This report reviews the federal regulatory developments that occurred in the natural gas industry during the period of February 2022 through August 2022. The report focuses on key issues of interest and provides an overview of the major federal orders issued and initiatives commenced during that period, including rulemaking initiatives, by the Federal Energy Regulatory Commission (“FERC” or “Commission”). Pertinent appellate decisions are highlighted as well.
For the second time, the Fourth Circuit vacated and remanded a U.S. Forest Service (Forest Service) and Bureau of Land Management (BLM) decision to authorize Mountain Valley Pipeline (MVP) to cross three and a half miles of the Jefferson National Forest in Virginia and West Virginia based on a failure to comply with National Environmental Policy Act and National Forest Management Act and Mineral Leasing Act regulations. After the initial remand, the Forest Service and BLM prepared a supplemental Environmental Impact Statement (supplemental EIS) which sought to address the pipeline’s sedimentation impacts utilizing two hydrological analyses provided by MVP. However, the Court found that these neither of these analyses nor the supplemental EIS considered water monitoring data from the United States Geological Survey (USGS) monitoring stations fifteen miles outside the Jefferson National Forest where such data showed that construction of this pipeline had significantly increased water turbidity, and that no reason was supplied to show that factors that could affect streams inside the forest were different from those outside the forest where the USGS measurements took place. The Court also found that the Forest Service and BLM improperly authorized the use of conventional bore method to cross four streams in the Jefferson National Forest without extensively considering the impacts of this method. The Court noted that the supplemental EIS did include information on this method, but, because MVP originally planned to use open cutting for stream crossings, conventional bore was not extensively considered. Subsequently, MVP requested authorization from FERC to switch to conventional bore for crossings outside of the Jefferson National Forest, which FERC is treating as an amendment to the certificate; the Court concluded that the Forest Service and BLM would surely benefit from FERC’s environmental analysis of the proposed amendment for its analysis of crossings within the Jefferson National Forest. The Court also found that the Forest Service improperly amended its forest plan for the Jefferson National Forest to accommodate the MVP pipeline because it could not determine that the plan would meet the regulatory requirement to “maintain or restore” the ecosystem given the Forest Service’s failure to adequately analyze sedimentation and the use of conventional bore for crossings. As to Forest Service’s reliance on the notion that the pipeline will affect only a minimal fraction of the entire forest, the Court found that this approach would allow circumvention of the regulations by simply passing project-specific amendments to the plan on an ad hoc basis.
On March 11, 2022, the D.C. Circuit remanded, without vacatur, Commission authorization of the Tennessee Gas Pipeline “Upgrade Project,” which involves the addition of 2.1 miles of new pipeline and a new compressor station in Agawam, Massachusetts. The Court rejected all of the Plaintiff’s environmental challenges to the certification of the project, except for the “indirect-effects” argument with respect to downstream gas consumption and resulting greenhouse gas (GHG) emissions. The Court noted that in Sierra Club v. FERC, the Court held that downstream GHG emissions were “reasonably foreseeable” indirect effects of a pipeline project designed to transport gas to certain specific Florida power plants, but in Birckhead v. FERC, this Court rejected a similar claim when the Commission could establish only that the gas was headed somewhere in the Southeast. The Court declared that foreseeability depends on information about the ‘destination and end use of the gas in question.’ The Court found that the record in this case more closely resembles Sabal Trail than Birckhead because the Commission has evidence that the Upgrade Project would add 72,000 Dth/day of capacity to Tennessee’s system, of which 40,000 Dth/day is under contract to Columbia Gas of Massachusetts (local distribution company) which would use that capacity to serve existing customers in the Greater Springfield area. The Court found that regardless of whether local distribution customer demand is more, or less, elastic and predictable than power plant demand, or whether the gas transported may displace existing gas supplies, the Commission is not excused from making emissions estimates in the first place. Hence, the Court remands to the Commission to perform a supplemental environmental assessment to either quantify and consider downstream carbon emissions or explain in more detail why it cannot do so. In deciding not to vacate the Commission’s certificate order, the Court found that FERC could, with further explanation, justify its decision to skip this procedural step, or, the Commission could arrive at its same finding of no significant impact of the project on the environment after accounting for foreseeable GHG emissions. As to the disruptive impact of vacatur, the Court found that the impact of vacatur would be significant because the Upgrade Project is now either mid-construction or operational.
Plaintiffs removed a suit filed in state court to federal district court alleging that their claim of grossly negligent damage to their property from the pipeline’s construction, maintenance, operations, and repairs in proximity to their property implicates federal questions under the “substantial federal questions doctrine.” In remanding the case back to the state court, the District Court found that there was no significant federal issues arising under the state-law claims that require settlement in a federal forum. Plaintiffs claimed that, because FERC orders under the NGA supply the standard under which Defendant’s conduct must be measured, FERC’s exclusive control over pipeline construction and operation would be supplanted if state law is applied to the duty of care in this negligence action instead of federal law. The District Court found that the NGA does not create a relevant cause of action and the Plaintiffs do not allege a violation of the NGA, much less a dispute over the interpretation of federal law. In concluding that any alleged federal issue was not “substantial,” the District Court noted that there was no issue of whether a federal agency complied with a statute or regulation, and the alleged federal issue of whether a pipeline complied with or exceeded the boundaries of its FERC certificate involves the application of federal regulations to establish the standard of care in a state-law based negligence case, which is necessarily specific to this case, and would not establish precedent in future cases; the mere need to apply federal law does not confer federal-question jurisdiction.
On June 28, 2022, the D.C. Circuit held that the Commission’s approved rate of return on a pipeline expansion project was reasonable and that the Commission’s Environmental Impact Statement (EIS) was adequate. Mountain Valley, LLC (Mountain Valley) proposed to build a 75-mile extension of its mainline (Southgate Project). The mainline itself is a greenfield project that commenced construction in 2018, that is only 92% constructed because of adverse court rulings on required permits. For the Southgate Project, the Commission approved an initial rate based on a rate of return on equity of 14% (typical of new greenfield pipeline companies), rather than the typical 10.55% used for expansions of existing pipeline systems because, absent cash flow from existing operations and a proven track record, Southgate’s funding outlook more closely resembled a new pipeline. Petitioners challenging the 14% rate of return relied heavily on Commissioner Glick’s dissent on the certificate order which argued that, because Mountain Valley was already granted a 14% return on its mainline as a new market entrant, it should not receive such a favorable return on the second time around as it is an existing company with binding service contracts with shippers which provide a level of revenue security most greenfield projects do not enjoy. The Court found reasonable the Commission’s “functional” analysis that Mountain Valley does not have a track record or revenue stream of an existing pipeline such that Southgate should be treated as a new market entrant even if it might “formally” be an extension of a partially constructed pipeline. The Court noted that the Commission cited another project where the Commission granted a high return for an expansion project linking up to a previously authorized, but not yet operational greenfield pipeline because of higher risk at the outset, while petitioners only cited expansion proposals for pipelines that had been operation for a year or more.
The Court also found the Commission’s EIS discussion of mitigation measures for sedimentation and erosion to be adequate because it discussed potential mitigation measures for erosion and runoff in detail and specified measure Mountain Valley must take and distinguished these measures from those that failed Mountain Valley in the past. The Court noted that National Environmental Policy Act (NEPA) regulations do not mandate that the Commission formulate a specific mitigation plan, only that it discusses mitigation in sufficient detail to ensure that environmental consequences have been fairly evaluated. As to petitioner’s claim that the Commission failed to consider the cumulative impacts of the Southgate Project and the construction of Mountain Valley’s original mainline, by purposefully restricting the temporal and geographic are for its analysis so as to avoid overlap with the mainline project with respect to turbidity plumes in streams that are crossed by the project, the Court declared that the selection of the relevant area of analysis requires a high level of technical expertise and is properly left to the informed discretion of the responsible agency. The Court concluded that the Commission fulfilled the NEPA requirement of a “hard look” because the EIS contained sufficient discussion of relevant issues and is well considered. The Court found that the Commission properly defined the geographic scope of its analysis, identified in-stream activities likely to increase turbidity, and identified other actions likely to impact the same area (with particular focus on the mainline project) and specified that the projects would not share overlapping workspace or be constructed at the same time. The Court noted that it affords the Commission “an extreme degree of deference” when considering evaluation of scientific data within its technical expertise, and that the petitioners did not marshal compelling evidence to counter the Commission’s cumulative impact analysis.
