastructure projects, which PJM's Tariff did not allow to vary by project type. FERC found the DFAX method to appropriately identify beneficiaries for non-flow-based projects, thereby rejecting ConEd's arguments.
In subsequent decisions, FERC reaffirmed its stance on the DFAX method, upheld its modeling conventions as just and reasonable, and rejected Linden's complaint. Additionally, FERC validated the DFAX method in a related proceeding concerning the Artificial Island project. After FERC denied ConEd's rehearing request, ConEd informed PSE&G of its intent to let their wheeling agreement expire. PJM then proposed a new cost allocation plan that shifted the financial burden of Bergen’s DFAX costs from ConEd to Hudson, Linden, and PSE&G, which faced objections from the New Jersey Board of Public Utilities and other entities involved.
Linden filed a section 206 complaint regarding cost reallocation, which FERC initially accepted in PJM's 2017 filing but did not address for three years. During this period, Hudson and Linden sought to avoid cost liability for the Bergen project by requesting PJM to convert their firm withdrawal rights to non-firm, exempting them from DFAX costs. The New Jersey Board intervened, claiming this would unfairly shift costs to PSE&G, but FERC ruled there was no justification for preventing the conversion. FERC also noted it could not impose costs on ConEd due to its outside status after a wheeling agreement expired and upheld PJM’s Tariff that allocates DFAX costs only to merchant facilities with firm rights as reasonable.
In 2018, FERC reconsidered its earlier rejection of the Artificial Island project, which aimed to stabilize nuclear generators. It acknowledged that beneficiaries of certain non-flow-based projects might not be accurately identified by the DFAX method and ordered PJM to adopt a new cost allocation method for stability projects. By 2020, FERC addressed the Bergen and Sewaren projects, denying rehearing on Linden's initial complaint and affirming the DFAX method as just and reasonable. FERC also approved PJM's 2017 cost reallocation and denied Linden's subsequent complaint challenging it.
Linden's rehearing application contested FERC's orders regarding the allocation of costs for the Bergen project, asserting that the DFAX method was unjust for a non-flow-based project. Linden compared the project to the Artificial Island case, where FERC had made exceptions for stability-related projects, arguing that similar treatment should apply. However, FERC defended its decision, stating that no exception was warranted for short-circuit projects and affirmed the DFAX method as just and reasonable. As FERC denied the rehearing applications of various parties, including ConEd and NYPA, they sought judicial review of FERC's cost allocations from 2014 to 2017, having already incurred approximately $115 million in costs. The City of New York and the New York State Public Service Commission intervened for the New York entities, while a group of transmission owners supported FERC. The New Jersey Board also petitioned for review concerning cost allocations affecting New Jersey ratepayers. Both the New York entities and the New Jersey Board argued that FERC's orders violated the Administrative Procedure Act (APA) and the Federal Power Act. The court confirmed its jurisdiction over most of the petitions but dismissed one for being untimely. Judicial review of FERC's orders is highly deferential, focusing on whether they are arbitrary or lack proper explanation. The New York entities contended that FERC failed to justify the differential treatment of cost allocations between Bergen and Artificial Island, a point with which the court concurred.
In 2016, the Federal Energy Regulatory Commission (FERC) affirmed that the Distribution Factor Analysis (DFAX) method was suitable for cost allocation across all projects in PJM’s regional plan, including non-flow-based projects like short-circuit and stability violations. FERC maintained that DFAX effectively identifies utilities benefiting from new facilities, regardless of the specific problems driving project needs. However, by 2020, FERC altered its stance on the Artificial Island project, distinguishing it from flow-based projects due to its stability-related nature, which does not stem from excessive electricity demand. FERC concluded that while DFAX is just for flow-based projects, it is inappropriate for non-flow-based projects like Artificial Island, as the utilities benefiting from stability improvements may not be the same as those utilizing expanded capacity.
New York entities contended that FERC should have applied this reasoning to the Bergen and Sewaren projects as well, arguing that FERC failed to justify the continued use of DFAX for these projects when a different method was directed for Artificial Island. They asserted that the principle of administrative consistency requires similar cases to be treated alike, necessitating either uniform application or a clear distinction between cases if exceptions are made.
In Westar Energy, Inc. v. FERC, the New York entities objected to FERC's decisions regarding the Second Linden Complaint Order and the Cost Reallocation Order, specifically referencing their concerns about the flow-based method used for assessing benefits in non-flow-based reliability contexts, such as the short-circuit issues affecting Bergen and Sewaren. They did not raise the Artificial Island case during the rehearing of the First Linden Complaint Order, arguing instead that a flow-based method was inappropriate for these non-flow-based reliability concerns. Typically, FERC lacks jurisdiction to consider arguments not specifically raised during rehearing, but since FERC altered its position on Artificial Island after the First Linden rehearing request was made, the parties had reasonable grounds for not citing it specifically.
