2. California Restaurant Ass’n v. City of Berkeley
On April 17, 2023, the Ninth Circuit held that the Energy Policy and Conservation Act (EPCA) preempts a Berkely ordinance that, as part of its building code, prohibited the installation of natural gas piping within newly constructed buildings. EPCA expressly preempts state and local regulations concerning the energy use of many natural gas appliances, including those used in household and restaurant kitchens. Instead of directly banning those appliances in new buildings, Berkely took a more circuitous route to the same result via a building code that prohibits piping into those buildings rendering such gas appliances useless. The ordinance sought to eliminate “obsolete” natural gas infrastructure and associated greenhouse gas emissions in new buildings thereby reducing the environmental and health hazards produced by the consumption and transportation of natural gas. Berkeley argued that the EPCA preemption only covered regulations that impose standards on the design and manufacture of appliances, not regulations that impact the distribution and availability of energy sources like natural gas. Specifically, the preemption clause of EPCA states that once a federal energy conservation standard becomes effective for a covered product, no state regulation concerning the energy efficiency, energy use, or water use of such covered product shall be effective. The Court found that EPCA preempts regulations that relate to the quantity of natural gas consumed by certain appliances at the place where the appliances are used, and EPCA is concerned with the end-user’s ability to use installed covered products; a regulation that prohibits consumers from using appliance necessarily impacts the quantity of energy directly consumed by the appliance. By enacting EPCA, the Court found, Congress ensured that states and localities could not prevent consumers from using covered products in their homes, kitchens, and businesses, and this preemption extends to regulations that address the products themselves and the on-site infrastructure for their use of natural gas. State and localities cannot skirt the text of broad preemption provisions by doing indirectly what Congress says they can’t do directly, so Berkeley can’t evade preemption by merely moving up one step in the energy chain and banning natural gas piping within those buildings; otherwise, the ability to use covered products would be meaningless. The Court added that, if a state enacted a broad regulation on all appliances, some that are “covered” and some that are not, EPCA would only supersede the regulation’s impact on the covered products.
3. Center for Biological Diversity v. FERC
On May 16, 2023, the D.C. Circuit denied a petition for review of the Commission's authorization of LNG facilities in Alaska’s North Slope. The Center for Biological Diversity (CBD) challenged the Commission’s decision on environmental grounds.
CBD claimed that the Commission failed to comply with the National Environmental Policy Act (NEPA). The Court noted that NEPA is a purely procedural statute and an agency therefore enjoys latitude when preparing an Environmental Impact Statement (EIS), and therefore the Court will not set aside an agency action on NEPA grounds if the EIS contains sufficient discussion of relevant issues and opposing viewpoints and the agency’s decision is fully informed and considered. As to CBD’s claim that the Commission inadequately considered alternatives to the project, the Court stated that alternatives must be technically and economically practical or feasible and must meet the purpose and need of the proposed action; those alternatives that are impractical or fail to further the purpose of the project may be rejected after only brief discussion. For the “no-action” alternative of rejecting the project with nothing like the project being built, the Commission’s concise rejection was reasonable because the project’s purpose was commercialization of North Slope gas, and this purpose would not be fulfilled. The Court found that the Commission recognized that if the project was not built substantial incentives would remain to commercialize North Slope gas, but reasonably rejected the likely alternatives because they would have similar environmental impacts to those of the project. The Court rejected CBD’s argument that the Commission was required to evaluate each alternative along every dimension of impact used to analyze the project. The Court claimed that rigorous evaluation means assessing and comparing impacts of reasonable alternatives, but some alternatives are more reasonable than others based on economic and technical feasibility and how well they serve the purpose of the project, and therefore, an agency need not provide the same level of detailed analysis for each alternative. The Court affirmed the Commission decision to evaluate reasonable alternatives along 23 dimensions of impact and reasonably concluded that no alternative offered a significant environmental advantage over the project.
As to CBD’s claim that the Commission acted arbitrarily and capriciously in not employing the social cost of carbon (SSC) metric to estimate the significance of the project’s direct emissions of greenhouse gas (GHG), the Court agreed with the Commission that the absence of an adequate methodology—lack of consensus on how to apply SCC on a long term horizon and lack of ability for the Commission to establish criteria for translating dollar values on carbon emissions into an assessment of environmental impacts—renders the Commission unable to assess the project’s causal effects on climate change. The Court cited recent cases that uphold the Commission’s finding.
As to CBD’s claim that the project approval and the Department of Energy’s decision to approve the export of the LNG are “connected actions” which cannot be segmented in the NEPA analysis (i.e., must be considered in the same EIS), the Court disagreed because the regulations concern closely related actions, but cannot expand the Commission’s jurisdiction; CBD’s reading of the regulations would conflict with precedent and would require the Commission to consider indirect effects of actions beyond its authority.
The Court rejected CBD’s claim that the Commission’s consideration of the project’s impact on beluga whales was inadequate. The Court found that the Commission carefully identified potential threats to belugas (primarily noise from underwater construction and additional ship traffic), analyzed the magnitude, and proposed targeted mitigation measures; this approach was entirely reasonable. The Court found that while CBD proposed an alternative way to analyze the impacts on the belugas, CBD did not demonstrate that the Commission’s analysis was unreasonable.
4. Fore River Residents Against the Compressor Station v. FERC
On July 21, 2023, the D.C. circuit denied rehearing of the Commission’s order granting Algonquin Gas Transmission LLC (Algonquin) an extension of time to complete construction of its Weymouth compression station project and a subsequent order permitting the compressor station into service. The Commission certificate order imposed a January 25, 2019, deadline to complete construction, but, challenges to required permits prevented Algonquin from constructing the project prompting Algonquin to file, on December 26, 2018, for a two-year extension of the deadline; that same day a Commission Branch Chief granted the request. Petitioners filed for rehearing, arguing that the Branch Chief lacked power to grant the request and that the short turnaround time evidenced unreasoned decision-making and did not afford the public an opportunity to submit adverse comments. The Commission order on rehearing found that the Branch Chief had delegated authority and acted quickly because he was closely following the proceeding, and concluded that good cause existed to grant the extension because there was no evidence of environmental changes or new information that would prompt a denial. Following construction of the Weymouth compressor station and other project facilities, Algonquin requested permission to bring the facilities online, which was granted by a Commission staff order. Neither the request nor the staff order mentioned that during safety testing a gasket failed at the compressor station resulting in a release of gas. Six days after the staff order was issued, the compressor station suffered another emergency shutdown and release of gas. The petitioners requested rehearing of the staff in-service authorization. They argued that the two emergency shutdowns necessitated a new “situational assessment” and that the Commission should reexamine project need and safety findings underpinning the original certificate order. This rehearing was originally denied by the Commission failing to take action, but, several months later, the Commission took the unusual step of requesting fresh briefing on the rehearing petition and asked for the parties to address a number of questions, including whether the Commission should “reconsider” operation of the Weymouth compressor station in light of changed circumstances since the project was authorized. In denying rehearing following the supplemental briefing, the Commission held that the process of authorizing a project to come online could not be used as an opportunity to relitigate the certificate proceeding, and nothing in the Natural Gas Act (NGA) or any Commission regulations or decisions require a situational assessment of a project so that the only relevant question is whether Algonquin complied with its certificate. On that score, the Commission found no violation of Algonquin’s certificate; the release of gas during two emergency shutdowns were not beyond the range of what was contemplated by the Commission in its certificate proceeding.