On July 8, 2022, the D.C. Circuit sustained a Commission order on remand finding that it properly granted NEXUS Gas Transmission, LLC (NEXUS) a certificate to construct and operate a pipeline from Ohio to Michigan. In a prior holding, the Court granted the City of Oberlin’s petition for review, finding that FERC did not adequately justify its reliance on agreements for the transportation of gas ultimately bound for export to Canada as evidence of need for the pipeline. On remand, the Commission explained why precedent agreements to serve foreign customers can be considered in determining public convenience and necessity, and why it would have certificated the project even if there were no precedent agreements with the Canadian companies. The Court agreed with the Commission.
The Court found that NEXUS has six precedent agreements to transport gas from Pennsylvania to Ohio, in addition to the precedent agreements with two Canadian companies and the gas bound for export is commingled with gas bound for domestic use and that all of the gas is interstate gas subject to Natural Gas Act (NGA) section 7 jurisdiction, and that FERC could consider the export precedent agreements because an assessment of public convenience and necessity requires consideration of all factors that bear on public interest. The Court found that FERC did not conflate its section 7 finding of public need with the finding under section 3(c) of the NGA that gas exported to countries with which the US has a free trade agreement “shall be deemed to be consistent with the public interest.” The Court agreed with the Commission that crediting the export precedent agreements is consistent with Congressional intent and disagreed with the City of Oberlin that this is tantamount to deciding that public interest under section 3 was interchangeable with a section 7 finding of public convenience and necessity which would contravene both Oberlin I and the NGA’s granting of eminent domain powers under section 7 but not under section 3. Far from conflating the two standards, the Court accepted the Commission’s explanation that it only gives precedent agreements for export the same weight given other precedent agreements and all such agreements are simply one input into an assessment of public convenience and necessity and is not dispositive—a certificate can be denied despite having export precedent agreements if the overall benefits of the project fail to outweigh overall costs. The Court agreed with the Commission’s finding of “myriad domestic benefits,” such as providing additional capacity to transport gas out of the Appalachian Basin which would also support production and sales of domestic gas, and the delivery of gas to the Dawn Hub in Canada which could, in the future, increase availability of gas transported through Canada and imported back into New York and New England.
The Court rejected Oberlin’s claim that crediting export precedent agreement runs afoul of the Takings Clause because a pipeline shipping gas for export does not serve a public use. The Court found that a finding of public convenience and necessity is a finding that the pipeline serves a public purpose consistent with the Takings Clause and the Commission is not putting itself out of reach of the Fifth Amendment because Congress granted the Commission this authority and because the Commission’s determination is subject to judicial review.
The Court also accepted the Commission’s finding that, the domestic benefits alone, when balanced against the small adverse impacts of the project, justified the construction of the pipeline. The Commission found that 42% of the capacity would serve domestic uses and that existing pipelines did not have enough capacity to ship this amount of gas. The Court agreed with the Commission’s rejection of the alternative of building a smaller pipeline sized to only carry 42% of the project’s capacity because the benefits of avoiding future construction outweigh the small reduction in burden of landowners that a smaller pipeline would yield. The Court found the Commission’s alternative analysis of considering the pipeline without the export precedent agreements to be reasonable; the Court found that because there is no floor to the subscription rate needed, the “flexible” inquiry into a wide variety of evidence of public benefits to balance against adverse impacts is reasonable.
On July 19, 2022, the Fifth Circuit vacated Commission orders granting declaratory petitions purporting to bind Gulfport to continue to perform under its gas transportation contracts even if Gulfport rejects the contracts during bankruptcy. This proceeding concerns how two legal regimes—the Bankruptcy Code and the Natural Gas Act (NGA)—interact. The Bankruptcy Code permits a bankrupt debtor to reject executory contracts, while the Commission has the power to decide whether a party may change or cancel filed-rate contracts which the Commission regulates. Under the Bankruptcy Code, a debtor, subject to the court’s approval, may assume (agree to perform) or reject (breach) any contract. A breach does not erase that contract; it entitles the counterparty to seek damages for the debtor’s non-performance. But, because most debtors are broke and cannot pay the full damages claim, in a typical bankruptcy, the counterparty receives only cents on the dollar while the debtor retains the benefits of having ceased performance. Under the NGA, natural gas companies file the rates they charge with the Commission and any changes thereto must also be approved by the Commission. In a prior Fifth Circuit holding, the Court rejected the Commission’s attempt to block a power company from rejecting filed-rate contracts in bankruptcy by claiming that the company cannot "modify” or “abrogate” rates without Commission approval; the Court explained that rejection does not change or cancel a contract, rather, it breaches the contract, giving the debtor’s counterparty a damages claim for the value of continued performance (the contract itself does not change, nor the filed rate), and therefore, the power company did not need the Commission’s consent to reject its contracts. Mirant notwithstanding, the Commission granted the interstate pipeline’s petition for declaratory order finding that the rejection of the contract in bankruptcy court alters the essential terms and conditions of the contract, and therefore, Commission approval is needed before rejection. The Commission also found that the bankruptcy court could not confirm any reorganization plan that rejected a transportation service agreement unless and until the Commission agrees, or the plan is made contingent on Commission approval.
The Court held that the Bankruptcy Code, Supreme Court precedent and the caselaw of every federal circuit has determined that rejecting a contract does not change or cancel the obligations under the contract, rather, rejecting breaches the contract giving the pipeline a damage claim valued at the filed rate; that rate does not change, and though Gulfport may be unlikely to pay that claim in full, that does not change the contract’s terms or the filed rate itself. The Court concluded that the Commission cannot prevent rejection, it cannot bind a debtor to continue paying the filed rate after rejection, and it cannot usurp the bankruptcy court’s power to decide rejection motions.
On August 2, 2022, the D.C. Circuit denied a petition for review of a certificate issued by the Commission for the construction and operation of the Adelphia Gateway Project (Project) which consists of the acquisition of existing pipeline in Pennsylvania and Delaware and the construction of two short lateral pipeline segments and a new compressor station. Petitioners challenged: 1) the Commission’s finding of market need for the Project; 2) the sufficiency of the Commission’s environmental review under the National Environmental Policy Act (NEPA); and 3) the constitutionality of the Commission’s purported preemption of state and local authorities’ ability to protect public health.
For the NEPA challenge, the Court agreed with the Commission that it did not have to consider the upstream impacts (the impacts of drilling and production of gas that would feed the pipeline) because such impacts are not “reasonably foreseeable.” The Court accepted the Commission’s claim that, because the Project would receive gas from other interstate pipelines, there is no information that would help predict the number and location of any additional wells that would be drilled as a result as a result of any production demand associated with the project nor did petitioners point to any evidence that the shippers would not extract and produce the gas if the project did not go forward. As to the downstream impacts (primarily the greenhouse gas (GHG) emission from the burning of gas after delivery), the Court agreed with the Commission that GHG impacts were not reasonably foreseeable because the Commission was unable to identify the end users of the gas--the gas would be delivered for further transportation on the interstate grid to unknown destinations and unknown end users. Citing Birckhead v. FERCthe Court rejected a categorical determination that emissions from downstream combustion is always a reasonably foreseeable indirect effect of a pipeline project, and also rejected use of industry statistics to determine average quantities burn instead of a “full burn” assumption, because that still applies a categorical determination that assumes that averages can be applied in any and every case. As to petitioner’s claim that the Commission should have taken the extra step of asking the shippers about the destination and end use of the gas, the Court found that the petitioners did not raise this issue on rehearing in a manner that put the Commission on notice of the position the petitioners now take, and therefore, the Court lacks jurisdiction to consider this claim. As to petitioner’s claim that one lateral would serve a specific powerplant which means that the Commission should have calculated emissions associated with that lateral, the Court found that, in this case, the lateral may serve certain specific powerplants, but because there are no contracts for the capacity, there is no way to ascribe any particular capacity to this end user, and therefore, no way to estimate emissions (in Sabal Trails precedent agreements provided data as to how much gas would be transported). The Court found that past precedent supports the Commission’s determination that there is no scientifically accepted methodology to correlate specific amounts of GHG emissions to discrete changes in the environment and supports its rejection of the Social Cost of Carbon methodology for assessing climate change impacts. As to the claim that 40 C.F.R. §1502.21(c)(4) provides for the use of theoretical approaches or research methods generally accepted by the scientific community when information cannot otherwise be obtained, and that the Social Cost of Carbon is one such accepted methodology, the Court found that the petitioners did not previously advance the argument that this provision, which applies to the more rigorous Environmental Impact Statement analysis also applies to the less demanding Environmental Assessment context, and therefore the Court lacks jurisdiction to consider this contention.