FERC had been evaluating the cost allocations for Artificial Island alongside those for Bergen and Sewaren for six years before changing its stance, which warranted the parties’ more general arguments about DFAX being unsuitable for non-flow-based projects. Consequently, the court held it had jurisdiction to review FERC's treatment of Bergen and Sewaren in comparison to Artificial Island. FERC justified its differentiation by stating it had not made a general ruling on all non-flow-based constraints but had allowed for a specific exception for stability-related projects, which it deemed “analytically unique.” FERC explained that the modifications made to the Bergen-Linden corridor were akin to flow-based project planning, thereby justifying the use of DFAX for cost assignment.
However, while FERC asserted that stability projects are uniquely different from other flow-based issues, it did not clarify why short-circuit projects also warranted such distinct treatment. The testimony referenced acknowledged both short-circuit and stability issues as poor fits for the DFAX method, indicating that both are not caused by flow overloads. Therefore, FERC's rationale for treating the two sets of projects differently lacked sufficient explanation, particularly in justifying why stability should be considered analytically unique compared to short-circuit issues.
FERC determined that the DFAX method should be used to assign costs for the Bergen project, likening it to a thermal overload project, despite lacking adequate explanation for this similarity. The primary issue with Bergen was related to short-circuit problems, not thermal overloads. Both Bergen and Artificial Island projects expanded grid capacity, benefiting not only the utilities utilizing the electricity but also other entities. After Bergen’s completion, PSE&G gained facilities resistant to short circuits, and other grid users received protection against short-circuit effects. In contrast, FERC previously recognized in the Artificial Island order that costs should not be allocated via DFAX to utilities relying on newly stabilized generators, but rather to those directly benefiting from the stabilization. FERC's differing treatment of Bergen and Sewaren compared to Artificial Island lacked justification, as both projects provided non-flow-based benefits. The Commission was required to explain why costs should be assigned differently under similar circumstances, adhering to legal principles against treating similarly situated parties unequally. FERC's failure to provide sufficient rationale is noted, but it may offer a clearer distinction on remand. Additionally, the New York entities contest specific aspects of the DFAX method, including the de minimis threshold, netting, and peak-load assumption. The DFAX method allocates transmission facility costs based on each zone’s usage, calculated from peak demand models to determine a "distribution factor" representing each zone's proportionate use.
PJM calculates cost allocations for facility usage based on arithmetic operations involving distribution factors and total loads from each zone. The process begins by multiplying a zone's distribution factor by its total load to determine the zone's usage of the facility. This usage is then divided by the total usage across all zones to obtain a quotient. This quotient is subsequently multiplied by the facility's total cost to allocate expenses to the respective zone. A significant aspect of this allocation process is the de minimis threshold, which stipulates that zones with a distribution factor below 1% are exempt from cost assignments due to negligible benefits derived from the facility.
The de minimis threshold operates as a "too-big-to-pay" rule, as it exempts larger zones from costs based solely on their size rather than their actual usage or benefits received from the facility. This practice violates the cost causation principle, which requires a fair comparison between costs imposed and benefits received. It also leads to undue discrimination against smaller zones that are left with higher cost burdens when larger zones are exempt. This discrepancy is illustrated through examples of varying peak loads among zones, such as PSE&G and Hudson, where PSE&G could avoid costs despite deriving significantly greater benefits than Hudson. The allocation method employed by PJM demonstrates unfairness, as seen in specific project allocations, where a disproportionate share of benefits was assigned to larger entities while smaller ones were left with higher costs.
PSE&G was excluded from cost allocation due to the de minimis threshold, resulting in ConEd and Hudson being assigned almost all upgrade costs (99.98%). Following ConEd's withdrawal from its wheeling agreement, PSE&G received 72.7% of benefits from a subproject, while Hudson received only 6%. Despite this disparity, Hudson bore 99.98% of the costs. Similar instances show PSE&G receiving significant benefits while ConEd and Hudson were allocated all or most of the costs, violating FERC's principle that no party should bear disproportionate costs for diffuse benefits. FERC's justification for the de minimis threshold, which supposedly identifies entities with minimal use relative to their load, is deemed unpersuasive, as it does not accurately reflect the principle of cost causation. FERC's claims about the threshold's relationship to zone size and its annual adjustments are also criticized for inconsistency and lack of relevance to the fairness of cost allocations. Additionally, PJM's method of calculating total flow from delivery points, where flows can be positive or negative, is outlined, with an example illustrating how net flows are determined.