The Court denied the petitions for review of both orders on procedural grounds. For the extension order, the Court found that the alleged procedural defect of the Branch Chief granting the extension was redressed by the Commission inviting extensive briefing, taking time to consider the record, and ultimately ratifying the initial decision and explaining why the extension was granted for good cause. As to the order permitting the facilities to be put online, the Court found that the Commission took three actions: 1) it granted the authorization; 2) it denied rehearing of that decision; and 3) following further briefing, it again denied rehearing (second rehearing order). The Court found that the petitioners only challenged the second rehearing order and did not challenge any substantive order within the meaning of the NGA (the order granting the authorization), and that, under the NGA, an order denying rehearing is not the type of order that , standing alone, can be the basis for review (a rehearing order can be challenged along with an “aggrieving” order, but the rehearing order cannot be challenged on its own). The only exception is if the rehearing order substantively modifies the result reached by the original order, in effect creating a new order subject to judicial review in its own right, which is not the case here because the Commission reached the same conclusion and simply marshaled new arguments to support the old outcome.
C. Enforcement
BP Corporation North America, Inc. IN13-15-000
On July 7, 2023, the Commission approved a Stipulation and Consent Agreement between its Office of Enforcement and BP America Inc. (BP) resolving matters remanded by the Fifth Circuit concerning the amount of civil penalties BP must pay for violation of the Commission’s Anti-Manipulation Rule. The Fifth Circuit agreed with the Commission that BP engaged in practices that manipulated the price of natural gas, but, found that certain transactions were not under the Commission’s jurisdiction and remanded to the Commission for a redetermination of the penalty amount. BP gas traders who held a spread between two trading hubs—the Houston Ship Channel and Henry Hub, found that, following Hurricane Ike, they were making a large amount of money from the much lower price of gas at the Houston Ship Channel as compared to Henry Hub. As the hurricane conditions abated, that spread began to close, but the traders, by selling at Houston Hub, sought to maintain the spread. The Court found in favor of the Commission that BP traders employed illegal manipulation of the market, but agreed to part of BP’s claim that the trades were not transactions in interstate commerce, and hence, the Commission did not have jurisdiction. Section 4A of the Natural Gas Act provides that: “It shall be unlawful for any entity, directly or indirectly, to use or employ, in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of the Commission, any manipulative. . .” The Commission claimed that the “any entity” and “in connection with” language gives it jurisdiction over any transaction that is a part of a manipulative scheme so long as that scheme affects the price of NGA-jurisdictional transactions. The Court disagreed, but agreed with the Commission that once gas is sold or transported in a transaction subject to NGA regulation, all subsequent transactions, including intrastate transactions, are controlled by the NGA. Some of the transactions, but not all, were found to be subject to the Commission’s finding of market manipulation.
The instant consent agreement reduces the civil penalty of $24,356,686 that BP has already paid to $10,750.
D. Rate Cases
1. Transcontinental Gas Pipe Line Co. RP23-840-000
On June 16, 2023, the Commission accepted and suspended tariff records and established hearing procedures concerning tariff changes Transcontinental Gas Pipe Line Co. (Transco) filed to implement market-based rates at its Washington Storage Field. In a prior order, the Commission granted Transco’s declaratory order petition which authorized Transco to charge market-based rates at the Washington Storage Field. In prior proceedings, Transco and its customers were engaged in extensive litigation over how to allocate the cost of replacement base gas at the Washington Storage Field. Under legacy rights held by some historical customers, such customers could buy, at very low prices, the base gas used to support their storage service when they ended their storage service at the Washington Storage Field. This raised complex issues as to how to allocate the substantial cost that Transco would incur in replacing such purchased base gas—whether it should be allocated to the new customers replacing the legacy customers leaving the system or to all customers new and old; this issue was resolved by settlement. In the instant proceeding, Transco filed tariff sheets to implement the market-based rates authorized by the Commission. The WSS Customer Group (Group) (primarily large utility customers of Transco) protested the filing and requested summary rejection. The Group argued that allowing Transco to provide market-based rate service utilizing low-cost base gas supplied by historical customers created an unlawful subsidy that is unjust and unreasonable. The Group also claimed that Transco failed to explain how market-based rates would be assessed to customers whose rates are currently cost-based, and that Transco must be required to establish parameters for initial implementation of market-based rates. The Group also claimed that the Commission should reject Transco’s proposal to remove reservation charge credits (credits when the pipeline is unable to provide service), as allowing Transco to impose whatever relief it believes to be appropriate. The Group also claimed that its members have solicited alternative storage service offers, and its failure to such alternatives demonstrates that Transco is a monopoly storage provider and the Commission’s declaratory order’s assumption of workable competition has not been realized and Transco’s filing must therefore be rejected.
In denying the requests for summary rejection, the Commission noted that summary disposition is granted only if there are no material issues of fact in dispute and the filing is a clear violation of an applicable statute, regulation or Commission policy; pleadings and evidence is considered in light most favorable to the non-moving party, and the burden of proof, which is on the moving party, and all ambiguities and reasonable factual inferences must be resolved in the non-movant’s favor. The Commission found that Transco has demonstrated that the Washington Storage Field is located in a highly competitive market and the Group failed to show any change in circumstances that warrant reconsideration of the Commission’s prior determinations. The Commission found that evidence of two companies having difficulty locating alternatives is insufficient, for purposes of summary rejection, because this does not definitively establish that there is a lack of alternatives or that Transco has market power. As to the issue of whether the low-cost base gas furnished by historical customers provides a significant subsidy of market-priced storage, to the detriment of existing customers who will no longer receive the direct benefits from the inexpensive gas they furnished for injection as base gas, the Commission found that it is unclear whether existing customers will continue to benefit from their provision of low-cost base gas in negotiating market-based rates in the future, or how base gas cost will impact new customers. Specifically, the Commission noted that historical customers are free to purchase their base gas, minus an injection/withdrawal fee, if they are no longer interested in service, and speculative and premature claims of undue subsidy are insufficient to meet the standards warranting summary rejection. The Commission noted that these issues were considered in the declaratory order, and therefore, these arguments constitute a collateral attack on prior orders.