As to the contention--that under the Fifth, Ninth, and Tenth Amendments to the U.S. Constitution, the Commission interpreted the NGA in a manner that unconstitutionally preempted legitimate state and local action that is necessary and appropriate to protect public health, safety, and welfare—the Court found that petitioners forfeited this claim because they are required to exhaust even constitutional claims before the agency even if the agency does not have the authority to rule on them in the first instance during the agency’s proceeding.
On the Commission’s market need determination, the Court found that the Commission’s analysis was not flawed as petitioners alleged. The 76% of capacity committed under precedent agreements is, sometimes, sufficient evidence of market need, and that petitioner’s evidence of a lack of demand does not rebut the existing precedent agreements; the Commission is not ordinarily required to assess benefits by looking beyond market need reflected by existing contracts with shippers. In any event, the Court found that the Commission addressed the evidence petitioners pointed to as demonstrating sufficient existing pipeline capacity and reasonably concluded that concrete obligations to purchase were better evidence of market need than the more speculative reports regarding overbuilding and future demand relied on by petitioners.
On February 18,2022, the Commission issued its “Updated Policy Statement on Certification of New Interstate Natural Gas Facilities (Updated Policy Statement) which describes how the Commission will evaluate all factors bearing on the public interest in determining whether a new gas project is required by the public convenience under the Natural Gas Act (NGA). This updates the Commission’s 1999 Policy Statement. The Updated Policy Statement will not be applied retroactively to cases where a certificate has already been issued, but it will apply to any currently pending applications for new certificate. Concurrent with the issuance of the Updated Policy Statement, the Commission issued a new policy statement on how it will assess project impacts on climate change in its National Environmental Policy Act (NEPA) and NGA review.
Under the 1999 Policy Statement, in practice, the Commission relied almost exclusively on binding precedent agreements with project shippers to establish project need. Under the Updated Policy Statement, the Commission finds that it cannot assess need without looking beyond precedent agreements and affirms its commitment to consider all relevant factors bearing on the need for a project; although precedent agreements remain important evidence of need, and applicants are expected to provide such agreements, such agreements may not be sufficient. The Commission will consider relevant circumstances surround such agreements (e.g., whether they were entered into before or after an open season, number of bidders in the open season, whether agreements were in response to local distribution company or electric generator requests for proposals (RFP), and if so, the details of the RFP process) and other evidence of need. Applicants are “encouraged” to provide specific information detailing how the gas will be ultimately used and the expected utilization rate, and to the extent the applicant does not have information on end use, the applicant is encouraged to obtain information from prospective shippers. For market-driven projects and projects that are not designed to serve specific customers but to add supplies to the market to respond to competition or support reliability, the Commission requested market studies and regional projections of both supply and market growth. The Updated Policy Statement also declared that precedent agreements with affiliates will generally be insufficient to demonstrate need, and how much additional evidence will be need will be a case-by-case determination.
Four major categories of adverse effects will be considered: 1) the interests of the applicant’s existing customers; 2) the interests of existing pipelines and their captive customers; 3) environmental interests; and 4) the interests of landowners and surrounding communities, including environmental justice communities. For the first category, the Commission maintained its 1999 Policy Statement requirement that the project be financially viable without subsidies from existing customers. For the second category, the Commission maintained its long-standing position that it has an obligation to ensure fair competition, but it is not the role of the Commission to protect existing pipelines from the effects of competition. However, the Updated Policy Statement recognizes that it is not just unfair competition that may harm the captive customers of other pipelines, and where a project is designed to substantially serve demand already being met on existing pipelines, overbuilding is something that the Commission must consider. For environmental impacts, the Updated Policy Statement declared that the Commission will balance all impacts, including economic and environmental impacts, together with public interest determinations under the NGA. The Commission expects applicants to structure their projects to avoid, or minimize, impacts and to propose measures for mitigating impacts. The Commission also claimed that the NGA grants the Commission broad authority to attach reasonable terms and conditions to certificates and should it deem proposed mitigation to be inadequate, it may condition the certificate to require additional mitigation or deny the application where adverse impacts outweigh benefits of the project and cannot be mitigated or minimized. When making a public interest determination, the Commission intends to fully consider climate impacts, in addition to other environmental impacts. The Updated Policy Statement declared that the Commission intends its analysis of impacts on landowners to be more expansive. The Commission stated that given the serious impacts associated with the use of eminent domain, it expects applicants to take all appropriate steps to minimize the future need to use eminent domain—engaging with stakeholders during planning phase of the project, taking seriously the obligation to attempt to negotiate easements respectfully and in good faith—and the Commission will examine these steps in assessing public convenience and necessity. The Updated Policy Statement stated that the Commission recognizes that demographic considerations such as disability, age, household income, pre-existing health conditions, and level of education may be appropriate to include in an environmental justice community impacts analysis. Also, the Commission stated that cumulative impacts are particularly important when conducting an environmental justice analysis because considering incremental impacts of a project in isolation will, almost by definition, fail to consider the project’s impact on a community that already experiences elevated levels of pollution or other adverse impacts. Hence, pre-existing conditions and how the project exacerbates such conditions, is an important part of the analysis. The Commission will also consider measures to eliminate or mitigate adverse impacts on environmental justice communities, and such measures will require close consultation between the project developer, the communities in question, and the Commission.
Commissioner Danly dissented, claiming that the Updated Policy Statement, in combination with the Interim Greenhouse Gas Policy Statement have profound implications for the ability of gas companies to secure capital and on the cost that a pipeline and its customers will bear as a result of the potentially unmeasurable mitigation that the majority expects each company to propose when filing its application and the possibility of further mitigation added unilaterally by the Commission. Commissioner Danly claimed that courts have determined that the phrase “public interest” in a statute is not a broad license to promote the general welfare, but instead, takes meaning from the purpose of the legislation, which in the case of the NGA is “to encourage the orderly development of plentiful supplies of. . . natural gas at reasonable prices.”; any balancing under the public convenience and necessity standard should “take meaning” from that purpose. He noted that the NGA includes exemptions from Commission jurisdiction, such as the production, gathering and local distribution of gas, and the limits of Commission jurisdiction are not extended by NEPA because NEPA does not mandate the achievement of any particular substantive environmental results, but rather, serves only to impose procedural requirements on agencies to undertake analyses of the environmental impact of their actions. Commissioner Danly chided his colleagues for being convinced that NEPA requires that environmental impacts be mitigated before a project can be found to be required by the public convenience and necessity, when neither NEPA nor the NGA establishes such a requirement. Commissioner Danly also claimed that the Commission’s conditioning authority cannot be used to impose conditions beyond the Commission’s jurisdiction. On the issue of determining project need, Commissioner Danly stated that he disagrees with any suggestion that the Commission must look beyond precedent agreements in every circumstance—such agreements are strong evidence of need and the Commission need not look further in most circumstances. He also disagreed with the majority position that the Commission should weigh end use in determining need because this is inconsistent with the Commission’s own open access and open season policies which provide for awarding capacity to those that value the capacity the most; moreover, the Commission does not have jurisdiction over the end use of gas and has been purposefully deprived of its upstream and downstream authorities by Congress. Commissioner Danly also raised practical considerations over mitigation measures, particularly with respect to GHG emissions, because the costs may be unmeasurable (e.g., costs of renewable energy credits are market driven and change over time) and there is no guarantee that potentially extraordinary costs incurred to comply with the Commission’s public interest determination will be recovered in a pipeline’s rates. Commissioner Danly claimed that the Commission’s approach of expecting the applicant to propose mitigation measures is calculated to circumvent limits on its conditioning authority (by not saying that it is imposing such legally dubious conditions itself but by having the applicants impose their own mitigation measures); if the applicant proposes the mitigation instead of having it imposed by the Commission, it is less likely that a court would deem such condition unreasonable.
