B. Court Cases
BP America, Inc.
On October 20, 2022, the Fifth Circuit sustained the Commission's finding that BP engaged in market manipulation in violation of the Commission's regulations, but, remanded to the Commission to calculate an appropriate penalty after finding that the Commission has jurisdiction only over transactions directly regulated by the Natural Gas Act ("NGA") and did not have jurisdiction over any gas transaction, including intrastate transactions, which affect the price of NGA-jurisdictional interstate transactions. Prior to Hurricane Ike's arrival in September of 2008, BP had amassed a significant financial spread, the value of which was determined by the difference in gas prices between Henry Hub, a major gas market in Louisiana, and the Houston Ship Channel ("HSC"), a hub in Houston. When Ike hit, the prices at HSC plummeted and BP realized a sizeable profit. BP realized it could make millions more if the differential persisted. BP held transportation rights on the Houston Pipeline ("HPL"), which is an underutilized pipeline, and after the hurricane struck, BP used the pipeline to deliver natural gas to the HSC to create a glut, thereby lowering the prices at HSC. The scheme went undetected until one of the traders disclosed it to higher up management which then reported it BP's internal compliance team, which reported it to the Commission. The Commission's investigation found that following Ike, BP changed its trading behavior at HSC by selling more gas to HSC, even when doing so was unprofitable, in order to realize bigger profits from its spread position. The Commission concluded BP engaged in market manipulation and ordered BP to pay a civil penalty of $20 million.
BP challenged the Commission's order claiming that its jurisdiction extends only to interstate activity and none of the transactions at issue were transactions in interstate gas regulated under the Natural Gas Act ("NGA"). The Court found that the language of the NGA, and subsequent court precedent establishes a clear division of regulatory power over the natural gas industry, with the Commission having authority over interstate transaction, but no authority over intrastate transactions. The Commission argued that while not all of the transactions were interstate transactions directly subject to the NGA, they were a part of BP's manipulative scheme that are subject to the anti-manipulation provisions of the Energy Policy Act of 2005, which amended the NGA to provide that:
It shall be unlawful for any entity, directly or indirectly, to sue 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 or deceptive device or contrivance. . .
The Commission argued that this provision gives it jurisdiction over any natural gas transaction that is part of a manipulative scheme, so long as that scheme affects the price of an NGA-jurisdictional transaction. The Court disagreed. The Court was not satisfied that the single statutory phrase "in connection with" can "bear the weight" of overturning the explicit division drawn between interstate and intrastate transaction, and that phrase cannot mean any connection whatsoever, regardless of how indirect or tenuous. Although the Commission did not assert that any of BP's transactions directly involved the purchase or transportation of natural gas across state lines, the Court found that the Commission convincingly demonstrated that some of the transactions involved gas that had been transported in interstate commerce under the NGA. The Court found that BP had not challenged the Commission's findings that once gas is sold or transported in interstate commerce it remains interstate gas thereafter.
As to the finding that BP engaged in market manipulation, the Court found the Commission's conclusions to be reasonable. The Court found that the Commission drew reasonable conclusions when comparing BP's behavior before the hurricane struck and the behavior thereafter to conclude that BP was manipulating the market. Particularly, the Court found that the statistically significant relationship between BP's transport decisions to bring gas to HSC using HPL and price differentials at HSC prior to Ike and the indifference to the price at HSC after Ike struck, to be compelling. As to establishing intent to manipulate, the Court found that the Commission's showing of changed behavior--by transporting more gas to HSC, selling more, and selling at a time calculated to maximally influence market price--established intent, and this was further buttressed by recorded conversations between BP employees which cast doubt on the trading strategy being compliant.
In light of the Court's finding that not all of the transactions were jurisdictional, the Court found it proper to remand to the Commission for reassessment of the penalty.
C. Rate Cases
1. MountainWest Overthrust Pipeline, LLC RP22-1118-000
On September 22, 2022, the Commission issued an order instituting a Natural Gas Act §5 investigation into whether Overthrusts currently effective rates are unjust and unreasonable because Overthrust is over-recovering its cost of service. Based on FERC Form 2 annual financial reporting for 2020 and 2021, the Commission estimated that Overthrust return on equity was 34.1% in 2020, and 30.5% for 2021. As with prior §5 investigations, the Commission required the pipeline to file a detailed cost and revenue study.
On December 20, 2022, the Commission issued an order dismissing Overthrust's request for rehearing. Because the investigation order made no final determination of the justness and reasonableness of Overthrust's current rates, and because it is just a procedural step in an investigation, the Commission determined that it is not a final order subject to rehearing. However, even if rehearing were appropriate, the Commission noted that courts have recognized the Commission's wide discretion to decide whether to investigate a pipeline's rates and to employ a requirement to file a detailed cost and revenue study in carrying out its investigation. The Commission clarified that Overthrust may complete the various statements in the study using the cost allocation and rate design methods underlying its existing rates without taking any position as to its preferred allocation and rate design methodology, thus, the study will not be used as evidence of the pipeline's preferred methodology.
2. Transcontinental Gas Pipe Line Co. RP21-1143-000
On October 27, 2022, the Commission granted Transco's request for authorization to charge market-based rates for firm and interruptible storage at its Washington Storage Field ("WSF")located in St. Landry Parish, Louisiana. In its application, Transco claimed that the geographic market for the WSF is the Gulf Coast Production Area (eastern Texas, Louisiana, Mississippi and Alabama) and that its market share in this area for working as is 1.6% and for daily deliverability is 2,8% and this is below levels that raise market power concerns and are substantially lower than the market share of other applicants whom the Commission has granted market-based rate authority. Transco claimed that the market concentration metric, as measured by the Herfindahl-Hirschman Index ("HHI"), are 254 for working gas capacity and 365 for daily deliverability, which is well below the 1,800-threshold adopted by the Commission to indicate a potential market power concern.
In applying its Alternative Rate Policy Statement framework, the Commission determines if the pipeline has market power over a service in the relevant marketplace; market-based rates will be approved if the applicant lacks market power or has adopted conditions that mitigate market power. Transco's market power study identified the relevant product market to include other interstate and intrastate underground storage facilities and local production in the Gulf Coast Production Area. The Commission agreed with Transco's study, finding that the Washington Storage Field is directly connected to other interstate pipelines and facilities that the Commission has identified to be in the Gulf Coast Production Area and that this storage field has been routinely accepted by the Commission in other analyses as a competitor in this market area. The Commission found that Transco demonstrated that there are good alternatives in this market, including other storage facilities and local gas production. The Commission rejected claims that only production directly connected to Transco meet the requirement for "good alternatives" because the Commission has never imposed such a restriction, and in this case, direction connection is irrelevant because Transco is not offering upstream or downstream pipeline transportation from this facility; any customer of the storage facility will have to arrange and have its own transportation capacity to use this storage facility. The Commission found that the price, quality and availability of local production makes it a good alternative. The Commission determined that even if the analysis were adjusted to remove storage and local production alternatives that protestors claimed should not be considered as good alternatives, Transco's market share would still be low and that the HHI figures would not rise to the 1,800 HHI threshold that raises market power concerns.
As to claims that granting market-based rates would cancel the right-of-first-refusal ("ROFR") that existing customers have under existing service, the Commission stated that the ROFR requires the existence of a maximum rate, and that maximum rate is a guard against market power of the pipeline; if the pipeline lacked market power, then the market, not the maximum rate, ensures that the pipeline's rates are just and reasonable, and ROFR is not applicable where there is market-based rate authority.