Nonetheless, the Commission found that Transco’s filing has not been shown to be just and reasonable, suspended the effectiveness of the filing for the maximum five-month period, and set the matter for hearing. As part of the hearing process, Commission staff was directed to conduct a technical conference.
2. Guardian Pipeline, L.L.C. RP23-92-000
On February 15, 2023, the Commission approved an uncontested rate settlement which was the culmination of a Natural Gas Act (NGA) section 5 investigation of the justness and reasonableness of Guardian Pipeline, L.L.C.’s (Guardian) rates. Based on Form 2 data (annual financial reports to FERC) for the years 2019 and 2020, Commission staff estimated that Guardian garnered a return on equity of 16.1% in 2019 and 20.8% in 2020. Finding that this level of return might render Guardian’s rates unjust and unreasonable, the Commission instituted an investigation. Guardian filed a settlement proposing to reduce rates over three periods, beginning April 1, 2023. The settlement establishes a moratorium, through April 1, 2026, for both Guardian filing a new rate case under NGA section 4 or settling parties and the Commission seeking to change rate under NGA section 5. Guardian will be required to file an NGA section 4 general rate case to be effective no later than April 1, 2027. The settlement provides that the standard of review for any proposed modifications to the settlement filed by the Commission or by non-contesting parties acting unanimously or any third party, will be the ordinary just and reasonable standard, while the standard for review for requests by fewer than all of the non-contesting parties will be the more stringent “public interest” standard.
E. Major Tariff/Service Issues
1. Equitrans, L.P. RP23-694-000
On May 19, 2023, the Commission accepted certain proposed tariff changes and rejected a proposed change filed by Equitrans, L.P. (Equitrans) concerning contracting for negotiated and discounted rate service. Equitrans proposed: 1) to set forth the circumstances where it may seek a discount-type adjustment for negotiated rate agreements; 2) add a clause to the pro forma contract stating that a discounted or negotiated rate was required by competition; and 3) allow for multiple rate agreements within a single service agreement.
As to the first proposed change, which sets forth the burden of proof, Equitrans must satisfy in a future general rate case to obtain a discount-type adjustment for a negotiated rate agreement (a showing that the negotiated rate was required to meet competition and that an adjustment to the rates will not have an adverse impact on recourse rate shippers) the Commission accepted the provision, as it has done with other pipelines, because it recites the burden of proof established by the Commission in its own Alternative Rate Policy Statement.
However, the Commission rejected putting into the pro forma service agreement a provision which states that the customer agrees that it has competitive alternatives and that the negotiated rate reflects the market rates for pipeline capacity at this time and are necessary to meet competition and for the customer to contract for capacity on Equitrans. The Commission noted that it has rejected similar proposals and Equitrans failed to argue that the Commission should reconsider its reasoning. The Commission noted that it already allows Equitrans to require the customer to provide documentation supporting any request for a discount; a mandatory clause added to all contracts, by contrast, documents neither the intent of the parties nor the market conditions at the time of contracting.
The provision allowing Equitrans to enter into multiple separate letter agreements under one contract to address different components of the rate (e.g., separate agreement for discounted fuel), was allowed in recognition that certain components, like fuel, are not eligible for a discount adjustment, and such separation permits easier accounting for such components. Such separation does not, according to the Commission, prejudge any aspect of a future general rate case.
2. Columbia Gas Transmission, LLC RP23-824-000
On June 30, 2023, the Commission granted a waiver request of Columbia Gas Transmission, LLC (Columbia Gas) to recalculate a rate under its current operational transportation cost rate adjustment (TCRA) by using a different time period than specified in its tariff to reflect refunds provided by another pipeline under a rate settlement. In approving the waiver request, the Commission applied its “four-factor test” which provides that a waiver will be granted where: 1) the applicant acted in good faith; 2) the waiver is of limited scope: 3) the wavier addresses a concrete problem; and 4) the waiver does not have undesirable consequences, such as harming third-parties. For the first factor, the Commission found that Columbia Gas acted in good faith by filing in advance of the requested effective date of the tariff record (by one month). For the second factor, the Commission found that the waiver is limited in scope because it is a one-time waiver that extends only till the next periodic filing is made. For the third factor, the Commission found that the waiver addresses the problem of Texas Eastern’s refund being issued after the specified date for the beginning of the annual period. For the fourth factor, the Commission found that the waiver reduces the TCRA rate by incorporating the refunds provided by the other pipeline. The Commission also noted that it previously used a “good cause shown” standard for evaluating tariff waiver requests, but now applies this four-factor test; for requests to waive Commission regulations, policies, and order conditions, the Commission will continue to use the “good cause shown” standard.
3. Florida Gas Transmission Co. RP23-466-000
On August 25, 2023, the Commission issued an order, following a technical conference, that rejected Florida Gas Transmission’s (FGT) proposed tariff changes regarding gas quality standards for the receipt and transportation of renewable natural gas (RNG) on its system. FGT proposed standards that would allow the introduction of RNG to its system, but would include limits on certain constituents found in raw biogas that have been identified in some studies as being of concern to the health of gas consumers and having the potential to harm pipeline facilities; the proposed tariff changes would also impose testing requirements on deliveries of RNG to its system.
The Commission, applying its Gas Quality Policy Statement, rejected the proposed tariff changes. The Commission stated that the Policy Statement provides that the Commission will assess the justness and reasonableness of gas quality and interchangeability tariff proposals on a case-by-case basis based on a record of fact and technical review, with each determination being unique and specific to the record of that proceeding, and with a balancing of safety and reliability concerns with the importance of maximizing supply, and recognizing the evolving nature of the science underlying these issues. The Commission also noted that the pipeline and its customers are required by the Policy Statement to collaborate in the process. While recognizing that FGT is attempting to balance the interests of a diverse group of shippers and recognizing that, unlike geologic gas, there has been no industry-wide effort to reach a consensus on RNG, FGT’s reliance on studies and standards from outside of its own system by itself is insufficient to support proposed tariff changes on its system; FGT had not shown how these studies and standards relate to its own system. Specifically, the Commission stated that FGT must show that: 1) the restricted constituents cause a specific problem on the pipeline’s system; 2) the proposed tolerance levels would solve the problem; and 3) there are not lower-cost or lower-impact solutions. In order to impose more stringent gas quality standards, a pipeline must demonstrate that the restrictions are necessary to resolve current or anticipated issues on its system. Also, the Commission stated that papers and studies that are not specific analyses regarding how RNG standards will affect shippers, the pipeline, and the market for RNG on that specific system, do not allow the Commission the ability to find the proposed changes to be just and reasonable.