A zone with one delivery point receiving +100 megawatts and another receiving −50 megawatts results in a net flow of +50 megawatts. The New York entities challenge this netting approach, arguing it violates the cost causation principle and discriminates against them. They assert that transmission facilities provide equal benefits regardless of flow direction, but netting leads to unequal cost allocations. For example, a zone receiving +150 megawatts pays significantly more than another zone with offsetting flows (+100 and −50 megawatts), which benefits large zones like PSE&G that can net flows due to multiple delivery points.
FERC approved netting, stating it generates additional capacity for transmission lines by allowing counterflows to reduce net flows, making more capacity available. FERC determined that zones with only one direction of flow should incur higher costs due to their greater capacity usage. While this reasoning is not the only possible interpretation, it is deemed reasonable and thus upheld.
The New York entities raised two additional objections: inconsistency with PJM's prior cost allocation rationale and discrimination between netting within versus across zones. However, these objections were not presented during their applications for rehearing, limiting jurisdiction for consideration. Subsequently, another merchant transmission facility owner filed a complaint regarding netting and de minimis provisions, prompting FERC to reassess their reasonableness. The New York entities requested a remand for FERC to reconsider netting based on this complaint, but agency evaluations are based on the circumstances at the time of the decision, and prior decisions do not necessitate changes in subsequent cases.
In MacLeod v. ICC, the court addressed the appropriateness of a remand concerning FERC's decision on netting practices. It noted that while agencies may be remanded if the underlying rule changes, FERC did not reject netting but instead ordered further examination, rendering a remand unnecessary. The court upheld FERC's rationale for approving netting without prejudging the related Neptune case.
The excerpt also discussed PJM's peak-load assumption in electricity modeling, where PJM presumes all zones are at peak demand for reliability. Merchant transmission facilities argued that this assumption overstated their usage, as they typically do not reroute electricity at peak demand times. Although FERC acknowledged this, it deemed the assumption reasonable for ensuring system reliability.
The New York entities challenged FERC’s interpretation of the PJM Tariff, specifically the application of the DFAX method and its alignment with the cost causation principle. They claimed that the Tariff mandates deviation from the DFAX analysis if it yields "objectively unreasonable" results. FERC disagreed, interpreting the Tariff as allowing for discretion only under certain circumstances and emphasizing the requirement for ex ante cost assignments, as specified in Order No. 1,000.
FERC asserts that the DFAX analysis results are deemed "objectively unreasonable" only if they deviate from the expected normal flow results that an engineer would anticipate. PJM engineers were able to accurately determine flows for the Bergen and Sewaren projects, indicating the DFAX analysis results were not objectively unreasonable. Furthermore, PJM has limited discretion to utilize a substitute proxy for the Required Transmission Enhancement in the DFAX analysis, rather than a broad authority to alter cost responsibility assignments. FERC's tariff interpretations are assessed through a "Chevron-like analysis," enforcing clear tariff language while deferring to reasonable interpretations of ambiguous terms. Determining unreasonableness by PJM must be objective, relying on engineering judgment, which pertains to technical assessments rather than cost causation principles that involve fairness and balancing competing goals. Even if PJM identifies objectively unreasonable results, it cannot abandon the DFAX method; it may only replace modeled flows with those from a comparable facility, rerunning the analysis without fully discarding the method. The tariff specifies the use of proxies explicitly, and any proxy utilization requires PJM to document recommendations for potential changes to the DFAX analysis. FERC's interpretation aligns with the ex ante cost allocation principle from Order No. 1,000, which necessitates PJM to apply existing cost allocation rules unless the DFAX analysis is unfeasible. The New York entities' interpretation would improperly grant PJM broader discretion in applying cost allocation rules based on subjective fairness assessments.
The New Jersey Board is seeking review of FERC's decision regarding the reallocation of costs for the Bergen project to PSE&G after New York entities relinquished their rights to withdraw electricity from the PJM grid. The Board presents three main arguments:
1. **ConEd’s Cost Responsibility**: The Board contends FERC erred by concluding that ConEd's obligation to pay for the project ceased when its transmission service agreements ended. The Board argues that the project was built for ConEd’s benefit and that ConEd had previously agreed to cover its share of the costs.
2. **Linden’s Cost Allocation Evasion**: The Board asserts that Linden circumvented cost allocations by combining non-firm transmission withdrawal rights with firm point-to-point service, allowing Linden to continue benefiting from the project without bearing its associated costs.