3. Panhandle Eastern Pipe Line Co. RP19-1523-000
On December 16, 2022, the Commission issued an order affirming in part and reversing in part an Administrative Law Judge's Initial Decision ("ID") on a Natural Gas Act (NGA) §4 rate increase filing by Panhandle that arose out of a Commission §5 investigation of the justness and reasonableness of Panhandle's rates. The Commission found that the ID correctly adopted Panhandle's actual capital structure. However, the Commission required an adjustment to the equity component based on various accounts related to deferred taxes that were affected by the lowering of the corporate income tax rate in 2017 and the determination that master limited partnership pipelines, like Panhandle, would no longer be permitted to recover an income tax allowance in its cost of service. The rate of return on equity ("ROE") was determined pursuant to the May 21, 2020 ROE Policy Statement. Since the 1980's the Commission has determined ROE using the "Discounted Cash Flow" ("DCF") model, but the ROE Policy Statement provided that, in addition to the DCF model, an alternative Capital Asset Pricing Model ("CAPM") would also be employed. The proxy group consisted of four energy companies. In adopting the proxy group approved in the ID, the Commission determined that while some companies did not meet certain standards for inclusion, such as 50% of income or assets being in the pipeline business, examination of other factors established by Commission precedent, and its determination that "flexibility" is warranted in order to have a group comprised of four members. The Commission rejected Panhandle's argument that data from the six-month period ending in January 2020 should be used in favor of a period ending in May 2020, because of anomalous impact of the Covid pandemic on the later period's short-term growth projections. The Commission cited its strong preference for using the most recent data in the record and also noted that the temporary reductions in stock prices did not depress ROE because the declining stock prices caused dividend yields of the proxy group to increase. Averaging the DCF and CAPM results, the Commission arrived at an ROE of 11.25%. The Commission also determined that Panhandle failed to overcome the presumption that its allowed ROE should be set at the median of the proxy group; the fact that Panhandle had to discount its rates to meet competition was not a sufficient basis to increase its allowed ROE and the Commission's rejection of discount adjustments for four contracts merely reflect the Commission's finding that Panhandle failed to demonstrate that the discounts were necessary due to competition.
The Commission analyzed the contracts for which a discount adjustment was sought by Panhandle. The Commission found that discounted rate contracts that expired outside of the rate case test period and renewed at the maximum rate were properly included in the discount adjustment because taking post test period changes into account is inconsistent with the Commission's test period ratemaking methodology which recognizes that, as time passes, costs, revenue, and other factors change so that it is best to take a picture of the company's operations at a single, consistent point in time. The Commission noted that although Panhandle replaced discounted rate contracts with maximum rate contracts a few months outside of the test period, Panhandle may also be required to offer other discounted contracts in the future that cannot be predicted during a rate case. The Commission disallowed discount adjustments for contracts where Panhandle provided only a general statement in its testimony that the discount to a non-affiliate was intended to meet competition and where the customer made a claim in the proceeding that it had competitive options, because the Commission found that such evidence was insufficient to carry Panhandle's burden--the customer's statement was not contemporaneous evidence produced at the signing of the contract. As to a contract included in the discount adjustment by the ID, based on a finding that Commission staff failed to meet its burden in raising a reasonable concern about the legitimacy of the discount adjustment, the Commission found that the ID overstated Commission staff's burden which was satisfied by pointing out that Panhandle offered no evidence that competition required such a long-term discount (contract first negotiated in 2005). The Commission stated that--where a discount adjustment is challenged--all parties have an opportunity to seek discovery and a pipeline's inability to explain why competition required a particular discount is enough to raise a question that shifts the burden to the pipeline to justify the discount; with the burden shifted back to Panhandle, the Commission found that Panhandle failed to introduce sufficient evidence and analysis to show that competition required it to grant those discounts.
On depreciation issues, the Commission rejected the ID's adoption of a 40-year remaining economic life of Panhandle and accepted the pipeline's proposed 35-year economic life. The Commission cited Energy Information Administration projects for gas demand for the next 30 years and the participants in the Panhandle proceeding agreeing that there is sufficient demand to sustain Panhandle through 2050 and the Commission's prior findings in other proceedings of a 35-year life for other pipelines as supporting a 35-year life determination. The Commission sustained the ID's determination that Panhandle's reliance on Office of Management and Budget's guidance on depreciation practices (generic average service life) was an insufficient basis for changing the depreciation of general plant and that Panhandle should have provided evidence of the average remaining physical life of its own system, and accordingly, the prior determination of the depreciation rate remains in effect. The Commission sustained the ID's denial of an interim negative salvage rate. The Commission found that Panhandle provided insufficient data to support its calculations because it provided only six years of retirement cost data which is not representative or reflective of long-term trends. As to Panhandle supplementing this data with 48 years of Form 2 annual report data, the Commission found that this data provided data only on the amounts removed from plant accounts upon retirement of an asset but did not include information on costs incurred when removing plant, offset by proceeds from plant that is sold or reused. As to the negative salvage rate for "terminal decommissioning" (at the end of the life of the system), the Commission affirmed the ID's rate based on the detailed study supplied by Panhandle and the lack of any counter analysis challenging the study. However, the Commission found that this rate must reflect only assets projected to remain in service at the end of its useful life, meaning that Panhandle must exclude assets that it projects to retire prior to the end of its useful life; Panhandle has not demonstrated that all plant retired in the interim will be replaced and therefore subject to terminal decommissioning.
The Commission sustained the ID's determination that Panhandle failed to demonstrate that its proposed rate increase of 150% to small customers is just and reasonable. The Commission noted that Panhandle's small customer service represent less than 1% of Panhandle's volumes in its market area and that Panhandle has not indicated a change in circumstance that reflects the need for a dramatic shift in rates, such as undue harm to the pipeline, to justify the significant impact on small customers compared to other customers.
The Commission affirmed the ID's finding that Panhandle did not meet its burden to justify a proposed increase in system storage (i.e., the allocation of more storage capacity, and associated cost, to storage used to support the pipeline's operation). The Commission found that the Panhandle's reliance on very high storage utilization factors and peak hourly demand levels observed on a January 30, 2019 peak day is based on figures that do not appear to be sourced from any data in the record, and that only monthly average figures are present in the record because, by Panhandle's admission, it does not keep records of daily utilization factors. The Commission rejected Panhandle's estimation of that peak day utilization based on projected demand instead of actual data. The Commission found other methodologies employed by Panhandle to support its claimed usage of storage on a peak day to be insufficient support for its proposed storage allocation. While acknowledging Panhandle's argument that requiring it to reduce its system storage level could potentially result in failure to deliver firm gas volumes on its system, the Commission noted that Panhandle retains its rights under NGA §4 to file a more fully supported study to justify its proposed level of system storage in a future rate proceeding.