Commissioner Christie also dissented. Commissioner Christie claimed that the Commission cannot reject a certificate based solely on an estimate of GHG emission, nor, on the basis of such estimates, attach to a certificate (or coerce through deficiency letters) conditions that represent a de facto rejection by rendering the project financially or technically unfeasible, nor may the Commission impose conditions on a certificate to mitigate upstream or downstream GHG emissions arising from non-jurisdictional activity. Commissioner Christie claimed that nothing in the NGA and its history suggests that the Commission can reject a project solely on adverse impacts to environmental interests (such as impacts on environmental justice communities, GHG emissions, etc.) because the history of the NGA indicates that Congress intended the statute to promote the development of gas facilities; the Commission was not given certification authority in order to advance environmental goals, and to construe the public convenience and necessity analysis as a license to prohibit the development of needed gas resources would negate the very legislative purpose of the statue. Commissioner Christie claimed that the issue of whether the Commission can reject a certificate based on a GHG analysis--a certificate that otherwise would be approved under the NGA--is undeniably implicates the “major questions doctrine” which presumes that Congress reserves major issues to itself, so unless a grant of authority to address a major issue is explicit in a statute administered by an agency, it cannot be inferred to have been granted. Commission Christie claimed that broad powers to regulate upstream and downstream GHG emissions and their global impacts has simply not been delegated to the Commission.
On March 22, 2022, the Commission issued an “Order on Draft Policy Statements” that converted both the Updated Policy Statement and the GHG Policy Statement to draft policy statements and invited comments on the draft policy statements. These draft policy statements will not apply to pending applications or applications filed before the Commission issues any final guidance.
On February 18, 2022, the Commission issued an Interim Policy Statement on greenhouse gas emissions (GHG Policy Statement) describing its procedures for evaluating climate impacts in its public interest determinations for the certification of natural gas facility construction. This GHG Policy Statement, which the Commission originally intended to apply to both pending and new Natural Gas Act (NGA) section 3 and 7 applications, has been converted to a draft policy statement by a subsequent order issued on March 22, 2022.
The GHG Policy Statement says that the Commission will quantify and consider GHG emissions resulting from construction and operation of the project as well as, in most cases, GHG emission resulting from the downstream combustion of transported gas. The downstream emissions from combustion will be based on project of the amount of project capacity that will be actually used (as opposed to assuming 100% utilization), and the Commission will consider evidence of factors expected to reduce or offset estimated or reasonably foreseeable downstream emissions. In the past, the Commission has typically found that the environmental effects resulting from natural gas production (upstream effects) are not “reasonably foreseeable” consequences because the location of the supply source and whether the gas will come from new or existing production are not known; but, the GHG Policy Statement provides that the Commission will continue to consider on a case-by-case basis upstream impacts, and to the extent known, project sponsors are encouraged to submit information on reasonably foreseeable upstream impacts.
To determine the appropriate level of review—whether an Environmental Assessment (EA) or a much more detailed Environmental Impact Statement EIS) will be prepared by the Commission—a project with estimated emissions of 100,000 metric tons per year or greater will require preparation of an EIS. This threshold will cover the vast majority of gas project—projects transporting 5,200 dekatherms per day and projects operating one or compressor stations or LNG facilities will likely exceed this threshold.
Project sponsors are encouraged to propose mitigation that will minimize climate impacts, and such project sponsor-proposed measures will be considered on a case-by-case basis when balancing the need for a project against its adverse environmental impacts, with the possibility that the Commission may require additional mitigation. The Commission stated that it will not be mandating any particular form of mitigation, but to ensure that any GHG emissions reduction mechanisms achieve real, verifiable reductions, the mechanism should: 1) be both real and additional-reductions would not have otherwise happened unless the mechanism was implemented, and reductions occur beyond regulatory requirements; 2) be quantifiable—calculated using a transparent and replicable methodology; 3) be unencumbered--seller has clear ownership of or exclusive rights to the benefits of the GHG reduction; and 4) be trackable—project sponsor must propose means for the Commission to monitor and track compliance for the life of the project. The various carbon offset markets that Commission noted that project sponsors could participate in include: 1) Renewable Energy Credits (tradeable commodities that provide proof that one megawatt hour of electricity was generated from a renewable source; 2) mandatory offset programs (e.g., programs that establish a GHG allowance for a power generator, and if a generator operates below such cap, it may trade an allowance to other entities); and 3) voluntary carbon offset markets. In addition to purchasing offsets, The GHG Policy Statement provides that project sponsors could propose to mitigate GHG emission through the use of physical, on-or off-site mitigation means (reducing fugitive methane emissions, incorporating renewable energy or energy efficient technologies to reduce emissions at compressor stations, or carbon capture and storage, planting trees or restoring wetlands).
As to the Commission’s authority to require mitigation, the Commission stated that it disagrees with the contention that it does not have authority under the Natural Gas Act (NGA) or the National Environmental Policy Act (NEPA) to require mitigation because downstream emissions are outside of its jurisdiction (the Commission does not have authority to impose conditions on the upstream and downstream users and entities). The Commission stated it is not asserting jurisdiction over such entities, rather, it is encouraging project sponsors to propose measures to mitigate the impacts of “reasonably foreseeable” GHG emissions associated with the project and will be considering such mitigation in assessing the extent of the project’s impacts. The Commission claimed that the NGA broadly instructs the Commission to consider the public convenience and necessity when balancing public benefits against adverse effects, including adverse environmental effects, and the Commission has broad conditioning authority to attach environmental conditions that mitigate adverse impacts of a project.
Commissioner Danly dissented, characterizing the GHG Policy Statement as “irredeemably flawed," “unworkable,” “an affront to basic fairness,” “unjustifiable,” and “unlawful” (because it arrogates to the Commission powers it does not have and violates the NGA and NEPA). In particular, Commission Danly took issue with the Commission telling project sponsors that they are free to propose mitigation mechanisms while offering no guidance on how much they should mitigate, nor explaining how the Commission can verify and track such mitigation throughout the life of a project. Commissioner Danly claimed that the GHG Policy Statement is directed at GHG emissions—measurement, threshold for preparing an EIS, and GHG emission mitigation—based on a presumption that GHG emissions are the “effect” of the authorization of the project (proposed action), but, the relevant effect that changes the human environment is not GHG emissions themselves, but rather, climate change. The question therefore under NEPA regulations is not whether GHG emissions are reasonably foreseeable but whether climate change is a reasonably foreseeable effect with a reasonably close causal relationship to the proposed action, and if so, can those effects be mitigated by the Commission. Commissioner Danly argued that climate change, as a result of any particular project, is not reasonably foreseeable (traceable and calculable) effect (to be a reasonably foreseeable effect we would be able to determine some quantifiable effect (additional climate change)) for which the project itself is causally responsible. He claimed that the Commission has never been able to do that and has repeatedly stated that “it cannot determine a project’s incremental physical impacts on the environment caused by GHG emissions”; nothing in the GHG Policy Statement suggests that this has changed and that the Commission can better determine a quantifiable connection between the two. Commissioner Danly also argued that Congress has delegated to EPA the decision of whether and how to regulate carbon dioxide emissions from stationary sources, but by claiming the authority to mitigate these same emissions as part of the NGA certification process, the majority are attempting to usurp the authority the Supreme Court has found to be delegated to EPA.
Commissioner Christie also dissented, for substantially the same reasons articulated in his dissent over the simultaneously issued updated policy statement on the certification of new gas facilities.