3. **Unjust Rate Relief**: The Board claims FERC failed to adequately assess whether relieving New York entities from cost responsibilities led to unjust and unreasonable rates.
Further, the Board argues that ConEd should have continued to pay project costs despite the termination of its service agreements, referencing a 2009 settlement that defined the obligations under the wheeling agreement. While FERC approved this settlement, it noted that ConEd would bear no liability for costs after the service term ended on April 30, 2017, and that the PJM Tariff dictated cost responsibilities based on this settlement. FERC also pointed out that the Joint Operating Agreement between PJM and NYISO prohibits cost compensation for interregional projects unless both regions jointly decide to undertake such projects. Hence, the Bergen project was solely planned by PJM, and the cost allocation rules apply even when mutual benefits arise from the interconnection of the two systems. The New Jersey Board, having participated in and signed the settlement agreement, could not later contest its provisions.
FERC determined that under the Joint Operating Agreement (JOA), ConEd is not required to pay project costs after the termination of its service agreements, as PJM and NYISO are prohibited from charging each other for mutual benefits. The New Jersey Board argues that the focus should be on whether the cost allocation is unjust and unreasonable, regardless of compliance with prior agreements. It highlights that previously approved cost allocation methods may still be unjust when applied to specific rate decisions. FERC's Order No. 1,000 emphasizes that costs should be allocated based on benefits, and Principle 4 mandates that cost allocation for transmission facilities must be confined to the planning region unless otherwise agreed by outside entities. After ConEd's agreements lapsed, it ceased to assume costs, and the Bergen project was solely managed by PJM. The New Jersey Board contends that this creates tension between Principle 4 and the cost causation principle, allowing some beneficiaries to evade costs. However, it is concluded that Principle 4 is a valid restriction on the cost causation principle. In past cases, courts have upheld that FERC can approve rates that do not strictly align with cost causation due to broader geographic policy considerations and the practicalities of cost allocation. FERC's formulation of Principle 4 considers monitoring costs, efficiency, and the feasibility of involuntary interregional cost allocation. Thus, FERC's reliance on Order No. 1,000 and Principle 4 in releasing ConEd from future costs for the Bergen project was deemed just and reasonable.
The New Jersey Board argues that FERC's decision to exempt Linden from cost allocations for the Corridor Project was arbitrary, as it did not address the relationship between firm Point-to-Point service and non-firm Withdrawal Rights. The Board points out that Linden, while giving up its firm withdrawal rights, negotiated for firm Point-to-Point transmission service, thus benefitting from the Bergen project without incurring costs. FERC contends that this argument cannot be considered since it was not sufficiently raised in the Board’s rehearing requests, citing 16 U.S.C. 825l(b), which requires objections to be presented to the Commission first. The Board's requests primarily challenged FERC's cost allocation handling without specifically addressing the argument regarding Linden’s service benefits. Consequently, the court lacks jurisdiction to review the Board’s cost allocation challenge.
Additionally, the Board claims FERC's analysis was "siloed" and failed to consider the overall impact of its orders on New Jersey ratepayers, asserting that the project’s costs were disproportionately borne by them. However, FERC acknowledged the necessity of the Bergen project in New Jersey, regardless of flows to New York, and concluded that the costs should be allocated solely within PJM since there was no mutual commitment for cost sharing with NYISO. FERC maintained that increased rates for New Jersey ratepayers did not inherently render those rates unjust or unreasonable.
FERC evaluated the overall cost allocation for New York entities and concluded it was not unjust or unreasonable, considering who incurred costs versus who benefited. The petitions for review in New Jersey Board v. FERC were denied, while those in ConEd v. FERC were partially granted and partially denied. FERC inadequately distinguished its decisions regarding the Linden projects from its earlier ruling on the Artificial Island case. Additionally, FERC's maintenance of the de minimis threshold was deemed unlawful. Consequently, the denials of Linden's complaints were vacated and remanded for further proceedings on both the cost allocation and de minimis issues. Similarly, ConEd's complaint was vacated and remanded solely on the de minimis matter. Most section 205 orders approving PJM’s cost allocations were upheld, as the New York entities did not challenge FERC's procedural rulings, which limited FERC's review to the correctness of PJM's methodology application rather than its legality. However, the Cost Reallocation Order was vacated, allowing FERC to reconsider the procedural aspects of the New York entities’ challenges. FERC's argument regarding jurisdiction over certain petitions was acknowledged, but the court indicated it has jurisdiction over related cases and could address them on the merits.