F. Infrastructure-Natural Gas
1. Driftwood Pipeline LLC CP21-465-000
On April 21, 2023, the Commission approved the construction and operation of two 42-inch mainline pipelines (co-located on the right of way) that extend from a new compressor station to the affiliated Driftwood LNG terminal (about 37 miles in length) to deliver up to 5,400,000 Dth/day of gas. Following an open season, Driftwood LNG, the foundation shipper signed a binding precedent agreement for 5,000,0000 Dth/day of capacity (92%) and two other shippers signed for 100,000 Dth/day each for a total subscription of 96% of the project’s capacity. Driftwood is a new pipeline company whose mainline facilities were certificated in 2019, but construction on the mainline has not commenced. The instant expansion project is not connected to the mainline.
Under the Commission’s 1999 Certificate Policy Statement, the threshold requirement is that the project applicants must be prepared to financially support the project without relying on subsidization by existing customers. Here, the Commission found, so subsidization issue exists because there are no existing customers, and even if the mainline is placed in service before this project, the incremental rates for the project’s service will ensure that the cost of the project, and the attendant risk, will be borne by the project’s customers.
As to the determination of need for the project, the Commission agreed with the applicant that there is shortage of connectivity between the existing pipeline network located between 20 to 30 miles north of the Lake Charles, and the Driftwood LNG terminal located at Lake Charles where the proposed pipelines would terminate. While acknowledging that 92% of the capacity has been contracted for by Driftwood’s affiliate, the Commission found that the precedent agreements demonstrate the need for the project and that it is not uncommon for entities developing LNG terminals to construct and operate, though an affiliate, an associated pipeline to provide transportation of gas which will serve as feedstock for the liquefaction process. The Commission also noted that LNG terminals, unlike, for example, affiliated local distribution companies, have no captive customers to whom they can pass costs associated with their transportation customers. The Commission found that a market study supplied by the applicant demonstrated a growing need in the Lake Charles, LA region (near the proposed Driftwood LNG, and other LNG terminals), with existing pipelines unable to meet that need. Although the Commission recognized that Driftwood LNG has not asserted that there is insufficient supply for its authorized exports of LNG, the Commission found that the project would provide the shipper with additional supply options which would enhance diversity, resilience, and reliability of its supply.
As to the claim that gas that is exported is not used by the “public” and therefore does not meet the “public interest” requirement of Natural Gas Act (NGA) section 7, the Commission disagreed. The Commission cited City of Oberlin v. FERC, which held that precedent agreements for gas that would be exported can be considered because all factors that might bear on public interest can be considered. The Commission also noted that the Driftwood LNG terminal is authorized by the Department of Energy to export LNG to countries that have entered into free trade agreements with the US, and section 3 of the NGA provides that exports to a free trade partner are deemed to be in the public interest. As to the claim that most, if not all, of the gas will be produced in Louisiana and would not be interstate commerce, the Commission noted that the project will receive gas from numerous interstate pipelines for redelivery into the Lake Charles market, including potential domestic destinations outside of Louisiana through interconnects with other interstate pipelines, making the project an interstate pipeline.
In its environmental review of the project, the Commission estimated the greenhouse gas (GHG) emissions from the construction and operation of the project. However, citing prior precedent, the Commission limited its review to the quantity of gas under contract to just one of the 100,000 Dth/day shippers because the other two shippers would be exporting the gas as LNG and the Commission has determined that the downstream end-use of LNG. As per regular Commission practice, these levels of GHG emissions were compared with national and state levels and state emissions targets. “For informational purposes” the Commission disclosed an estimate of the Social Cost of GHG associated with the reasonably foreseeable emissions from the project. The Commission explained that, in some past orders, the Commission has recognized that the measure of the social cost of GHG may have some utility in certain contexts such as rulemaking, the Commission has found that it is unable to determine credibly whether such emissions are “significant” or “not significant” in terms of impact on global climate change. The Commission claimed that, currently, there are no criteria to identify what monetized values are significant, and that the Commission is unaware of any scientifically accepted method to determine the significance of reasonably foreseeable GHG emissions. The Commission noted that the D.C. Circuit has repeatedly upheld the Commission’s decisions not to use the Social Cost of Carbon protocol, including to assess significance.
In an opinion dissenting in part, Commissioner Clements claimed that the order could be interpreted as a conclusion that the Social Cost of GHG is inherently unsuitable for determining the significance of GHG emissions associated with natural gas infrastructure projects. Further, Commissioner Clements stated that her inability to determine whether the Social Cost of GHG protocol, or any other tool, should be used to determine significance stems from the Commission’s failure to seriously study the matter; the Commission has yet to address the voluminous record in its GHG Policy Statement docket, which is where this important issue should be resolved.
2. Rio Grande LNG, LLC & Rio Bravo CP26-454-004
Pipeline Co., LLC
On April 17, 2023, the Commission issued an Order on Remand and Amending Section 7 Certificate concerning the Rio Grande LNG export terminal and the Rio Bravo Pipeline which will deliver gas to the LNG export terminal. The D.C. Circuit, in Vecinos para el Bienestar de la Communida Costera v. FERC, remanded the Commission’s orders authorizing the construction of the Rio Grande LNG, LLC proposed LNG export project and the proposed Rio Bravo Pipeline which would feed the LNG export terminal, directing the Commission to: 1) explain whether National Environmental Policy Act (NEPA) regulations call for the Commission to apply the social cost of carbon protocol or some other analytical framework generally accepted by the scientific community, when analyzing whether the project will have a “significant impact,” and if not, why not; 2) explain why it chose to analyze the projects’ impacts on “environmental justice communities” within two miles of the project sites, or else analyze impacts on such communities within a different radius of each site; and 3) revisit the public interest determination under section 3 and 7 of the Natural Gas Act (NGA). Separately, Rio Bravo filed to amend its pipeline project to reduce the number of compressor stations from three to one, increase the horsepower at the remaining station, increase the diameter of a pipeline, and increase the operating pressure of the pipelines (while maintaining the originally certificated capacity).