On July 28, 2022, the Commission issued a Notice of Proposed Rulemaking that would add a requirement that all entities communicating with the Commission or other specified organizations, concerning matters subject to the jurisdiction of the Commission, submit accurate and factual information and not submit false or misleading information or omit material information; an entity is shielded from violation if it has exercised due diligence to prevent such occurrences. Entities communicating with the Commission (including Commission staff), Commission-approved market monitors, and jurisdictional transportation providers would have this duty of candor; the Commission gave as an example, communications from shippers to interstate pipelines. The Commission stated that it intends to interpret “communications” broadly, including informal and formal communications, verbal or written, and via any method used for transmission. The regulations would apply to communications related to a matter subject to the jurisdiction of the Commission but matters tangential or unrelated to matters subject to its jurisdiction are not covered (e.g., contracts for general services with jurisdictional entities or employee/employer disputes within a jurisdictional entity). The Commission also explained that even where due diligence cannot be demonstrated, it is not the Commission’s intention to investigate or penalize all potential violations; inadvertent errors, especially those of limited scope and impact, will not be penalized.
Commissioner Danly dissented. He claimed that this expansion of the duty of candor is “chilling broad in scope” and by its plain terms, encompasses constitutionally protected speech. He gave as an extreme example, a landowner exaggerating a complaint in an email to a pipeline developer with a right-of-way on her land about construction noise and says something like “I’ve never heard such a racket” but in fact attended a Poison concert in 1988; absurd but also a duty of candor violation, and while the Commission enforcement of such a violation may be unlikely, the assurance given the public amounts to “just trust us.” The sad irony of the rulemaking, according to Commissioner Danly, is that actual candor within the industry will suffer; employees at one utility will hesitate to call or email counterparts at another utility without first seeking advice of counsel to make sure they have done their due diligence before engaging in any communication. Commissioner Danly solicited comments on whether an intent or materiality requirement would narrow the proposed duty of candor and allay concerns that the rule will impermissibly encompass core First Amendment protected speech.
On May 11, 2022, the Commission issued an order dismissing a request for rehearing, and in the alternative, addressing the arguments raised on rehearing concerning an enforcement proceeding over improper construction activity during the construction of the Rover Pipeline (Rover). On December 16, 2021, the Commission issued an Order to Show Cause and Notice of Proposed Penalty directing the Respondents to show cause why they should not be found to have violated the Natural Gas Act, Commission regulations, and Rover’s certificate order by: 1) including diesel fuel and other toxic substances and unapproved additives in its drilling mud during their drilling operations to cross the Tuscarawas River; 2) failing to adequately monitor the right-of-way at the drilling site; and 3) improperly releasing contaminated drilling mud (Drilling Proceeding). The Commission issued a Designation Notice specifying which Commission staff were designated as “non-decisional” (meaning they were involved in the initial investigation and cannot advise the Commission in its decision making or review of any settlement offer in the decision phase of the proceeding). Respondents sought rehearing of the Designation Notice arguing that it is unlawful because decisional staff in this proceeding may interact with non-decisional staff in a related proceeding in violation of ex parte communication and separation of functions rules under Commission regulations and the Administrative Procedures Act and the Fifth Amendment’s Due Process Clause. That other related proceeding is another enforcement action against Rover concerning the purchase and destruction of a potentially historic house and Rover allegedly misleading the Commission regarding this activity during the certification of the pipeline (Stoneman House Proceeding).
In dismissing the rehearing request, the Commission stated that its rules permit rehearing of any final decision or other final order and such orders are ones that impose an obligation, deny a right, or fix some legal relationship as a consummation of the administrative process. The Designation Notice is not such a final order because it does not resolve or even address the issues in this proceeding and imposes no penalty and requires nothing of the respondents.
However, the Commission stated that, to provide assurance of the Commission’s commitment to the highest ethical standards and to assure that the subjects of investigations receive due process, the Commission will exercise its discretion to construe the pleading as a motion to address the propriety of the Designation Notice and address the merits of the Respondents’ arguments. The Commission concluded that the Respondents have failed to prove that conferring investigative and adjudicative powers on the same individual posed such a risk of bias or prejudgment because Drilling Proceeding and the Stoneman House Proceeding are not “factually related” proceedings. The Commission cited instances where the same parties and even the same project did not render the proceedings factually related. The alleged facts giving rise to the Drilling Proceeding and Stoneman House Proceeding are, according to the Commission, distinct and the violations alleged are different in character. The Commission also noted that the Respondents submitted no evidence of impermissible commingling of function or improper communications and that there is a presumption that staff will follow Commission rules and that no due process violations have occurred.
Commissioner Danly issued a concurring opinion. He concurred with dismissing the rehearing request as procedurally improper because the Designation Notice is non-decisional. However, he asserted that the alternative of addressing Rover’s request on its merits is also procedurally improper because rehearing was dismissed and addressing the merits results in dicta that the regulated community will now have to contend with as if it were actual precedent, even though it is not. Commissioner Danly also characterized as improper the Commission’s own practice of designating staff as “decisional” or “non-decisional” and stated that the regulated community is rightly suspicious of the entire process. Employing staff to investigate and prosecute alleged wrongdoers and then have staff present their own case to the Commissioners to judge who is right—their own staff or the alleged wrongdoers--makes the whole process fraught with conflict of interest. As to the Commission’s claim that Rover submitted no evidence of impermissible commingling of function or improper communications, Commissioner Danly claimed that it should be obvious that supplying evidence is nearly an impossible burden. As to the finding that the two proceedings are not factually related, Commissioner Danly said that they may perhaps be unrelated in theory, but this pays no regard to the actual fact that the two proceedings involve the same company, the same project, many of the same witnesses, and many of the same investigators. Commissioner Danly questioned the need for decisional staff at all because enforcement adjudication involves numerous rounds of detailed back-and-forth show cause orders, answers and pleadings, such that if any questions or doubts remain then perhaps Enforcement staff has failed to prove the case.
On April 21, 2022, the FERC opened an investigation into whether Guardian Pipeline, L.L.C.’s (Guardian) rates are unjust and unreasonable. The Commission noted that Guardian’s currently effective rates were set in a settlement approved on February 6, 2006, and that the settlement approved the recourse rates authorized when Guardian was originally certificated, and that Guardian has not filed a Natural Gas Act Section 4 rate case since Guardian became subject to Commission jurisdiction. Based on Form 2 annual reports, the Commission estimated that Guardian’s return on equity was 16.1% in 2019 and 20.8% for 2020. Based upon this analysis, the Commission found that Guardian may be recovering revenue substantially in excess of its estimated cost of service. The Commission directed Guardian to file a cost and revenue study based on information for the latest 12-month period available. However, as the Commission has done in other recent Section 5 proceedings, the Commission permitted Guardian to also file a separate cost and revenue study that reflects projected changes that will occur during a six-month adjustment period following the 12-month base period. This matter was set for hearing before an Administrate Law Judge.
On April 21, 2022, the FERC opened an investigation into whether El Paso Natural Gas Co., L.L.C.’s (El Paso) rates are unjust and unreasonable. The Commission noted that it approved a rate settlement in 2019 that required El Paso to file a cost and revenue study at the end of a rate moratorium period ending on January 1, 2022. In its “Unadjusted Study,” El Paso claimed a revenue shortfall of $3 million, based on an illustrative return on equity (ROE) of 15.29% (derived from the ROE proposed by other pipelines in recent rate filings). El Paso’s “Adjusted Study,” which made adjustments to 1) increase depreciation rates, 2) increase negative salvage rates, 3) include transmission and storage terminal decommissioning cost allowances, and 4) reduce park and loan revenues, showed, according to El Paso, a revenue deficiency of $43 million. The Commission, using 2019 and 2020 Form 2 annual report data, estimated El Paso’s ROE at 24.4% in 2019, and 20.4% in 2020. Based on El Paso’s Unadjusted Study data, the Commission estimated an ROE of 20.7%. Although El Paso’s Adjusted Study proposed new depreciation rates, negative salvage rates, and decommissioning rates, the Commission removed these adjustments because the Commission had not approved these modifications and El Paso did not support these adjustments and came up with an estimated ROE of 19.3%. The Commission also found that the recent maturity date of $260 million in long-term debt, could materially affect whether El Paso’s use of its own capital structure remains appropriate for ratemaking purposes or whether it should rely upon its parent’s capital; these concerns would be addressed in the cost and revenue study El Paso was directed to file as well as in the hearing instituted by this investigation. El Paso sought rehearing of this order; the Commission dismissed the rehearing request because the investigation order is not a final dete4rmination of the justness and reasonableness of El Paso’s current rate, but rather, a procedural step, and is therefore not a final order subject to rehearing.