Panhandle has a contract for storage service from an affiliate, Southwest Gas. Southwest Gas provides this service to Panhandle under a negotiated rate agreement. In determining what rates regarding this service Panhandle can include in its cost of service (and thereby pass through the cost to Panhandle's customers), the ID found that the maximum rate in a 2019 Southwest Gas settlement ("2019 Settlement Rate") should be used in lieu of the rates set forth in the negotiated rate agreement itself. The Commission sustained this determination finding that Panhandle has not shown the costs of the negotiated rate agreements are just and reasonable for inclusion in Panhandle's cost of service while the 2019 Settlement Rates are the most accurate valuation of Southwest Gas' services contained in the record. Given the affiliate relationship with Southwest, the Commission found that Panhandle had failed to carry its burden of showing that it would be reasonable to pass along the cost of the negotiated rate to its shippers. The Commission agreed that Panhandle had an incentive to lock in the higher rate in anticipation that the Commission would reduce Southwest Gas' rates through an NGA §5 proceeding. The Commission found Panhandle's evidence that the negotiated rate was similar to the rates of other storage agreements unpersuasive because it merely consisted of a list of storage contracts, the majority of which expired before the negotiated rate contract was executed, and it did not show that the storage providers listed offered comparable service. Moreover, the Commission found that whether the rate was competitive is not the sole relevant factor here because Panhandle had an incentive to contract with its affiliate regardless of the competitiveness of the rate. Similarly, with respect to a storage contract with Bammel and related transportation from Trunkline, which replaced a less expensive expiring arrangement with DTE/Washington 10, the Commission sustained the ID's finding that the rejected renewal offer from DTE/Washington 10 should be substituted for purposes of calculating Panhandle's cost of service because contracting with Bammel/Trunkline was motivated by the benefits of the transaction for affiliates and for the parent, Energy Transfer. The Commission cited a document comparing the pros and cons of the two alternative arrangement and found that most of the listed pros for the Bammel/Trunkline arrangement were actually benefits to other companies in the Entergy Transfer family while the pros for the DTE/Washington 10 were benefits to Panhandle and its customers. The Commission noted that Panhandle has not provided further evidence of contemporaneous considerations supporting operational benefits of the Bammel/Trunkline arrangement.
The ID found that Panhandle was unduly preferential in resolving pipeline to pipeline imbalances via an Operational Balancing Agreement ("OBA") with Trunkline, an affiliate, as compared to non-affiliated pipelines. The ID found that imbalances under the Trunkline OBA were significantly higher in absolute value than the imbalances with non-affiliates. The ID also found concerning the suggestion that the imbalances under the Trunkline OBA may have caused Panhandle to purchase additional storage services thereby increasing Panhandle's cost of service. The remedy the ID adopted was the requirement to reform Panhandle's OBAs to include language that a mutual waiver of the 30-day deadline for resolving outstanding balances can be sustained only if the parties are unaffiliated; otherwise, prior Commission notice and approval will be required. The Commission reversed the ID's findings because the NGA §5 burden of showing unduly discriminatory and preferential behavior was not sufficiently supported. Specifically, the Commission noted that the Trunkline/Panhandle point is a bi-directional interconnection that has been a historically major source of supply into Panhandle's system which explains why imbalances are larger at times than at other points, and that the record did not show that Panhandle refused to waive the deadline for resolving imbalances with parties to other OBAs.
4. El Paso Natural Gas Co. RP19-73-006
On January 31, 2023, the Commission approved a rate settlement resolving all issues arising out of the Commission's April 21, 2022, order instituting an investigation, pursuant to section 5 of the Natural Gas Act, into El Paso's existing rates. The investigation was prompted by a cost and revenue study filed by El Paso under the terms of a 2019 rate settlement. This new settlement provides for a 16% reduction (on average across mainline rate zones) of El Paso's maximum reservation rates to be phased in over three years. The settlement also requires El Paso to file a cost and revenue study on October 1, 2027.
Commissioner Danly issued a concurring opinion. As in previous rate settlement orders, Commissioner Danly raised his concern over the common practice of including an attachment to the settlement that lists parties who support or do no oppose the settlement rather than having the parties actually execute the settlement document. Commissioner Danly stated that a situation will almost certainly arise in which an entity's status as a party or non-party will be dispositive and this will be "even more important should the issue be presented to a body less indifferent to fundamentals of contract law than this Commission."
D. Major Tariff/Service Issues
1. Energia Axteca X, S.A. de C.V. v. RP22-1266-000
North Baja Pipeline, LLC
On October 21, 2022, the Commission denied a complaint by Energia alleging that North Baja failed to comply with its tariff in providing adequate notice to shippers regarding maintenance and curtailment of service, failing to consult with shippers impacted by curtailment, and failing to establish that its proposed actions were operationally necessary. North Baja provided notice on August 3, 2022, of partial and complete curtailment of service for various periods of time starting on October 1, 2022, in order to do work on an expansion project. Energia's complaint argued that the notice was inadequate, and that North Baja failed to operationally justify the significant curtailments and requested that the Commission order North Baja to suspend and postpone the planned operations and convene a meeting with its shippers to determine a new schedule for curtailment. The Commission denied the protest, finding that North Baja acted reasonably within its tariff by providing notice soon after the construction schedule was finalized for the expansion project. The Commission found that North Baja did not violate its tariff provision on providing a schedule of maintenance in the spring of 2022, because it updated the maintenance schedule as soon as it finalized the construction schedule, and because its tariff does not require the pipeline to include every potential curtailment or operation that could impact service within the next year, include impacts relating to unknown construction activity. The Commission also found that North Baja did not violate its tariff by failing to establish that the proposed operations are operationally necessary; the tariff does not require a justification for each curtailment or interruption of service and the tariff gives the pipeline reasonable discretion to determine when curtailment should occur.
2. Eastern Gas Transmission and Storage, Inc. RP21-1187-008
On November 18,2022, the Commission issued an order on rehearing of a prior order finding certain aspects of Eastern's reservation charge crediting tariff provisions to unjust and unreasonable. Certain minor aspects of Eastern's reservation charge crediting provisions were protested in Eastern's Natural Gas Act ("NGA") section 4 rate case, and the Commission acted under NGA section 5 to require changes to these provisions. The July 2022 Order found unjust an unreasonable the requirement for shippers to continue to make daily nominations even when advance notification of an outage means that the shippers know that their nominations will not be honored. The Commission reasoned, in prior orders as well, that the shippers should be permitted to focus on obtaining alternate supply routes and not on submitting nominations that they do not expect the pipeline to honor. The July 2022 order also required changes to the method of measuring the amount of credit a shipper will receive when an outage is known in advance. The Commission found that Eastern's tariff failed to account for instances where historical usage may have been constrained by an outage in the prior year. In its rehearing request, Eastern claimed that, given how rare are outages on its system (two days in 2020 and one day in 2019, the Commission failed to demonstrate that its provisions no longer serve their basic purpose. Eastern claimed that it must receive nominations, even in the event of total outages, to have the opportunity to perform its contractual obligation (e.g., Eastern may have "back up methods of providing firm service" even during a total outage). Eastern also argued that rather than requiring the pipeline to suggest replacement tariff language, the Commission was required to devise and support its own language to meet its NGA section 5 burden of showing that the tariff provision it seeks to change is unjust and unreasonable and that any replacement tariff provision is just and reasonable.