In approving the pipeline project amendment, the Commission found that the proposed modifications would improve the hydraulic efficiency of the pipeline and provide it with additional flexibility to meet the needs of its shipper, Rio Grande LNG, and that no adverse comments were filed by other pipelines or their captive customers. The Commission rejected claims that the Commission was required to reassess the whole Rio Bravo Pipeline project in a new Environmental Impact Statement (EIS), rather than assess just the impact of the proposed amendment in a less comprehensive Environmental Assessment (EA). The Commission explained that the original EIS fully considered the impacts of the Rio Grande LNG and the Rio Bravo Pipeline, so it is appropriate to limit the analysis of amendment to only those aspects of the pipeline project that would change. The EA determined that the impacts of the amendment would not be significant, and therefore, a detailed EIS was not required because the authorization would not constitute “major federal actions significantly affecting the quality of the human environment.” The Commission noted the EA concluded that there would be a marginal decrease in greenhouse gas emissions (GHG) attributable to the reduction in the number of compressor stations even though the amendment proposed increased compression at the remaining station. The Commission rejected claims that the EA did not fully consider, as an alternative to proposed amendment, the substitution of one of the two proposed Rio Bravo Pipelines with the use of capacity on Valley Crossing Pipeline, an intrastate pipeline, which another LNG terminal project (Annova Project) proposed to expand in capacity, but subsequently, the project was cancelled. The Commission found that there is no evidence that Valley Crossing Pipeline, which was fully subscribed by end users in Mexico, had been expanded in capacity in anticipation of service to the Annova LNG terminal, which means that only interruptible capacity would be available to Rio Grande LNG, and there is no evidence that Valley Crossing Pipeline, an entity not subject to the Commission’s jurisdiction, is willing or able to modify its facilities to provide sufficient capacity to be an alternative.
In addressing the Court’s remand issue concerning the use of the social cost of carbon protocol (updated to calculate the social cost of specific GHGs which include carbon dioxide, nitrous oxides, and methane), the Commission characterized the protocol as an administrative tool intended to quantify, in dollars, estimates of the long-term damage resulting from future emissions of GHGs. Although the Commission stated that it will include the social cost of GHG figures in its orders for informational purposes, the Commission has found that because this tool was not developed for project level review and does not enable the Commission to credibly determine whether the emissions are “significant,” for purposes of a NEPA review, the NEPA regulations do not require their use in certificate proceedings. Calculating the social cost of GHG’s does not enable the Commission to determine whether the GHG emissions are significant or not significant in terms of their impact on global climate change because there is no criteria to identify what monetized values are significant for NEPA purposes, and the Commission is not aware of any other currently scientifically accepted method that would enable the Commission to determine the significance of reasonably foreseeable GHG emissions. The Commission claimed that the D.C. has repeatedly upheld the Commission’s decisions not to use this tool, including to assess significance.
In addressing the remand on its environmental justice impact review, the Commission chose to reanalyze the LNG terminal project and the pipeline project based on an area of review that was expanded to the furthest estimated direct impact for each project site. For the LNG terminal, the area was expanded from a radius of two miles to 50 kilometers, which is a conservative estimate of the most distant of impacts, which is air quality impacts. The updated analysis of impacts on identified environmental justice communities addressed wetlands, recreational fishing, tourism, socioeconomics, traffic, noise, safety, air quality, greenhouse gases, and visual resources. The analysis for the Rio Bravo Pipeline project covered a 50-kilometer radius from the now single compressor station, and census block groups crossed by the pipeline. The Commission analyzed the impacts with respect to similar subject matter as listed above for the LNG terminal. The Commission concluded that impacts of both the LNG terminal and pipeline projects will be disproportionately high and adverse because they will be predominantly borne by environmental justice communities. The visual impacts of the LNG terminal were found to be potentially significant when the cumulative impacts of other projects in the area are considered. However, the Commission continued to find that the projects, as conditioned in the original certificate order and the instant order, are environmentally acceptable and required by the public convenience and necessity. The additional conditions require Rio Grande to prepare a “Project Ambient Air Quality Monitoring and Mitigation Plan” to address cumulative construction air quality impacts on environmental justice communities.
Commissioner Phillips issued a concurring opinion approving the way the Commission addressed the issues on remand. Commissioner Phillips particularly focused on the additional measure required regarding air quality monitoring and mitigation for the overlapping LNG terminal projects. Commissioner Phillips claimed that, on a broader level, this mitigation illustrates how the Commission is making progress on the critical issue of cumulative impacts, rather than just the impacts of the project, thereby helping to protect communities, including environmental justice communities, that may venture near the projects.
Commissioner Clements issued a dissent. Commissioner Clements stated that the Commission was required to issue a supplemental EIS and to hold public meetings to address the Commission’s new analyses of environmental and other impacts; the absence of these steps leaves the Commission with a fundamentally flawed record that cannot support a public interest determination for either the terminal or the pipeline project. Commissioner Clements noted that the reanalysis of environmental justice impact identified 367 new environmental justice communities not identified in the original analysis but did not provide these communities any meaningful opportunities to comment on the impacts and mitigation measures to minimize adverse impacts. The identification of hundreds of additional potentially affected communities constitutes, according to Commissioner Clements, significant new information “relevant to environmental concerns” that requires a supplemental EIS under NEPA regulations.
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3. Mountain Valley Pipeline, LLC CP16-10-000
On June 28, 2023, the Commission issued an order authorizing Mountain Valley Pipeline, LLC (Mountain Valley) to move forward on all remaining construction associated with its new interstate pipeline system. Mountain Valley was originally certificated on October 13, 2017, and substantial portions of the pipeline have already been built. However, numerous challenges to required federal permits have resulted in some permits being invalidated and not all of the invalidate permits have been reissued. The Commission has, accordingly, halted construction activity while the federal permits remain outstanding. On June 23, 2023, President Biden signed into law the Fiscal Responsibility Act of 2023. Section 324 of the Act not only ratified and approved all authorizations issued pursuant to Federal law necessary for the construction and operation of MVP, it superseded any other provisions of law, statute, regulation or judicial decision that are inconsistent with the issuance of any authorization or other approval for MVP. Accordingly, the Commission determined that MVP has all necessary authorizations to proceed with the remaining construction. The Commission also noted that its Order No. 871, which precludes construction while the Commission considers certain requests for rehearing, is not implicated by this order; therefore, construction can commence immediately and will not be halted by any rehearing request.
4. Transcontinental Gas Pipe Line Co. CP22-461-000
On July 31, 2023, the Commission authorized the construction and operation of Transcontinental Gas Pipe Line Co.’s (Transco) proposed Southside Reliability Project which primarily involves the installation of a new electric compressor unit at an existing compressor station and modifications to facilitate flow reversal at another existing compressor station in order to provide 423,400 Dth/day of new capacity which is subscribed by Piedmont Natural Gas Co. (Piedmont), a non-affiliated local distribution company.
In its determination that the there is a public need for the project, the Commission rejected a claim of insufficient evidence of need because the Commission must look behind the precedent agreement with Piedmont because Piedmont, on average, utilizes only 38.6% of contracted capacity on this part of Transco’s system. The Commission noted that the average utilization rate does not take into account the requirement of pipelines and their shippers to meet peak demand which is of particular importance to gas distribution companies.
