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Certification of New Interstate Natural Gas Facilities

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Federal Energy Regulatory Commission, Department of Energy.


Notice of Inquiry.


In this Notice of Inquiry, the Federal Energy Regulatory Commission (Commission) seeks information and stakeholder perspectives to help the Start Printed Page 18021Commission explore whether, and if so how, it should revise its approach under its currently effective policy statement on the certification of new natural gas transportation facilities to determine whether a proposed natural gas project is or will be required by the present or future public convenience and necessity, as that standard is established in section 7 of the Natural Gas Act.


Comments are due June 25, 2018.


Comments, identified by docket number, may be filed in the following ways:

  • Electronic Filing through Documents created electronically using word processing software should be filed in native applications or print-to-PDF format and not in a scanned format.
  • Mail/Hand Delivery: Those unable to file electronically may mail or hand-deliver comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE, Washington, DC 20426.

Instructions: For detailed instructions on submitting comments and additional information on the rulemaking process, see the Comment Procedures Section of this document.

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Thomas Chandler (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, 202-502-6699.

Maggie Suter (Technical Information), Office of Energy Projects, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, 202-502-6463.

Caroline Wozniak (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, 202-502-8931.

Brian White (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, 202-502-8332.

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1. In this Notice of Inquiry, the Commission seeks information and stakeholder perspectives to help the Commission explore whether, and if so how, it should revise its approach under its currently effective policy statement on the certification of new natural gas transportation facilities (Policy Statement) [1] to determine whether a proposed natural gas project is or will be required by the present or future public convenience and necessity, as that standard is established in section 7 of the Natural Gas Act (NGA).[2] Specifically, the Commission seeks input on whether, and if so how, the Commission should adjust: (1) Its methodology for determining whether there is a need for a proposed project, including the Commission's consideration of precedent agreements and contracts for service as evidence of such need; (2) its consideration of the potential exercise of eminent domain and of landowner interests related to a proposed project; and (3) its evaluation of the environmental impact of a proposed project. Finally, the Commission seeks input on whether there are specific changes the Commission could consider implementing to improve the efficiency and effectiveness of its certificate processes including pre-filing, post-filing, and post-order issuance.

2. Nineteen years have passed since the Commission issued the Policy Statement to describe the criteria and analytical steps that the Commission uses to balance a proposed natural gas pipeline project's public benefits against its potential adverse consequences. That period has seen significant changes, such as: (1) A revolution in natural gas production technology leading to dramatic increases in production; (2) new areas of major natural gas production; (3) flows on pipeline systems becoming bidirectional or reversing; (4) customers routinely entering into long-term precedent agreements for firm service during the formative stage of potential projects and the use of those precedent agreements as applicants' principal evidence of the need for their projects; (5) the increased use of natural gas as a fuel source for electric generation, resulting in a closer relationship between natural gas transportation and natural gas-fired electric generation; (6) increased concerns expressed by landowners and communities potentially affected [3] by proposed projects; (7) an increased interest regarding the Commission's evaluation of the impact that greenhouse gas (GHG) emissions associated with a proposed project have on global climate change; (8) an increased focus on environmental concerns within the NGA public interest determination; and (9) a desire to generally expand or limit the Commission's evaluation under the National Environmental Policy Act of 1969 (NEPA).[4]

3. The Commission's aim in this proceeding is the same as in the Policy Statement: “to appropriately consider the enhancement of competitive transportation alternatives, the possibility of over building, the avoidance of unnecessary disruption of the environment, and the unneeded exercise of eminent domain.” [5] In issuing this Notice of Inquiry, the Commission seeks information to examine the Policy Statement and its application, as well as the structure and scope of the Commission's environmental analysis of proposed natural gas projects. Further, it is the Commission's desire to improve the transparency, timing, and predictability of the Commission's certification process. To these ends, we encourage commenters to identify, with specificity, any perceived issues with the Commission's current analytical and procedural approaches and to provide detailed recommendations to address these issues.