The instant order rejected Eastern's arguments. The Commission found that it does not matter if the situation the tariff provision addresses is likely to be infrequent; tariffs regularly allocate risks for infrequent force majeure events, and the Commission does not have to be purely reactive, waiting for a tariff provision to be triggered a specific number of times before finding it to be unjust and unreasonable as written. As to the claim that Eastern requires nominations because it may be able to deliver gas during a total outage, the Commission found that, by definition, a total outage means it cannot perform its obligations, and anything less is a partial outage for which Eastern can require nominations. The Commission further clarified that, to the extent Eastern is describing the ability to provide secondary service rather than primary service, this would not be providing the contracted firm service. The Commission found that there is no rationale for requiring nominations during total outages beyond creation of a formalistic hoop to obtain reservation credits, and thus, even the slightest burden caused by requesting nomination is inherently an unreasonable burden. The Commission also disagreed that it was required by NGA section 5 to devise its own replacement tariff language rather than proving Eastern with an opportunity to propose revised language. Once replacement language was found to be necessary, the Commission has broad flexibility in deciding the procedure, including whether to solicit proposed language. The Commission could have proposed language, which Eastern might find more undesirable than its own proposal but opted to provide Eastern with a framework and an opportunity to propose specific language to remedy the issues.
Commissioner Danly issued a dissenting opinion. He questioned the Commission's use of NGA section 5 authority to correct what amounts to mere annoyance.
3. Eastern Shore Natural Gas Co. RP23-180-000
On December 9, 2022, the Commission accepted Eastern Shore's tariff change filing which adds a new section to the tariff to provide Eastern Shore with authority to conduct operational purchases and sales of natural gas to maintain system pressure and line pack, manage system imbalances, manage system use and lost and unaccounted for gas over and under recoveries, and perform other operational functions. As to a claim that the proposed section provides for a posting of a notice for the sale of gas, but no requirement for the posting when Eastern Shore seeks to purchase gas, the Commission did not require a revision because the Commission has previously held that all operational sales of gas must be posted and subject to bidding, but its precedent does not require pipelines to post operational purchases for bid. As to a claim that Eastern Shore should be required to add an obligation to sell or buy gas at the best price offered, at least if an affiliate is involved in the transaction (an affiliate is Eastern Shore's largest customer), the Commission rejected the proposed revision because any shipper will be able to see the criteria used in selecting bids, because that information will be posted; and information in the annual report of operational purchases and sales will allow anyone to evaluate the transaction to determine compliance with the Commission's rules of conduct to prevent affiliate favoritism. The Commission also rejected a proposed revision that would clarify that the "source" of gas reported in the annual report be the specific entity the gas was received from because, other pipelines report the source of gas to be excess fuel retainage, excess gathering or products extraction gas, and as such, source may not be a specific entity. The Commission required Eastern Shore to make one addition to the type of information included in the annual report, which is, an explanation of the purpose of any operational transaction.
E. Infrastructure--Natural Gas
1. Owen Stanley Parker v. Permian CP22-451-000
Highway Pipeline LLC
On September 22, 2022, the Commission denied a complaint alleging that the Permian Highway Pipeline is an interstate natural gas pipeline that was built without authorization from the Commission in violation of section 7 of the Natural Gas Act ("NGA"). Permian, which is a 430-mile long pipeline located entirely in Texas, was constructed in 2020 as an intrastate pipeline. After providing service as an intrastate pipeline for more than a month, the pipeline began providing interruptible and firm interstate service pursuant to section 311 of the Natural Gas Policy Act of 1978 ("NGPA"). Complainant alleged that all but one of twelve pipelines supplying Permian transport interstate gas (the gas does not need to cross a state border to be interstate gas-- if the destination is across a state line-- it becomes interstate gas as soon as it enters the pipeline system) and that the gas Permian transports is comingled with interstate gas.
In denying the complaint, the Commission determined that Permian was initially built and operated exclusively as a non-jurisdictional intrastate pipeline and then provided interstate service under NGPA section 311. The Commission noted that an intrastate pipeline is one located within the borders of one state and delivers gas produced in the same state to consumers within that state, and even if it later provides interstate service under NGPA section 311, such service would not subject the company to NGA jurisdiction. The Commission found that Permian meets the definition of intrastate pipeline because it is located entirely in Texas and delivers gas produced in Texas to consumers within Texas. Contrary to the complaint, the number of interconnections with interstate pipelines and the comingling of intra-and inter-state gas do not factor into the Commission's analysis, instead, the Commission looks to whether the pipeline plans to operate, or in this case operated, solely as an intrastate pipeline when it began service.
As to the allegation that Permian deliberately sought to avoid regulation under the NGA, thereby depriving landowners of the procedural and substantive protections of federal law, the Commission stated that it is not unusual, much less unlawful, for entities to structure transactions to either qualify for or avoid regulation so long as such structuring is not contrary to public interest or is not inconsistent with the purposes of statutes effecting a federal scheme of regulation. Here, the Commission found, there is no evidence that Permian thwarts or frustrates the purposes of the NGA or NGPA, or that the pipeline was constructed solely to provide interstate service. The Commission found that Permian is located in entirely in Texas, interconnects with numerous intrastate pipelines and had sufficient supplies of Texas gas to operate as an intrastate pipeline when it was initially constructed, and continues to transport intrastate gas. Therefore, even if the respondents did structure Permian to avoid NGA jurisdiction, this does not support a finding that that structuring frustrates the purposes of either the NGA or NGPA.
2. Columbia Gulf CP20-528-001
On September 29, 2022, the Commission issued an order on rehearing of its approval of Columbia Gulf's East Lateral Xpress Project ("Project") in Louisiana. The project, which includes 8.13 miles of 30-inch pipeline connecting a Columbia Gulf line to a new delivery point at the Gator Express Pipeline. This lateral is designed to deliver gas that will ultimately be liquified and exported to foreign counties by the Plaquemines LNG Terminal.
The Commission disagreed with the objection made on rehearing claiming that precedent agreements with an exporter are insufficient to demonstrate need for the project. The Commission claimed that it is appropriate to give agreements for the transportation of gas destined for export the same weight in determining need that it gives other precedent agreement for transportation because the Department of Energy ("DOE") authorized the export and to act otherwise would thwart Congressional intent, as expressed in section 3 of the Natural Gas Act ("NGA") which deems exports to countries with a free trade agreement with the US to be in the public interest, and with exports to non-free trade countries, the DOE, in authorizing the export, makes a determination that the export will not be inconsistent with the public interest.
As to the claim that the Commission unlawfully segmented its National Environmental Policy Act ("NEPA") environmental review of the Project, the Commission found that not to be the case in analyzing multiple feeder lines, the authorization of the LNG terminal and other facilities. With respect to the authorization of the Project and the Plaquemines LNG terminal as connected actions, the Commission declared that the export of natural gas from a separate, previously authorized project, is not a proposal before the Commission because DOE, not the Commission, has sole authority to license the export through the LNG facilities, hence it is not connected action because it encompasses two actions by two separate agencies. As to Project and two other lines feeding the Gator Express line, the Commission noted that Gator Express is connected two major interstate lines and can feed the full requirements of the LNG terminal, and therefore, the LNG terminal and Gator Express have independent utility and can proceed without the other feeder projects. The other feeder projects, including the Project, provide access to other gas supplies, but none depend on the others, so they are likewise not connected actions. As to cumulative impacts, the Commission found that it did not err in failing to consider the impacts of the Venice Extension Project that was filed after the Project's final EIS was issued. The Commission determined that it was not required to issue a supplemental EIS because the information filed about the Venice Extension Project was not sufficient to show that the Project's impacts will affect the quality of the human environment in a significant manner or to a significant extent not already considered. The Commission analyzed the impact where the two projects converge at the Gator Express line and found that the rest of the facilities of the two projects were not in close enough proximity to have a significant cumulative impact. The Commission noted that the cumulative impact would also be considered in the EIS for the Venice Project.