In its greenhouse gas (GHG) emissions analysis, the Commission stated that construction, direct operational and downstream emissions (the emissions from the end-user burning gas) are “reasonably foreseeable,” and included estimates of tons of carbon dioxide equivalents of GHGs produced during construction, per year operational emissions, and “full-burn” downstream emissions. Unlike prior certificate orders, the Commission omitted discussion of the social cost of GHG metric for estimating the dollar value adverse impacts of the estimated GHG emissions of the project. The Commission rejected claims that upstream emissions are reasonably foreseeable and that the Commission must attempt to obtain information necessary to perform “reasonable forecasting.” The Commission acknowledged that courts have held that NEPA requires reasonable forecasting but countered that it is not required to engage in speculative analysis. The Commission claimed that the effects resulting from gas production are generally neither caused by a pipeline project nor are they reasonably foreseeable consequences of the Commission approval of a project, particularly where, as here, the supply source is unknown. The Commission declined to consider the project would induce additional production or utilize system-wide average data if specific sources cannot be determined because the impacts would be too speculative to be reasonably foreseeable.
In performing the NEPA analysis of project alternatives, the Commission provided a detailed comparison of an alternative of converting compression at a different compressor station to electric driven compression instead of installing additional compression at the existing station as proposed by Transco. The Commission found that adding compression at the alternative station would be less hydraulicly efficient and would require more horsepower and would result in more noise due to the higher compression. The Commission also found that construction at the alternative station would involve disturbing wetlands and adding compression to the alternative station would require construction of new electric transmission lines.
Chairman Phillips and Commissioner Phillips issued a concurring opinion concerning the social cost of GHG issue. They both support the Driftwoodlanguage, which they characterized as a compromise needed to get approval of gas infrastructure projects. However, in the interest of getting the instant project approved, they agreed to the removal of all discussion of the social cost of GHG and significance of GHG emissions from the order, and instead, moved the Driftwood language to this Joint Concurrence.
Commissioner Danly dissented in part. Commissioner Danly claimed that the Commission intentionally disregarded the Builder Act which was included in the recently passed Fiscal Responsibility Act of 2023. The Builder Act amended NEPA and required the Commissions environmental report to include certain specified findings on reasonably foreseeable environmental effects, range of alternatives, etc. Commissioner Danly stated that, regardless of how the Commission chooses to implement the Builder Act, the Commission must comply instead of pretending it does not exist. Commissioner Danly also claimed that the Commission violated the Administrative Procedure Act by failing to respond to the full scope of comments filed, specifically, comments by the EPA that upstream GHG can be estimated based on national averages as per interim guidance from the Council on Environmental Quality. Commissioner Danly claimed that instead of ignoring the comment and the interim guidance, the Commission should have responded by stating that the interim guidance is non-binding and the Commission is not adopting it because the Commission has repeatedly explained why upstream GHG emissions are not reasonably foreseeable and that upstream production and gathering are outside of the Commission’s jurisdiction and recent legislative enactments now supersede the interim guidance. Even more troubling, according to Commissioner Danly, is his colleagues’ insistence that downstream emissions from local distribution companies (LDC) are reasonably foreseeable. The instant order’s finding that the downstream emissions are reasonably foreseeable based on a full-burn calculation, is not, in Commissioner Danly’s opinion, reasoned decision making because the evidence clearly shows that Piedmont’s forecasted average annual consumption is only 38.6% of capacity. Commissioner Danly argued that it is impossible to find full-burn calculations to be reasonably foreseeable because this ignores how LDCs contract for capacity—they are legally obligated to serve customers at all times, so they contract to meet peak demand. Moreover, Commissioner Danly argued, just as the Commission claims it has no obligation to consider upstream GHG because upstream activities are non-jurisdictional, the Commission has no jurisdiction over LDCs who are regulated by the states.
Commissioner Clements issued a concurring opinion that criticized the Commission for including the Driftwood rationale regarding the significance of GHG emissions and use of the social cost of GHG protocol in all certificate orders, including those where intervenors did not raise GHG concerns. Commissioner Clements stated that the absence of this language in the instant order made it possible for her to issue a concurrence, but chided the Commission for not acting on issuing its GHG Policy Statement or otherwise studying how the protocol or other tools can be used to assess significance of GHG emissions. Commissioner Clements stated that in approving any project involving substantial GHG emissions, the Commission must prepare an Environmental Impact Statement (EIA) or risk a court overturning the Commission’s order for failure to explain why GHG emissions are insignificant and therefor properly addressed in an Environmental Assessment (EA). Commissioner Clements stated that having left the GHG Policy Statement docket dormant, the Commission would have no justification for finding GHG emissions insignificant, nor does the Commission have a framework for describing the significance of project-related GHG emissions in any EIS it does prepare.
G. Infrastructure-LNG
1. Freeport LNG Development, L.P. CP17-470-000
On February 23, 2023, the Commission issued an order on rehearing of the extension of time the granted to Freeport LNG Development, L.P. (Freeport LNG) to construct and make available for service its Train 4 Project (Project). The Commission’s 2019 certificate order authorized the construction of additional LNG liquefaction facilities and set a May 17, 20223 deadline to place the facilities into service. Freeport LNG sought, and was granted, two extensions of time to place the facilities into service. The latest request, which is the subject of this order, sought an extension to August 1, 2028, because Freeport LNG has not commenced construction due to delays related to replacement of its engineering, procurement, and construction contractor and continuing impacts of the COVID-19 pandemic on the global supply chain and global LNG demand. The Extension Order found that Freeport LNG made a good faith effort to meet the deadline and granted the extension.
As to claims that the extension order is a “major federal action” requiring National Environmental Policy Act (NEPA) review or a supplemental review to account for new developments regarding climate change, endangered species, and new information regarding Freeport LNG’s operations, the Commission found that this was not the case. The Commission claimed that an extension of time is not a major federal action nor is it a new approval; rather it is an administrative action that does not require additional NEPA review. As to claims that there is new information warranting new review, the Commission found this to not be the case. The Commission claimed that the “new information” concerning federal re-adoption of social cost of carbon modelling and announcements about federal greenhouse gas emissions targets constitute a collateral attack on the certificate order which already dealt with the effects at issue. With regards to new information about Freeport LNG’s intention to incorporate carbon capture and sequestration at its LNG terminal, the Commission found this to be speculative because Freeport LNG has not requested authorization on this matter. The Commission also found that, while an explosion at the Freeport LNG terminal was a serious matter, it caused no additional safety risks beyond those analyzed in the certificate order’s Environmental Assessment (EA). As for the recent listing of the Rice’s whale as a protected species, the Commission claimed that the EA concluded that this species is not found within the project area, and there has been no change in the project; without further indication that environmental impacts will go beyond what has already been considered, the listing of the Rice’s whale itself is not enough to trigger further Endangered Species Act consultation or additional NEPA analysis.