4. During the pendency of this proceeding, the Commission intends to continue to process natural gas facility matters before it consistent with the Policy Statement, and to make determinations on the issues raised in those proceedings on a case-by-case basis.[6] Should the Commission decide to generally revise its procedures as a result of this proceeding, it will address at that time how and when those changes will be implemented. The Commission will decide any next steps with regard to this review of the Policy Statement after the Commission has reviewed the comments filed in response to this Notice of Inquiry.

I. Background

A. The Natural Gas Act of 1938

5. The NGA declares “that the business of transporting and selling natural gas for ultimate distribution to the public is affected with a public interest, and that Federal regulation in matters relating to the transportation of Start Printed Page 18022natural gas and the sale thereof in interstate and foreign commerce is necessary in the public interest.” [7] NGA section 7(c) requires that any person seeking to construct or operate a facility for the transportation of natural gas in interstate commerce must obtain a certificate of public convenience and necessity from the Commission.[8] Under NGA section 7(e), the Commission shall issue a certificate to any qualified applicant upon finding that the construction and operation of the proposed project—whether pipeline, storage, or liquefaction facilities—“is or will be required by the present or future public convenience and necessity.” [9] The Commission's regulations provide for public notice and the opportunity to intervene in certificate proceedings to comment on or protest an application, and to participate in the environmental review process.[10] If an applicant receives a certificate from the Commission, NGA section 7(h) authorizes the certificate holder to acquire the property rights necessary to construct and operate its project by use of eminent domain if it cannot reach a voluntary agreement with a landowner.[11]

6. The public convenience and necessity standard encompasses all factors bearing on the public interest.[12] The words “public interest,” however, are “not a broad license to promote the general public welfare.” [13] The Supreme Court has stated that:

in order to give content and meaning to the words `public interest' as used in the [Federal] Power and [Natural] Gas Acts, it is necessary to look to the purposes for which the Acts were adopted. In the case of the Power and Gas Acts it is clear that the principal purpose of those Acts was to encourage the orderly development of plentiful supplies of electricity and natural gas at reasonable prices.[14]

7. As part of its decision-making process, the Commission, in accord with the Policy Statement, determines whether there is a need for a proposed project. This analysis is distinct from that required by the Council on Environmental Quality (CEQ) regulations, which specify that environmental documents contain a “purpose and need statement” used to determine the objectives of the proposed action and then to identify and consider reasonable alternative actions.[15] Under the NGA, the Commission will take into account all information in the record from the applicant, parties to the proceeding, commenters, and the environmental document to determine whether a proposed project is required by the public convenience and necessity.[16]

8. The Commission's powers under NGA section 7 are limited. The Commission can issue a certificate for a proposed project, subject to “such reasonable terms and conditions as the public convenience and necessity may require.” [17] The Commission can deny an application if, and only if, a balancing of all of the factors weighs against authorization of the proposed project.[18] The Policy Statement explains that relevant factors reflecting the need for the project might include, but would not be limited to, precedent agreements, demand projections, potential cost savings to consumers, or a comparison of projected demand with the amount of capacity currently serving the market while adverse effects include economic, competitive, environmental, or other effects on the relevant interests.[19] We note the Commission only has authority over facilities for the transportation of natural gas in interstate commerce. The Commission has no authority to certificate intrastate facilities or facilities for the production, gathering, or local distribution of natural gas.[20] Nor does the Commission have jurisdiction over facilities used for the generation of electric energy.[21]

B. The National Environmental Policy Act of 1969

9. The Commission's consideration of an application triggers environmental review under NEPA.[22] NEPA and its implementing regulations require that before taking a major action, such as action on an application for a natural gas project, an agency must take a “hard look” at the environmental consequences of the proposed action and at alternatives, and disclose its analysis to the public.[23] Regulations issued by the CEQ to implement NEPA [24] require agencies, including the Commission, to consider the environmental impacts of a proposed action, generally by preparing either an Environmental Assessment (EA) or an Environmental Impact Statement (EIS).[25] The requirements of NEPA are procedural: They are intended to disclose impacts and allow for informed decision-making, but do not mandate a particular result or give preeminent weight to environmental considerations.[26]