On June 30, 2022, the Commission accepted revised tariff provisions for Tennessee Gas to implement a producer certified gas (PCG) pooling service option on its system. In response to customer interest in “responsibly sourced gas” (RSG), Tennessee proposed to create an option under its pooling service that would allow gas aggregators to obtain certification from third-party certification vendors that particular gas supplies met certain minimum environmental, social and governance standards and Tennessee’s minimum performance criteria. Such performance standards include methane emissions intensity level (i.e., maximum permitted methane emissions during production of the gas). Tennessee’s pooling option would identify certified RSG gas offered at certain pooling points to facilitate trading and purchases and sales of such gas at those points. Tennessee initially proposed to post the PCG criteria on its website so that it would have the flexibility to revise the criteria as certification market standards evolve, but, in response to feedback from shippers, Tennessee modified its proposal by incorporating the PCG criteria into its tariff such that future changes to the criteria would be made via a limited Natural Gas Act (NGA) section 4 tariff filing. The Commission rejected this modified proposal because Tennessee had failed to demonstrate that incorporating the PCG criteria into its tariff is just and reasonable. The Commission stated that because RSG standards are in the early stages of development, it is appropriate to allow market-driven initiatives so that the development of RSG can happen organically. The Commission told Tennessee it could resubmit its proposal but exclude the PCG criteria from its tariff. The instant order approves such filing made by Tennessee. Parties protesting the filing argued that the PCG criteria includes certification standards and that the pooled gas cannot be included in the PCG pooling option if it does not meet these standards meaning that the criteria constitute terms and conditions of service, as they are being used to classify gas under a service, and therefore, NGA section 4 requires inclusion of the standards in Tennessee’s tariff. In accepting Tennessee’s proposal, the Commission noted that the PCG pooling option is a free, voluntary service which presents the shipper with an option, not a requirement, to designate certain gas traded at pooling points as PCG. Tennessee’s PCG pooling option adds to an existing pooling service “an informational feature,” that does not affect the transportation service itself or the rates or charges for such services, which simply informs shippers that a subset of pooled gas meets specified environmental criteria. This information does not affect transportation service and nothing in Tennessee’s tariff permits it to transport gas that meets the PCG criteria differently from other gas.
Commissioner Danly issued a dissenting opinion. He claimed that the majority ignored the fact that the PCG pooling option is itself a jurisdictional service; without the option, shippers could not aggregate PCG at proposed paper pooling points. As the PCG pooling option is a jurisdictional service, the classifications, regulations, and practices that significantly affect that option must be included in the tariff, and what could be more significant than the criteria to be eligible to participate in that service?
On August 22, 2022, the Commission granted Venture Global, an LNG exporter, a limited waiver of the Commission’s buy/sell prohibition and any other relevant capacity release regulations and policies to enable Venture Global to purchase gas from unaffiliated upstream suppliers, transport the gas over interstate pipelines capacity it has contracted for and liquify and sell the gas to potentially affiliated suppliers. Venture Global said that it has contracted for a large amount of firm capacity on four interstate pipelines to deliver gas to its LNG export terminal. Although Venture Global does not expect any gas supplier to be its affiliates, the suppliers potentially could be LNG sales customers or an affiliate of sales customers. This could be contrary to the Commission’s prohibition of buy/sell arranges, where a shipper holding interstate capacity is prohibited from buying gas at the direction of, or on behalf of, or directly from an entity, shipping that gas through its pipeline capacity, and then reselling an equivalent quantity of gas downstream to that same entity at the delivery point. Venture Global explained that it will not be buying gas at the direction of, or on behalf of another entity, and its gas suppliers are not explicitly seeking to transport gas to the export terminal and Venture Global will not sell equivalent quantities of gas back to that counterparty (or its affiliates), and any sales would not be of natural gas but rather LNG after liquefaction at the export terminal.
The Commission explained that its prohibition on buy/sell transaction is intended to prevent a capacity holder from circumventing the Commission open access policies which require capacity not being used by the holder to transport its own gas to be “released” by posting and bidding on a nondiscriminatory basis. Absent the buy/sell prohibition, a large marketer with significant amount of capacity could bypass the release market by engaging in a buy/sell transaction wherein the capacity holder would buy gas from its customer and transport it as its own gas and then sell it back to the same customer at a delivery point. Because Venture Global’s LNG customers are large gas producers and marketers, they could potentially include entities (or affiliates of such entities) from which Venture Global purchased gas. However, the Commission determined that Global Venture’s future transactions may foster an efficient, transparent, international market for gas based on a diverse national source of gas, and the requested waiver will give it the flexibility to manage its portfolio of supply and transport capacity to allow for LNG export, and therefore, a waiver would be in the public interest.
On February 17, 2022, the Commission issued an order on rehearing of its grant of a temporary certificate to continue operating its pipeline until the Commission acts on remand of a D.C. Circuit decision vacating the Commission’s order authorizing Spire’s construction and operation of its 65-mile greenfield pipeline. The Court vacated the certificate of an already built and operating pipeline. Spire filed for a temporary certificate to continue to operate because, if it were removed from service, Spire Missouri Inc., a local distributor and shipper on the pipeline, would be unable to obtain adequate supplies to satisfy peak demand in the St. Louis region during the 2021-2022 wither heating season. The Temporary Certificate Order permitted Spire to continue to operate but did not authorize the construction of any new facilities.
Rehearing petitioners argued that the Commission erred by failing to prohibit Spire from exercising eminent domain authority under the temporary certificate. Petitioners noted that Natural Gas Act (NGA) section 7(h) conveys the power of eminent domain to holders of a certificate of public convenience and necessity, but that section 7(h) refers only to a certificate issued under NGA section 7(e) and therefore does not confer eminent domain on the holder of a temporary certificate issued under 7(c)(1)(B). The Commission noted that courts have repeatedly held that Congress did not give the Commission authority to deny or restrict a certificate holder’s exercise of the statutory right of eminent domain with respect to a section 7(e) certificate, but Courts have provided less guidance on whether the same holds true for temporary certificates. The Commission declared that the applicability of NGA section 7(h) to temporary certificates is an issue better resolved by the courts. The Commission noted that two federal district courts have recently held that temporary certificates confer eminent domain authority. As to the petitioner’s claim that Order Nos. 871-B and 871-C presumptively say certificate orders pending rehearing, the Commission said that the stay is only presumptive and the question of whether to impose a stay will be decided on the particular circumstances; here, an emergency exists, and it would be inconsistent with a finding of a temporary emergency to stay the certificate and perpetuate the emergency. As to limiting the stay to eminent domain, the Commission again declared that it lacks authority to deny or restrict a certificate holder’s exercise of the statutory right of eminent domain.
Commissioner Danly issued an opinion concurring in part and dissenting in part. He concurred with the denial of a stay but dissented on the Commission’s decision to again decline to take a position on whether NGA section 7(h) confers eminent domain authority on the holder of a temporary certificate. He claimed that the Commission is well-situated to speak in the first instance on the rights enjoyed by a temporary certificate holder under the statue that the Commission administers.
On February 21, 2022, the Commission issued an order denying rehearing of a two-year extension of time for Algonquin to complete construction of its Atlantic Bridge Project. On January 25, 2017, the Commission issued Algonquin a certificate to construct the Atlantic Bridge Project, with the certificate including a condition that construction be completed and available for service within two years. The certificate also required Algonquin to obtain permits from the Massachusetts Office of Coastal Zone Management prior to construction of a compressor station in the Town of Weymouth, Massachusetts. In its request for a two-year extension of the construction deadline, Algonquin explained that it is experiencing delays in getting the required permits. On the same day that Algonquin filed its request for an extension, a branch chief in the Commission’s Office of Energy Projects (OEP) granted the request. The City of Weymouth and other petitioners filed for rehearing of the extension order.
The Commission denied assertions that neither the certificate order nor Commission regulations delegate authority for the branch chief to grant extension of time to complete construction. While the certificate order itself did not delegate to the OEP Director or the Director’s designee authority to extend the deadline, the Commission claimed that such authority is found in Commission regulations and the authority in the regulations do not require the proceeding to be uncontested.