2. Cameron LNG, LLC CP22-41-000
On March 16, 2023, the Commission approved an application to amend the authorization to site, construct, and operate the Cameron LNG, LLC (Cameron) export terminal in Cameron and Calcasieu Parishes, Louisiana. Cameron currently operates three liquefaction trains to liquify gas for export as LNG. The Commission has also authorized an expansion to add a fifth LNG tank and two more liquefaction trains. The instant amendment application proposed to vacate the authorization for the fifth liquefaction train and the fifth LNG tank, resulting in a reduction of the total authorized output of capacity from 24.92 million metric tons per annum (MTPA) to 21.7 MTPA. The amendment application also proposed enhancements to Train 4 to reduce greenhouse gas (GHG) emissions and increase the reliability of Train 4, and sought authorization to add dual ship-loading capability to allow simultaneous loading and unloading of two LNG vessels at the same time.
The Commission declined to address economic claims (e.g., market demand for LNG), because such is relevant only to the exportation of the commodity of natural gas and this is exclusively within the Department of Energy’s (DOE) jurisdiction. Similarly, the Commission claimed that the impact of gas development and production are related to DOE’s authorization of the export and not the Commission’s authority over the siting of the export facilities. The Commission claimed that it did review the proposal and determine that it would not be inconsistent with the public interest and concurred with the findings in the Commission’s Environmental Assessment (EA) that the project would not significantly affect the quality of the human environment.
The Commission rejected claims that a more comprehensive Environmental Impact Statement (EIS) must be prepared, instead of relying on an EA, because the amendment project is part of, and relies on, infrastructure already in place, and the EIS should cover the entire four-train facility, as opposed to just the fourth train. The Commission noted that if it believes that its certification will not be a major federal action significantly affecting the quality of the human environment, an EA, rather than an EIS, will be prepared first, and depending on the outcome of the EA, an EIS may or may not be prepared. Here, the proposed changes were limited in scope and the facilities will be located within the footprint of the currently authorized terminal. As to the dual ship loading capability, the Commission claimed that the EA addressed this issue with its finding that Cameron’s proposal to enlarge the marine transfer area spill containment capacity will handle the worst-case spill. The Commission also adopted the EA’s finding that the proposal does not implicate any new air emissions and GHG impacts as these are expected to be reduced.
Commissioner Danly issued a concurring opinion. The Commissioner stated that the now draft Interim GHG Policy Statement should never have been issued and the proceeding should be terminated. He objected to the EA inclusion of calculations of the Social Cost of GHG because that metric is not used by the Commission to make any finding or determination regarding either the impact of the project’s GHG emissions nor whether the project is in the public interest.
3. Commonwealth LNG, LLC CP19-502-000
On June 9, 2023, the Commission issued an order addressing arguments on rehearing of the Commission order authorizing Commonwealth LNG, LLC (Commonwealth) to site, construct and operate a natural gas liquefaction and export facility, including a Natural Gas Act (NGA) section 3 gas pipeline, in Cameron Parish, Louisiana.
The Commission rejected claims that it failed to articulate a coherent standard for the exercise of NGA section 3 authority, by relying on the Department of Energy’s (DOE) authorization of the export of natural gas to nations with which the United States has a free trade agreement, in balancing the benefits and harms of the Commonwealth project. The Commission found that the Authorization Order properly recognized that section 3 provides that the application shall be approved if the Commission finds that the proposal will not be inconsistent with the public interest and that this sets out a presumption favoring such authorization; courts have said this means there must be an affirmative showing of inconsistency with the public interest for the Commission to deny authorization. The Commission stated that its staff prepared a comprehensive Environmental Impact Statement (EIS) that found that although there would be some permanent and significant impacts on visual resources, most impacts would not be significant or would be reduced to less than significant levels with mitigation and avoidance measures recommended by the EIS. The Commission concluded that the presumption has not been overcome because the Commission adopted the conditions recommended by the EIS and the Commission did not rely solely on the DOE export authorization.
The Commission sustained its National Environmental Policy Act (NEPA) review of project alternatives. For the “no-action alternative” (meaning not authorizing the project), the Commission noted that an agency does not err by rejecting a no-action alternative that would not fulfill the project’s purpose. The Commission claimed that the EIS contemplated a “no-build” scenario where Commonwealth’s objective of liquefying and exporting natural gas would not be realized, but under this scenario, end users of LNG would be required to make different arrangements and the Commission is unable to speculate that any portion of liquefaction capacity at other LNG terminals would be available to meet the demand of the Commonwealth customers because DOE’s export approval at other terminals was to satisfy other demand and the Commission cannot conclude that increase in capacity elsewhere would not replicate the environmental impacts of the project. The Commission also sustained the EIS’ determination on alternatives to specific aspects of the project’s design, such as the type of liquefaction process used (rejection of a more efficient process because it would require a larger footprint that would impinge on wetlands and an endangered species habitat), use of combined-cycle electric generators to reduce emissions (Commission agreed with EIS conclusion that this alternative would not provide a significant environmental advantage; disagreement with this determination does not undermine the fact that the Commission considered the alternative and NEPA does not require anything more than a reasonable explanation), and carbon sequestration (EIS found no nearby sequestration projects except one that will serve another LNG export project).
On the issue of greenhouse gas emissions (GHG), the Commission claimed that the Commission’s NGA and NEPA responsibilities are separate and distinct. With respect to the NGA, the Commission again referred to its balancing of public interest under NGA section 3, as discussed above, and added that the Commission is not required to characterize the project’s estimated GHG emissions as significant or insignificant and no court has held to the contrary. As to NEPA requirements, the Commission claimed that although it did not characterize the emissions as significant or insignificant, the Commission disclosed and contextualized reasonably foreseeable emissions (compared emissions to national and state emissions and state goals) and claimed that there are no accepted tools or methods for the Commission to determine significance. The Commission cited court decisions affirming the Commission’s decision to not analyze the Social Cost of Carbon in its NEPA analysis.
The Commission rejected a claim that, pursuant to NEPA regulations, the approval of Commonwealth’s project is a “connected action” with the pending DOE approval of non-free trade agreement exports from the project, thereby requiring a new EIS covering both. The Commission claimed that the proposal before the Commission is to site, construct and operate the LNG facilities, the export license is before DOE, and because DOE has the sole authority to license the export, there are no connected action factors to apply in this case. In any event, the Commission noted that DOE has already authorized the export of the project’s full capacity to free trade countries such that this entire capacity may be statutorily deemed to be in the public interest, and therefore, the DOE’s pending authorization to export to non-free trade agreement countries is not a connected action because the project does not depend on the additional DOE authorization.