As to greenhouse gas emission and climate change, the Commission sustained its Certificate Order finding that it need not consider the effects of upstream production or downstream transportation, consumption or combustion of exported gas because the DOE's independent decision to allow exports breaks the NEPA causal chain and absolves the Commission of responsibility to include these considerations in it NEPA analysis. As to claims that the Commission inconsistently relied on the economic benefits of the Project (domestic jobs in gas production, altering international trade balance) in its NGA section 7 finding of public convenience and necessity while refusing to consider the corresponding environmental impacts, the Commission, the Commission argued that it can make a determination as to these benefits, but the upstream impacts on gas production are not "reasonably foreseeable" because the specific timing, location, and extent of upstream activities are unknown, and the downstream GHG emissions are attributable to the DOE's independent decision to allow exports which is a decision over which the Commission has no authority.
3. Spire STL Pipeline LLC CP17-40-006
On December 22, 2022, the Commission issued an order on remand from the D.C. Circuit reissuing the certificate authorizing the construction and operation of the Spire STL pipeline. The court vacated and remanded the Commission's order for failing to demonstrate the need for the project and to balance the benefits and adverse effects of the project under the Commission's Certificate Policy Statement. Spire STL is a new, 65-mile pipeline extending from an interconnection with Rockies Express Pipeline ("REX") in Illinois, to an interconnection with Spire Missouri Inc., a local distribution company that is an affiliate of Spire STL. Spire Missouri is the sole customer of the pipeline and subscribed 87.5% of the total capacity of the pipeline and utilizes this capacity to serve its existing customers with no demonstration of need for additional capacity to serve new or increasing demand. The Certificate Order, in finding that the project was needed, claimed that the precedent agreement with the affiliated shipper was sufficient to demonstrate need. Because of the long interval of time between the issuance of the certificate, the Commission order on rehearing, and the D.C. Circuit decision, Spire STL had been built and in operation for more than 16 months before the court vacated the certificate and remanded the decision back to the Commission for further action. The court found the granting of the certificate to be arbitrary and capricious because the Commission was presented with strong arguments as to why the precedent agreements were insufficiently probative of the need for and benefits of the pipeline, given that nothing in the Commission's own Certificate Policy Statement suggests that a precedent agreement is conclusive proof of need in a situation where there is no new load demand, no finding that the new pipeline would reduce costs, only a single precedent in which the pipeline and shipper are corporate affiliates, the affiliate agreement was entered into privately after no shipper subscribed capacity in an open season, where there was plausible evidence of "self dealing" between the affiliates, and the agreement is not for the full capacity of the pipeline. Following vacatur, the Commission has issued temporary certificates for Spire STL to continue operation until it issued its order on remand.
In the instant order, the Commission concluded that it erred in relying solely, without any further examination, on a single precedent agreement among affiliated entities to find need for the project, especially because it is undisputed that the existing system was sufficient to enable that shipper to meet most of the current and anticipated customer demand. However, at this point in time, Spire STL has been in service for three years, and the Commission now found that the project is needed because Spire Missouri has, in those years, retired compressors at a storage field, decommissioned its propane peaking facilities, and is unable to re-contract for pipeline capacity it let expire on its primary service provider, which is Enable Mississippi River Transmission, LLC ("MRT"). The Commission found other benefits to Spire Missouri such as increased supply diversity from REX's access to diverse supply basins, improved reliability from alternative transportation paths that do not cross a major fault line, and lower delivered price of gas than that of MRT. The Commission also found benefits to another unaffiliated pipeline, MoGas Pipeline LLC, which, when interconnected with Spire STL could take advantage of higher gas pressure to increase its capacity without a major expansion. In evaluating the recertification, the Commission issued an Environmental Impact Statement on the continued operation of the pipeline.
Commissioner Glick issued a concurring opinion criticizing the then Chairman of the Commission for allowing 16 months to pass before permitting the Commission to act on rehearing requests, which meant that the pipeline was built and commenced operation before the opponents of the project could even go to the courts to seek redress; he characterized this case as the "one of the starkest example of abuse of tolling orders". Commissioner Danly's concurring opinion agreed with the need to look behind precedent agreements in this case, but disagreed that the Commission must look beyond precedent agreements in every circumstance. Commissioner Danly also disagreed with the Commission preparing an EIS on remand because the court remand called into question only the need for the project and not the findings in the environmental documents underlying the certificate order. Commissioner Clements issued a concurring opinion stating that the most basic lesson is that the Commission should follow its own Certificate Policy Statement which provides for the consideration of other evidence than precedent agreements, including market studies, and that is particularly important in the affiliate context, and that the Commission must fully engage arguments and evidence credibly challenging the probative value of a precedent agreement.
4. Transcontinental Gas Pipe Line Co. CP21-94-000
On January 11, 2023, the Commission approved an application to abandon and replace existing, less energy efficient compression facilities, construct new pipeline facilities in Pennsylvania, construct a new compressor station in New Jersey, expand existing compressor stations in New Jersey and Pennsylvania, and modify compressor stations in Pennsylvania and New Jersey, and modify other facilities in Pennsylvania, New Jersey and Maryland. The Project is an incremental expansion of Transco's existing system which will provide 829,400 Dth/d of transportation service from northeaster Pennsylvania to multiple delivery points in New Jersey, Pennsylvania, and Maryland.
Transco entered into long-term precedent agreements with shippers for 100% of the Project's capacity (two of nine shippers are affiliated with Transco). The shippers are primarily local distribution companies ("LDC"). Transco also submitted a market study that found that, accounting for firm delivery rights of downstream customers, existing firm capacity will fall short of the LDC shipper's design day demand during the 2023 winter heating season, and the shortfall will grow through the 2038/2039 winter heating season. The Commission found that this study did not account for the New Jersey Energy Master Plan and other energy policy targets, and may therefore overstate future demand, and did not account for short-term available peaking contracts from gas wholesalers, but, the study did correctly factor in competing demand from natural gas electric generators whose peak demand would also coincide with LDC peak demand; on balance, the Commission found the study to be consistent with traditional LDC supply planning. A New Jersey Agencies Study found that new capacity into New Jersey is unnecessary because existing capacity is sufficient and will continue to be sufficient if gains in energy efficiency are realized and non-pipeline alternatives are made available (only 56% of the capacity is subscribed by New Jersey LDCs so the study does not reflect needs for the remaining 44%). The Commission found that while New Jersey has directed LDC's to consider feasibility of non-pipeline alternatives in meeting peak-day demand, there is no requirement under New Jersey law to adopt such alternatives, and such alternatives may not be economic. Therefore, the Commission concluded that the record does not support a finding of sufficient non-pipeline alternatives, and the Commission concluded the LDC shipper's conclusion that the Project is needed to ensure supply during a peak day, supports the need for the project. The New Jersey Conservation Foundation submitted a study ("NJCF Study"), which concluded that the gas system is overbuilt, was found by the Commission to be deficient because it assumed that large volumes of non-New Jersey LDC capacity contracts that pass through the state should be counted as available to New Jersey even if the primary rights are held by downstream customers and New Jersey cannot rely on the capacity being available, and because the study also did not address reliability needs because it made no effort to estimate the highest gas demand the LDC may be obligated to serve ("design day") and focused exclusively on historic peak demand which is less than design day demand. On balance, the Commission found sided with the lower risk tolerance reflected in the Transco study and found that the Project would provide more reliable service on peak winter days and will increase supply diversity.