As to the public convenience and necessity challenge to the extension, the Commission conceded that the information supporting its determination can go stale with time, but claimed that the completion date specified in its certificates are not intended to establish a limit for the period during which its environmental and other public interest findings are expected to remain valid; the Commission noted that it has authorized projects with deadlines of four, five or six years where appropriate. The Commission noted that the Atlantic Bridge Project’s market need was supported by 15 year long term agreements for 100% of the capacity and no evidence was provided that the extension would obviate those agreements. The Commission found that the only change Algonquin is requesting is to the timing of the project and no new circumstances or information has been present that were not already considered. As to the claim that good cause for the extension has not been demonstrated because Algonquin did not cooperate with the state and local agencies in pursuing the permit and delayed filing of a suit in federal district court claiming federal preemption, the Commission stated that good cause can be demonstrated by a good faith effort to meet its deadline which encountered unforeseeable circumstances and that the certificate holder is free to decide how to satisfy the prerequisites for construction. The Commission found that Algonquin was entitled to make its particular arguments in pursuing the necessary permits and did not unduly delay seeking a court judgment.
As to the almost immediate approval of the extension request, the Commission claimed that staff closely monitors projects and was in a position to determine immediately that an extension was warranted, and nothing in the Commission’s regulations suggest that an opportunity for notice and Comment is required; in any event, rehearing provides a full opportunity to challenge staff action. However, the Commission announce a new procedure going forward: a notice of requests for extension of time to complete construction will be issued within seven days, each notice will establish a 15-day intervention and comment deadline, only interventions from entities that were party to the underlying proceeding will be accepted and no reply comments or answers will be considered. For those extensions that are contested, the Commission acting as a whole will aim to issue an order on the request within 45 days. The Commission will not consider arguments that re-litigate the issuance of the certificate order.
On March 25, 2022, FERC issued an order authorizing Tennessee Gas Pipeline Company (Tennessee) to construct pipeline looping and a new compressor station, for Southern Natural Gas Co. (Southern) to construct a new compressor station, and for Tennessee to lease the capacity of the Southern project which will allow Tennessee to provide 1,100,000 Dth/day of firm service to Venture Global Plaquemines, LNG (Venture Global) (LNG exporter located in Louisiana). Certain intervenors claimed that the facilities being built by Southern to create the lease capacity constitute a cheap expansion, i.e., an incremental rate calculated to recover the cost of the new facilities would be lower than the existing system rate, and that the proposed lease rate to Tennessee is about half the applicable system rate that Southern is charging its customers. FERC noted that its practice is to approve a lease if it finds that: 1) there are benefits from using a lease arrangement; 2) the lease payments are less than, or equal to, the lessor’s firm transportation rates; and 3) the lease arrangement does not adversely affect existing customers. In applying this test, FERC found that Tennessee providing the proposed service to Venture Global using facilities constructed entirely on its own system would have significantly more adverse impacts on the environment and landowners and would cost approximately $1.55 billion, as compared to the $172,412,811 estimated cost of Southern building a portion of the project. FERC concluded that the reduced cost and adverse impacts, plus the administrative benefits of Venture Global being able to receive service under a single contract with Tennessee, meets FERC’s benefits test. As for the lease payments, FERC acknowledged that its rate policy for project expansion capacity would require the rates for the expansion to be not less than the applicable system rate (if an incremental rate would be lower than the applicable system rate, the system rate would be the expansion system rate), but, this lease is distinguishable because the shippers of the lessee have less rights than Southern’s shippers (restrictions on access to secondary points, no capacity release rights or segmentation rights); this limitation of rights under a lease is a reason why FERC does not require lease payments to be set at the lessor’s rate. FERC explained further that its requirement for expansion capacity rates to be set at the higher of the incremental rate or the existing system rate is intended to ensure that existing shippers can compete with expansion shippers on an equal basis for markets on that pipeline, but, when a pipeline obtains capacity under a lease, the shippers that use the lease capacity are not transporting gas on, or competing for markets on, the lessor’s pipeline (i.e., the Southern expansion capacity will be used by shippers transporting on Tennessee). As for the lease impact on Southern’s existing customers, the Commission found that its policy of not permitting the lessor to reflect in its system rates any costs associated with the lease capacity, provides protection during the term of the lease, and after the lease expires, the lessor’s customers would have the ability to challenge, in a rate proceeding, any proposal to include costs associated with the capacity in system rates.
In its environmental review, FERC declined to consider the impacts of upstream and downstream greenhouse gas emissions (GHG) pursuant to National Environmental Policy Act (NEPA) regulations, because the natural gas will be delivered to an LNG export terminal and the independent decision of the Department of Energy to allow the export breaks the NEPA causal chain and absolves FERC from responsibility for such analysis. FERC did provide estimates of GHG emissions caused by the construction and operation of the project and compared such estimates to national and state emission levels to assess the project’s share of contribution to such levels, but declined to characterize the emissions as significant or insignificant because FERC is in the process of conducting a generic proceeding to determine whether and how it will conduct significance determinations going forward. FERC also employed a “social cost of GHG tool intended to quantify, in dollars, estimates of long-term damage that may result from emissions of carbon dioxide, nitrous oxide, and methane, but, noting that there are legal challenges to federal agencies use of the particular methodology, FERC stated that it was not relying on these estimates to make any determination of either impact of the project’s GHG emissions or whether the project is in the public convenience and necessity.
Commissioner Danly issued a concurring opinion. He stated that he would have preferred that the order explicitly repudiate Northern Natural Gas Co.and reaffirmed the Commission’s prior position that without an accepted methodology, it cannot make a finding whether a particular quantity of GHG emissions poses a significant impact on the environment and how that impact would contribute to climate change. As to the inclusion of the Social Cost of Carbon calculation in the order, Commissioner Daly stated that the Commission has provided an extensive discussion as to why this metric is not appropriate for project-level NEPA review, and why it cannot meaningfully inform the Commission’s decision, and therefore, nothing can be gleaned from the numbers calculated by Commission staff and included in the order. As to the Commission’s “recognition” of the Sierra Club citing Vecinos para el Bienestar de la Communidad Costera v. FERC,as requiring the Commission to apply the Social Cost of Carbon protocol in its consideration of impacts, Commissioner Danly claimed that the Sierra Club misread the holding of the case, because the D.C. Circuit admonished the Commission not for failing to use this metric but for failing to respond to arguments that NEPA regulations require the use of this metric. Commissioner Danly also criticized the Commission for the unnecessary delay in issuing its certificate (two years after the filing, nineteen months after issuing the EA, and thirteen months after the requested issuance date).
Commissioner Glick issued a concurring opinion. He acknowledged the difficulty in assessing significance of the impacts of GHG emissions in the absence of a universally accepted scientific methodology and the difficulty in ascribing discrete impacts of carbon dioxide caused by a particular project but argued that the administration of NEPA is rife with judgment calls and agencies use the best tools and information at hand. He claimed that the Commission does not hold other environmental impacts associated the natural gas infrastructure to the same high standards for considering significance, for example, the Commission routinely assesses impacts on permafrost, ephemeral and intermittent waterbodies, visual resources and old growth forests without clearly articulated objective standards, much less ones enjoying universal acceptance. He stated that he is concurring with this order because it does not rehash the same arguments on the difficulty of assessing climate impacts and instead defers to the now Draft GHG Policy Statement. However, Commissioner Glick voice his disappointment in the Commission not following the lead of Northern which states that there is nothing about GHG emissions that prevents the Commission from making a significance determination. He would have applied Northern to find the emissions of this project are not significant.
Commissioner Clements issued a concurring opinion. He stated that this order declines to label the GHG emissions here as significant or insignificant because there is no consensus among the Commissions on whether and how to determine significance. He stated that he supports the 100,000 ton per year carbon dioxide threshold for determining significance in the Commission’s Draft GHG Policy Statement because it provides a workable framework and gives clarity to stakeholders, but that he is open to considering all reasonable approaches.