Commissioner Danly issued a concurring opinion. Commissioner Danly stated that the Supreme Court has explained that “public interest” in the NGA is not a broad license to promote general welfare, but instead, takes meaning from the purpose of the regulatory legislation, which is “‘to encourage the orderly development of plentiful supplies of…natural gas at reasonable prices.’” This public interest meaning and the NGA section 3 public interest presumption applicable to exports to free trade agreement countries means that the Commission “need not confect complicated rubrics or analytical frameworks to arrive at its determinations.”
Commissioner Clements issued a dissenting opinion. Commissioner Clements characterized the discussion of balancing of public interest under NGA section 3 as “opaque,” and criticized the footnote reference to NAACP v. FPC, as purporting to show that the purpose of the NGA is to promote gas supply development when that opinion also identifies environmental protection as a subsidiary purpose. Commissioner Clements claimed that both the NGA and NEPA require the Commission to consider climate and other environmental impacts when approving a project and this means that the two statutes are inextricably linked. Commissioner Clements also criticized the Commission’s conclusion that it is impossible to assess the significance of GHG emissions, and in particular, “concentrating its fire on the Social Cost of GHG protocol.” Commission Clements argued that NEPA regulations require an analysis of the significance of GHG impacts, that disclosing and contextualizing reasonably foreseeable GHG emissions does not substitute for analysis, and this defect renders the Commission determination arbitrary and capricious.
4. NF Energia LLC CP23-518-000
On July 31, 2023, the Commission authorized the construction of a 220-foot pipeline from an existing LNG terminal at the Port of San Juan, Puerto Rico, to a U.S. Army Corps of Engineers’ emergency temporary generation project. NF Energia LLC filed the application with the Commission on July 19, 2023, as a Natural Gas Act (NGA) section 3 application. The emergency generation project is scheduled to be brought online by August 15, 2023, in order to limit potential hurricane-related impacts on the island.
In granting the authorization, the Commission admitted that there is no explicit statutory authority for the Commission to issue the section 3 authorization. However, the Commission claimed that given the involvement of the multiple other federal agencies in an effort to protect the Puerto Rican electric grid during the upcoming heart of the hurricane season, the Commission will not take action to prevent the immediate construction and operation of the proposed facilities.
Commissioner Danly issued a dissenting opinion. Commissioner Danly claimed that the Commission should have disclaimed jurisdiction over the facilities and simply gotten out of the way and allowed Energia LLC to build the desperately needed infrastructure unimpeded. One of the consequences of granting the authorization, according to Commissioner Danly is that, having asserted jurisdiction, the Commission ignored the requirements of the Administrative Procedure Act and the National Environmental Policy Act (NEPA) which requires the preparation of an environmental document. Commissioner Danly stated that the Commission’s action leaves the applicant in jeopardy, because if challenged, the Commission’s order will be remanded or worse yet, vacated.
H. Abandonment
Stingray Pipeline Co. CP20-528-000
CP20-529-000
On June 15, 2023, the Commission issued an order authorizing Stingray Pipeline Co. (Stingray) to abandon various offshore facilities by sale to an affiliate, Triton Gathering LLC (Triton) and to abandon in place other facilities, and a determination that the facilities acquired by Triton would function as non-jurisdictional gathering facilities exempt from Commission regulation, the abandonment of other on-shore and off-shore facilities to Triton for Triton to convert to crude oil transportation, and the abandonment of its Natural Gas Act section 7 certificate and authorizations to provide transportation service and cancellation of its gas tariff. In support of its application, Stingray claimed that current average throughput is about 1.2% of certificated capacity, that throughput on the system that it proposes to sell to Triton to operate as gathering has fallen from 6,771 Dth/day in 2018 to 16 Dth/day in 2022, and that total revenues in 2022 have fallen to $72,696 as compared to operation and maintenance expenses of $3,314,007.
In considering abandonment requests, the Commission stated that the primary factors it examines are: 1) the needs of the affected gas systems and the public markets they serve; 2) the economic effect on the pipeline and their customers; and 3) the presumption in favor of continued service (the primary consideration is continuity and stability of existing service). The Commission found that the proposed re-routing to allow another offshore pipeline to offer service means continuity of service can be maintained. As to Stingray maintaining the service, the Commission noted that even with substantial discounts, Stingray has not been able subscribe service and costs are likely to exceed revenues in the future; under these circumstances, the Commission will not require Stingray to maintain and operate facilities awaiting firm demand that may never materialize.
The Commission also determined that the facilities to be abandoned to Triton to be operated as gathering facilities will qualify as such when Triton acquires the facilities and attaches the facilities to its system. The Commission also stated that it looks into whether the rates to be charged to the customers receiving service after abandonment will increase. Here, the Commission found that Triton will charge both firm and interruptible customers the same discounted rate Stingray charged, and that Triton will pay for the facilities needed to re-route certain gas onto another pipeline.
I. Miscellaneous
Columbia Gas of Virginia CP23-77-000
On August 30, 2023, the Commission issued a blanket certificate of limited jurisdiction to Columbia Gas of Virginia (Columbia-Virginia) to sell or transport gas in interstate commerce. Columbia-Virginia is a local gas distribution company located in Virginia. Columbia Gas states that its system qualifies for an exemption under Natural Gas Act section 1(c) because (1) Columbia-Virginia receives all its within the boundaries of the state; 2) all of the gas is consumed in the state; and 3) and its rates, services and facilities are subject to regulation by a state agency. Columbia-Virginia’s application states that it is engaged in discussions with a renewable natural gas (RNG) producer who wishes to deliver gas to its distribution system. While all the RNG would be physically transported and likely consumed in Virginia, the arrangement would involve transportation on interstate pipelines, displacement, or exchanges that would involve gas that would be consumed outside of Virginia. Columbia-Virginia sought, pursuant to section 284.224, a blanket certificate to engage in interstate sales and transportation. Columbia-Virginia elected to use rates approved by the Virginia State Corporation Commission for services it provides in Virginia rather than have the Commission determine a cost-based rate. Columbia-Virginia also proposed to use rate trackers for such costs as modernization costs (infrastructure replacement costs) and sought Commission permission to not make tariff filings unless the changes accumulate to more than a 10% increase.
The Commission granted the blanket certificate application, finding that Columbia-Virginia’s primary role will continue to be that of a state-regulated local distribution company, that its application for a limited jurisdiction certificate to provide interstate service meets the requirements of 284.224, and accordingly, that its proposal is in the public convenience and necessity. While recognizing that the proposed rate tracker is not included in the Commission’s regulations of rates for this service, the Commission found that the proposal meets its requirements; the Commission noted that, pursuant to its regulations, Columbia-Virginia is required to have its rates reviewed within five years.