Commissioner Danly issued an opinion that concurred in part, and dissented in part. He concurred with the issuance of the certificate, but dissented on the reasoning in reaching the determination of project need. He noted that the order mentioned the binding precedent agreements, but also mentioned the studies and concluded that the project will provide more reliable service on peak winter days and increase supply diversity. He found that this conclusion might be read to suggest that precedent agreements for 100% of the capacity (by primarily unaffiliated shippers) might, by themselves, be insufficient to demonstrate need, or that other evidence proffered in the face of such precedent agreements, somehow tip the evidence against a finding of need. This would, according to Commissioner Danly, mark a departure from longstanding precedent without an attempt to explain the departure. Commissioner Danly also dissented because the order did not find that circumstances here overcome the presumptive stay of construction during rehearing established by Order Nos. 871-B and 871-C. He claimed that Transco demonstrated that a delay could threaten the ability to meet critical construction windows established to protect threatened and endangered species and this could postpone the in-service date by 12 months, preventing this vital capacity from being placed in service in time for the 2023/2024 wither heating season; the Commission should have refused to implement the stay because it would be contrary to the public interest. Commissioner Clements' concurring opinion took issue with the Commission's departure from its 1999 Certificate Policy Statement which declared that the evidence necessary to establish need will usually include a market study; over time the Commission has come to rely almost exclusively on precedent agreements to establish need. Commissioner Clements stated that in this case the Commission has actually done what it said it would do in the 1999 Certificate Policy Statement, and this is a meaningful step forward. However, Commissioner Clements said that, by denying an evidentiary hearing and relying only on a paper record, the Commission left important questions unanswered. Commissioner Clements claimed that the most glaring omission in the needs analysis is the lack of discussion of the weight the Commission should accord the finding of the New Jersey Board of Public Utilities ("New Jersey BPU") that no additional pipeline capacity is needed in New Jersey. Commissioner Clements stated that the Commission should determine, as a matter of policy, how to consider and weight relevant state laws, programs and administrative determinations in future proceedings. In the instant proceeding, Commission Clements criticize the Commission's treatment of the Transco study as being on par with the NJ Agencies Study instead of giving special weight to the study endorsed by the New Jersey BPU. Commissioner Christie, in his concurring opinion, questioned how much weight the third-party studies should receive, given that they have not been authenticated by a witness who can be subjected to cross-examination under oath. Weighted against the evidence from third-party studies in this proceeding is uncontested evidence that several shippers--unaffiliated with the pipeline--freely executed agreements to take service. He concluded that the third-party studies submitted in this proceeding are conflicting, and suffer shortcomings that limit their usefulness, and on balance, do not outweigh the persuasive evidence of need represented by executed agreements.
5. LA Storage, LLC. CP21-44-001
On January 20, 2023, the Commission issued an order on rehearing of its issuance of a certificate for LA Storage to construct and operate new storage facility in Louisiana intended to serve LNG export facilities, electric generation facilities, industrial customers, and other customers in the region. The Sierra Club argued, in its petition for rehearing, that the Commission violated the Natural Gas Act ("NGA") and National Environmental Policy Act ("NEPA") by 1) failing to consider greenhouse gas ("GHG") emissions in its public interest analysis and to determine whether the GHG emissions are significant; 2) not considering the upstream and downstream effects of the project; and 3) failing to consider the cumulative impacts of other projects in the area.
On the issue of determining the significance and considering the impact of GHG emissions, the Commission noted that the Certificate Order was issued after the Commission turned its Interim GHG Policy Statements into draft policy statements so that the significance threshold in the Interim GHG Policy Statements no longer applied. Hence, the Commission found it proper to not characterize the project's emissions as significant or insignificant, a determination the Commission will make in the future after completing its generic proceeding to determine whether and how the Commission will conduct significance determinations for GHG emissions going forward. As to Sierra Club's argument that the Commission could determine significance by using the social cost of GHG tool, the Commission disagreed, finding that the tool is an administrative tool intended to quantify, in dollars, estimates of long-term damage that may result from future emission, the Commission claimed that there are currently no criteria to identify what monetized values are significant for NEPA purposes, and the Commission is unable to identify any such appropriate criteria. The Commission conceded that the tool
is generally accepted in the scientific community and can play an important role in different contexts, such as rulemaking, but claimed that it cannot be used for project-specific review absent such criteria.
As to upstream effects (such as induced production of gas and the impacts of increased drilling and transportation of gas), the Commission claimed that its finding that upstream effects are "not reasonably foreseeable" is consonant with Delaware Riverkeeper Network v. FERCwhere the D.C. Circuit rejected contentions that the Commission did not adequately consider upstream effects because the petitioners failed to: 1) identify record evidence that would help the Commission predict the number and location of wells that would be drilled as a result of production demand created by the project; 2) identify evidence that shippers would not produced the gas in the absence of the project; and 3) argue that the Commission violated NEPA by not seeking out additional information. The Commission noted that the project is designed to enhance the efficiency and reliability of service to the contracting parties through the availability of storage rather than providing new sources of gas to the market and there is no evidence that the project would result in additional upstream production of gas. The Commission similarly rejected Sierra Club's arguments about downstream effects. The Commission found that the project was designed to enhance efficiency and reliability of service rather than providing new sources of natural gas and the record reflects that there was no increase in system capacity associated with the project. Therefore, the Commission did not have an obligation to seek more information, or in the absence of project-specific information, utilize a "full burn" estimate of downstream emissions as argued by the Sierra Club.
The Commission also disagreed with the Sierra Club's claim that multiple LNG export projects located in the same communities as the LA Storage project were improperly excluded from the NEPA analysis resulting in an inadequate analysis of: 1)impacts to environmental justice communities, which may not be alleviated through mitigation; 2) impacts from existing and proposed projects in the Gulf of Mexico by excluding projects not in an area determined by the use of a watershed hydrologic unit code; and 3) cumulative impacts of the project and other reasonably foreseeable projects on air pollution, specifically emissions of nitrogen oxides and volatile organic compounds. On rehearing, the Commission concluded that the final Environmental Impact Statement ("EIS") fully addressed the adverse impacts of the project. The final EIS concluded that impacts on environmental justice populations may be disproportionately high because the impacts in the project area (e.g., traffic, noise, visual, air quality) would be predominantly borne by those populations, but, the final EIS properly concluded that those impacts would be less than significant in light of mitigation proposed by LA Storage and required by the Certificate Order. The Commission claimed that its analysis encompassed numerous LNG export projects and many other petrochemical and manufacturing projects and chided the Sierra Club for claiming that the analysis failed to include other LNG export projects while not specifically identifying the projects. The Commission also agreed with the final EIS' determination that, based on estimated operational emissions and a review of the modeling, the project would not cause air quality standards to be exceeded. As to the choice of geographic area, the Commission stated that the Commission has significant discretion to establish reasonable geographic boundaries for a cumulative impacts analysis and it properly used the watershed designation to analyze impacts on certain resources while using a different area to analyze impacts on a different resource.