Commissioner Christie issued a concurring opinion. He claimed that the nation’s response to climate change is a major policy question and how GHG reduction will be accomplished will impact all Americans, and therefore, the public policy is for elected legislatures, not unelected judges and unelected administrative agencies to decide, unless Congress unambiguously gives the agency clear authority to implement policy regarding GHG emissions and their impact on global climate change. He claimed that there is national campaign to achieve the policy goal of eliminating the use of natural gas and prevent the construction of pipeline infrastructure, and this is a major question of public policy that must be made by the legislature. Commissioner Christie stated that one of the fundamental questions likely to be raised on appeal of this order is: Should or even can the Commission credibly characterize the impact of estimated GHG emissions from a single facility on global climate change? The answer, he said, is: no. He claimed that what the Commission can do, which will satisfy various court requirements regarding its NEPA obligations is to provide an upper bound estimate of GHG emissions. But, estimating a quantity of GHG emissions, is fundamentally different from predicting the impact of such emissions on global climate change and making a finding that these impacts are significant or insignificant. Although such findings will have no intellectual rigor and should not be used to reject a natural gas facility, according to Commissioner Christie, because the Commission has no jurisdiction to order mitigation of upstream or downstream emissions, the “real game” of those advocating the Commission to characterize the emissions as significant is to offer outright rejection of the facilities as among the remedies for such impacts.
Commissioners Phillips and Christie issued another concurring opinion addressing Northern. They explained that they depart from Northern because that decision did not make clear how the determination that the particular emissions estimated were not significant or how a finding of significance would have affected the Commission’s duties and authority under the NGA. In the instant order, the Commission assessed the emission but did not estimate the extent of those emissions’ impact on the environment because the Commission does not have the analytical tools to so do. They stated that the Commission should continue to provide as much detail, but to the extent the Commission makes a significance determination or draws a bright line between significance or insignificance, the Commission should identify the factors considered and explain the determination.
On April 8, 2022, the Commission approved an amendment application by Mountain Valley Pipeline (MVP) to change most of its waterbody and wetland crossings from open cut to trenchless (primarily conventional bore); slightly shift the right-of-way to avoid a wetland and a waterbody, and to conduct 24-hour construction activity at trenchless crossings. As to claims that the amendment triggered requirements for state certification under section 401 of the Clean Water Act (required for construction or operation of facilities that may result in discharges into navigable waters), the Commission concluded that the construction methods and mitigation measures proposed would avoid discharges into waters of the United States meaning that certification was not necessary. The Commission stated that it solicited the opinions of the two states where the project is located (Virginia and West Virginia) and both states said it was up to the federal agency to make the determination as to whether a section 401 permit is required, and both also stated that their prior 2017 authorizations would cover any activities that would require certification. As to the status of other authorizations, FERC stated that MVP is not permitted to commence any new construction until it has received all outstanding federal authorizations-- the Corps authorizations to complete its open-cut crossings, authorization to cross the Jefferson National Forest, and Fish and Wildlife Service authorizations regarding endangered species.
On March 25, 2022, the Commission granted a declaratory order petition by Nopetro requesting that the Commission declare that its construction and operation of a natural gas liquefaction and truck loading facility and proposed loading operations in St. Joe, Florida, would not be subject to the Commission’s jurisdiction under section 3 or section 7 of the Natural Gas Act (NGA). The facilities would receive gas from a non-jurisdictional local distribution company, liquify the gas, load the LNG into ISO containers which would be trucked a quarter mile to a dock, and at the dock, the ISO containers would be loaded onto ocean-going general cargo container vessels for export to foreign markets. Section 3(a) of the NGA provides for federal jurisdiction over the siting, construction, and operation of facilities used to import and export gas. The Commission exercises this authority over 1) LNG terminals located at the site of import or export, and 2) the site and facilities where a pipeline crosses and international border. Under a 2005 amendment to the NGA, section 2(11) was added to act to define an LNG terminal as:
All natural gas facilities located onshore or in State waters that are used to receive, unload, load, store, transport, gasify, liquefy, or process natural gas that is imported to the United States…, exported to a foreign country…, or transported in interstate commerce by waterborne vessels….
Commentors argued that the Nopetro facility should be considered close enough to the point of export to meet the definition of an LNG terminal because it is only a quarter mile away from the export point and notwithstanding the fact that the ISO containers are trucked that distance this has the effect of directly transferring LNG to an ocean-going LNG tanker. The Commission disagreed. The Commission found that trucking the ISO containers and using loading equipment that is available for general public use (the dock and crane) means that the Nopetro facilities are not capable of transferring LNG onto water-borne vessels.
Rehearing petitions focused on the term “onshore” in section 2(11). The Commission stated that while section 2(11) is ambiguous, it can reasonably be read in a manner consistent with the Commission’s well-established precedent and evidence of congressional intent to include only those onshore facilities that are on the coast such that LNG can be directly transferred to vessels for export. The Commission claimed that the term “onshore” when used in conjunction with “or in State waters,” and combined with the fact that section 3 applies to LNG that is “transported in interstate commerce by waterborne vessels,” connotes that section 2(11) applies to facilities that are located on or near the water or the coast. The Commission cited prior Commission orders disclaiming jurisdiction over inland facilities that did not directly transfer LNG to oceangoing vessels and to cases involving compressed natural gas where the fact situation was virtually identical (facilities located a quarter mile from the point of export). As to claims that “onshore” is intended to differentiate the Commission’s jurisdiction from that of the Coast Guard which has jurisdiction over deepwater ports used for the import or export of natural gas, the Commission argued that there is no dispute that the Commission has jurisdiction over onshore facilities so the question is whether “onshore” should be read so broadly as to encompass non-coastal facilities; there is no support given to the assertion that Coast Guard jurisdiction over offshore facilities means that the Commission necessarily has jurisdiction over any onshore facility which might liquefy gas that might ultimately be exported, particular when section 2(11) explicitly contemplates transportation by waterborne vessel.
On June 17, 2022, the Commission granted an application by Equitrans to abandon all of its certificated and non-certificated gathering facilities, consisting of approximately 932 miles of low-pressure pipelines, 11 compressor stations and other facilities in West Virginia and Pennsylvania and to remove from its tariff Rate Schedule AGS (Appalachian Gathering Service) under which it provides interruptible gathering service on these facilities. The overriding issue of parties opposed to the abandonment was continuity of gas service to customers of local distribution companies (LDC) that have no alternative means of receiving service; these parties argue that abandonment does not meet the public interest standards for abandonment under section 7(b) of the Natural Gas Act (NGA) for which courts have found that continuity and stability of service are the primary considerations.
In granting the application, the Commission noted that section 1(b) of the NGA gives the Commission jurisdiction over the transportation of natural gas in interstate commerce but specifically provides that the NGA does not apply to local distribution of gas or the gathering of natural gas. However, if an interstate pipeline provides gathering service in addition to jurisdictional transportation service, the Commission may have jurisdiction over the rates of that gathering service, as it may be considered as being performed in connection with the jurisdictional transportation service (because this enables the Commission to ensure that the rates for the jurisdictional services are just and reasonable and not discriminatory). But, when the Commission imposed a requirement on a pipeline trying to spin down gathering facilities and to cease gathering service to have in place contracts ensuring continuity of service for two years at existing rates, the D.C. Circuit held that the Commission has no authority to impose the contract condition on the abandonment of facilities or services that were exempt for its 1(b) jurisdiction. In granting the abandonment the Commission stated that it recognizes the concerns over the fitness of purchasers of Equitran’s facilities and the potential for immediate cessation of service to captive end users, but the Commission has no discretion to disregard the section 1(b) exemption of gathering facilities from its jurisdiction. In sum, the Commission declared that once Equitrans filed for abandonment, the Commission had no discretion to deny, and must approve, the request, and there is no section 7(b) analysis that must be conducted to determine if the abandonment is in the public interest (i.e., no consideration of whether customers are firm or interruptible for purposes of assessing continuity of service obligations that are normally analyzed in abandonment applications). The Commission added that it has no authority to place conditions upon the approval of the abandonment as would be the case with abandonment of jurisdictional facilities, and therefore, the Commission denies requests for assurances of alternative arrangements being in place, or compensation to LDCs for the cost of continuing to provide service or the costs of end users to convert to alternative forms of energy.