F. Infrastructure--LNG
1. Freeport LNG Development, L.L.C. CP17-470-002
On October 13, 2022, the Commission granted Freeport LNG a 26-month extension of time to complete construction of and make available for service the Train 4 Project authorized by the Commission in May 2019. In its request for an extension, Freeport LNG claimed that it has not yet commenced construction because of delays stemming from the replacement of its engineering, procurement, and construction contractor and from the COVID-19 pandemic, including the pandemic's effects on the global suppl7y-chain and on global LNG demand. Freeport stated that demand for LNG has rebounded and it has been actively negotiating with potential LNG customers. The Sierra Club opposed the extension, claiming that good cause has not been demonstrated and that the Commission must revisit its environmental findings and supplement its National Environmental Policy Act ("NEPA") analysis.
In granting the extension, the Commission found that given the unforeseeable difficulties associated with the pandemic, Freeport LNG's failure, to date, to replace its contractor and commence construction is not evidence that Freeport LNG has not taken all reasonable, good-faith efforts to meet its deadline. Unlike the applicants in Chestnut Ridge Storage, LLC,Freeport LNG is not sitting on its approval waiting to see whether market conditions become favorable, instead, it has maintained its permits, actively pursued commercial agreements and is actively pursuing a new contractor.
The Commission also found that the environmental analysis for the certification of the project remains valid and the decision to grant an extension of time is not a "major Federal action with the potential to significantly affect the environment" which would require a supplemental Environmental Impact Statement under NEPA. The Commission claimed that an extension is an administrative action, not a major Federal action, and does not involve substantial changes that are relevant to environmental concerns, nor has there been a showing that environmental effects of the project have changed since the issuance of the certificate order. As to the listing of the Rice's whale as an endangered species after the issuance of the certificate, the Commission agreed that this requires a determination of whether the project may impact the newly listed species. The Commission stated that if a new species is listed before the completion of project construction, its staff will determine whether the project may affect the species, and if the project will not affect the species, the Commission has no further obligation under the Endangered Species Act, and if it will affect the species, the Commission must consult with the National Marine Fisheries Service or the U.S. Fish and Wildlife Service, as appropriate. However, the potential to re-initiate consultation does not in and of itself render the EIS stale or trigger a supplemental EIS; a determination of whether additional NEPA analysis is needed cannot be made prior to determining if further consultation is needed and obtaining the results of such consultation.
2. Commonwealth LNG, LLC CP19-502-000
On November 17,2022, the Commission authorized the siting, construction and operation of a new gas liquefaction and export facility, including a Natural Gas Act ("NGA") section 3 gas pipeline, in Cameron Parish, Louisiana. The design capacity is 8.4 metric tonnes per annum (equivalent to about 391 Bcf per year of gas). A 3.09 mile pipeline, which interconnects the LNG export terminal to two existing pipelines are considered part of the LNG terminal and were not considered for certification under NGA section 7 which covers interstate gas pipelines. Because the facilities will be used to export gas to foreign countries, the Commission's approval was granted under NGA section 3, and that section provides that the application shall be approved if the Commission finds the proposal "will not be [in]consistent with the public interest," subject to "such terms and conditions as the Commission [may] find necessary or appropriate." As to the claims-- of no demonstration of public benefit (e.g., merely duplicative of capacity of existing facilities), and claims that the Commission cannot simply defer to the Department of Energy's ("DOE") approval of export of the LNG (particularly because DOE has disclaimed authority to consider export-induced gas production)--the Commission declared that because it has no authority to approve or disapprove the export of the commodity, it will decline to address economic claims (e.g., those regarding market demand for LNG), which are only relevant to the exportation of the commodity. The Commission claimed that its only authority under NGA section 3 applies to the siting and operation of the facilities necessary to accomplish the export of gas. For similar reasons, the Commission declined to address the impacts on natural gas development and production related to the export of gas. Because of the NGA section 3 presumption of public interest, the Commission claimed that it reviewed the application to determine if there is an affirmative showing that the siting, construction and operation of the facilities is inconsistent with the public interest and made no such finding.
The Commission prepared an Environmental Impact Statement ("EIS"), pursuant to the National Environmental Policy Act ("NEPA"), that determined that, although some impacts of the Project would be permanent and significant, such as impacts on visual resources, most impacts would not be significant or would be reduced to less-than-significant levels with the implementation of avoidance, minimization, and mitigation measures recommended in the EIS which the Commission adopted in its order. As to a challenge to the Biological Opinion issued by the U.S. Fish and Wildlife Service ("FWS") regarding the impact on the Eastern Black Rail, an endangered species, the Commission stated that, although it is required to ensure that its actions will not jeopardize the existence of a listed species, it must do so in consultation with the appropriate agency, in this case the FWS, which is the recognized expert in this matter, and the Commission may rely on the FWS' conclusions. Hence, the Commission concluded, the relevant inquiry is not whether the Biological Opinion is flawed, but whether the Commission's reliance on it is arbitrary and capricious, which is not the case here because the challengers failed to cite new information that FWS did not take into account that challenges the Biological Opinion's conclusions.
As to the impacts of greenhouse gas ("GHG") emissions, the Commission noted that it has quantified the emissions from the construction and operation of the facilities and has "contextualize" such emissions by comparing the emissions to national and state emission levels, and recognized that such emissions may contribute incrementally to future global climate change. However, because the Commission is conducting a generic proceeding to determine whether and how it will conduct significance determinations for GHG emissions going forward (development of a new policy statement), it will not herein characterize the Project's emissions as significant or insignificant. As to claims that the Commission should analyze the impacts of GHG emissions related to upstream production and downstream consumption of gas that would be exported by the Project, the Commission cited Sierra Club v. FERC (Freeport),as finding that it need not consider upstream production, downstream transportation, consumption, or combustion of exported gas because the DOE's independent decision to allow exports breaks the NEPA causal chain and absolves the Commission of responsibility to include these considerations in its NEPA analysis. As to claim--that the Commission, as lead agency coordinating Federal authorizations and supervising the preparation of the EIS, should do a comprehensive analysis of impacts, including the connected action of DOE's authorization, which could persuade the Commission to require additional mitigation--the Commission disagreed. The Commission stated that although it supervised the preparation of the EIS, the lead agency designation does not alter the scope of the project before the Commission either for approval or environmental review, nor does it make the Commission responsible for ensuring compliance of a cooperating agency with its own NEPA responsibilities.
Commissioner Glick issued a concurring opinion. He stated that section 3 of the NGA does not provide a sufficient framework for consideration of the adverse impacts associated with the proposed LNG facility. Under section 7 of the NGA, the Commission makes two findings: whether the project is needed, and if so, whether it is in the public interest (weighing of the benefits against adverse impacts) while DOE makes its determination whether the export or import is consistent with the public interest. Under this bifurcated framework, Commissioner Glick claimed it is not clear how the Commission is supposed to weight adverse impacts when the public interest determination as the export or import is outside of the Commission's jurisdiction. Commissioner Glick claimed that the Commission should have made a determination that the Project's GHG emissions will have a significant impact on the climate. He claimed that surely there is a degree of adverse impact so great that public interest requires the Commission to reject a section 3 application, but without a clear framework for making that determination in light of the substantial benefits the LNG export can provide (after all, Congress deemed exports to free trade partners to be categorically in the public interest), there is unavoidable uncertainty regarding how the Commission should weigh adverse impacts. Commissioner Danly issued a concurring opinion acknowledging that the Commission acted quickly in issuing the order just 69 days after the issuance of the EIS, where timely action is important because LNG is needed right now, particularly to supply Europe's demand for LNG. Commissioner Danly criticized the order's attempt to "sugarcoat" its analysis of GHG emissions by recognizing that the Project may release GHG emissions that contribute incrementally to future global climate change and by disclosing information on emission levels where nothing can be gleaned from the information (no means by which to determine the significance of the estimated emissions). He added that, without a reasoned method to determine significance, the Commission "has a rocky road ahead should it continue its pursuit of environmental policy goals. Because the Commission does not have a clear delegation of authority from Congress to regulate GHG emissions, the Commission's charge under the NGA remains, according to Commissioner Danly, encouraging the orderly development of plentiful supplies of natural gas at reasonable prices. Commissioner Clements issued a concurring opinion stating that the Commission should consider whether to provide a formal opportunity for the public to comment on the final EIS and should continue its efforts to inform affected environmental justice communities about proposed projects. Commissioner Phillips issued a concurring opinion raising concern over the Commission's approach to mitigating impacts on environmental justice communities.
G. Abandonment
Equitrans, L.P. CP20-312-001
On December 16, 2022, the Commission issued an order on rehearing of an order granting, in part, Equitran's request to abandon certificated and non-certificated gathering facilities. The Abandonment Order found that a part of non-certificated facilities in West Virginia, known as the Taylor County Field, receives occasional backflows of natural gas from Equitran's jurisdictional pipeline, and as a result, the Commission required Equitrans to either: 1) show cause why it is not required to seek a certificate from the Commission; 2) seek a certificate for the facilities; or 3) file information supporting abandonment by sale of the facilities to Big Dog Midstream, LLC ("Big Dog").. Subsequently, Big Dog filed an application for a limited jurisdiction certificate to provide interstate transportation service on the Taylor County Field facilities. As detailed below, the instant order authorizes Equitrans to abandon the facilities by sale to Big Dog and finds that the facilities will be used primarily to perform a gathering function exempt from the Commission's jurisdiction, and grants Big Dog a limited jurisdiction certificate for the incidental interstate transportation service Big Dog will provide to certain customers.
Equitrans explained that the Taylor County Field facilities gathers gas from ten conventional production receipt meters and has 125 farm tap customers and seven city-gate interconnections feeding another company's distribution system. During periods of insufficient local production, Equitrans delivers interstate gas into the Taylor County Field facilities in order to meet the winter needs of these customers. Big Dog filed for a limited jurisdictional certificate to allow it to continue the backflow from Equitrans to serve these customers without affecting the non-jurisdcitional status of any of its other operation or services, and also requested waiver of filing and reporting requirements, such as the requirement for a Commission-approved tariff, accounting requirements, reporting requirements, and annual charges.
The instant order found that abandonment by sale to Big Dog would be permitted by the public convenience and necessity even if the Taylor County Field facilities were functionalized as providing interstate service. The Commission found that Equitrans' customers were only interruptible service customers, Big Dog will continue to provide service to these customers and no concerns were raised about adverse impacts. The Commission also concluded that after sale to Big Dog, the Taylor County Field facilities will be gathering facilities because 69% of flows on the facilities will be locally produced gas, with the remaining portion being backflows from Equitrans. The Commission noted that Big Dog owns no interstate facilities and is only in the business of gathering. Because of the limited scope of anticipated jurisdictional activities, the Commission granted the limited jurisdiction certificate and the requested waivers. However, the Commission required the filing of the contracts or service agreements and the rates which the Commission must approve.
Commissioner Danly issued a dissent, in part. He questioned why the Commission required Equitrans to show cause why it should not be required to seek a certificate, when on the record, the Commission could have found that the facilities are gathering facilities, and therefore, non-jurisdictional. He also found that it makes no sense that the Commission found that Big Dog's operation of the facilities would be gathering, but refused to say that Equitrans' similar operation of the facilities was also gathering. Had the Commission made the gathering determination with respect to Equitrans' ownership of the facilities, the inquiry would end there and the Commission would have no authority to deny the abandonment on the basis of continuity of service. The only notable difference he discerned is that the general business activity of the owners differ, with Equitrans being a jurisdictional interstate natural gas company. While recognizing that court precedent indicates that non-physical factors, such as general business activity and prior certification are relevant factors, he stated that these are considered secondary to the physical factors, and those physical factors lead to only one conclusion: these are gathering facilities. Commission Danly concluded that the Commission must apply its "primary function test" consistently and questioned why the Commission would suggest "murkiness where none need exist."
H. Miscellaneous
Hummel Generation, LLC/UGI Sunbury,LLC RP22-678-000
On September 22, 2022, the Commission denied a complaint filed by Hummel requesting that the Commission find Sunbury to be exempt from the Commission's jurisdiction under the Natural Gas Act ("NGA") and vacate the April 29, 2016 Order Issuing a certificate that authorized Sunbury to construct and operate its pipeline system. The Commission certificate order authorized the construction of the 34.4-mile long Sunbury Pipeline in Pennsylvania from interconnections with two interstate pipelines to delivery points at the Hummel electric generation plant (180,000 Dth/day) and to UGI Energy Services (20,000 Dth/day) for use by affiliated local distribution companies. Hummel's complaint alleged that the Sunbury is exempt from Commission jurisdiction under section 1(c) of the NGA under what is called the Hinshaw exemption which provides that a company whose facilities are located entirely in one state, receives all gas at or within the boundaries of the state, has all of its gas supplies consumed with the state, and is regulated by a state commission is exempt from the jurisdiction of the Commission. Hummel and UGI Sunbury agree that the first three criteria are met, but disagree as to whether the Sunbury is subject to regulation by Pennsylvania. Hummel claimed that under Pennsylvania statutes and case law, to be considered a public utility subject to the Pennsylvania Public Utility Commission's ("PAPUC") jurisdiction, the only question is whether Sunbury is transporting for the public and it does not matter how many customers a pipeline serves--it qualifies as a public utility if the service is not offered only to particular individuals and Sunbury conducted an open season as part of its Commission certification process. Sunbury countered that there is no statement by the PAPUC that it intends to assert jurisdiction and provided evidence that the PAPUC has issued orders acknowledging its pipeline while not contesting the Commission's jurisdiction. Sunbury claimed that its pipeline was designed and constructed to serve two individual shippers that sponsored the pipeline and cannot operationally or contractually offer service to the public.
The Commission, in the instant order, stated that it agreed with Hummel that a pipeline may be exempt from Commission jurisdiction regardless of whether the state agency actively asserts its authority; it is sufficient that the agency has authority to regulate the pipeline's rates and services, even when the authority is not exercised. However, the Commission declined to interpret Pennsylvania law under the particular circumstances, and instead, found that the state is best situated to determine if its jurisdiction extends to the Sunbury Pipeline. Therefore, the Commission declined to reverse its early finding that the Sunbury Pipeline is subject to the Commission's jurisdiction under the NGA, and unless and until the PAPUC certifies that it would have jurisdiction, the Commission's certificate remains valid.