10. An agency's environmental document must include a statement to “briefly specify the underlying purpose and need to which the agency is responding in proposing the alternatives including the proposed action.” [27] Agencies use the purpose and need statement to define the objectives of a proposed action and then to identify and consider reasonable alternatives.[28] Agencies consider alternatives “that are practical or feasible from the technical and economic standpoint and using common sense, rather than simply desirable from the standpoint of the applicant.” [29] An agency need only evaluate alternatives that can satisfy the purpose and need of the proposed project, and the evaluation is shaped by the application and the function that the agency plays in the decisional process.[30] Alternatives that are not environmentally preferable, not able to Start Printed Page 18023provide equivalent services, uneconomic, speculative ventures as opposed to planned projects, or otherwise inadequate to function as a serviceable alternative to the proposed project may be eliminated so long as the agency briefly discusses the reasons for the elimination.[31]

11. Commission documents under NEPA first address the scope of the project (i.e., “the range of actions, alternatives, and impacts to be considered”) [32] , then address the environmental impacts of the proposed action, connected actions, and cumulative actions.[33] Commission documents under NEPA may also address similar actions if a combined analysis would be the best way to adequately assess combined impacts.[34] These NEPA documents disclose and evaluate the direct, indirect, and cumulative impacts of the project on various environmental resources in the context of temporary, short-term, long-term, and permanent impacts, and then consider practical measures to avoid, minimize, or mitigate those impacts. Direct impacts are caused by the proposed action and occur at the same time and place. Indirect impacts are “caused by the [proposed] action and are later in time or farther removed in distance, but are still reasonably foreseeable.” [35] Cumulative impacts are defined as “the impact on the environment which results from the incremental impact of the [proposed] action when added to other past, present, and reasonably foreseeable future actions, regardless of what agency (Federal or non-Federal) or person undertakes such actions.” [36] The impacts of these other actions must occur within the same geographic area and same time period in which the proposed project's impacts will occur.[37]

C. Conditions and Considerations Leading to the Development of the Policy Statement

12. Historically, the Commission established prices for natural gas sales and transportation, and there was little competition for gas supply or transportation capacity. Interstate pipelines, operating as merchants, produced and/or purchased natural gas at the wellhead, transported it to a city gate, and sold it to a local distribution company (LDC) at a Commission-regulated price that reflected combined (i.e., bundled) commodity and transportation costs. Congress and the Commission introduced increasingly competitive elements into this merchant model. The Natural Gas Policy Act of 1978 began the process of decontrolling wellhead natural gas prices and eased barriers between intrastate and interstate markets.[38] The Commission issued Order No. 436, which initiated open access transportation to allow downstream gas users, such as LDCs and industrial customers, to buy gas directly from producers or merchants and transport their gas on interstate pipelines.[39] The Wellhead Decontrol Act of 1989 lifted remaining price controls on wellhead sales as of January 1, 1993.[40] In 1992, the Commission issued Order No. 636 to “reflect and finally complete the evolution to competition in the natural gas industry initiated by [the above-cited statutory and regulatory revisions] so that all natural gas suppliers, including the pipeline as merchant, will compete for gas purchasers on an equal footing.” [41] As a result, natural gas markets have changed from being highly regulated to being largely driven by competition and market forces. Instead of merchant pipelines delivering natural gas to customers at a Commission-regulated bundled price, most natural gas pipelines have exited the merchant business and now provide unbundled transportation and storage services. As a result, shippers are able to purchase natural gas at the wellhead or from gas marketers, trade gas among themselves, and purchase pipeline and storage capacity from marketers and other shippers in the secondary market as well as directly from the pipeline. These changes have benefitted natural gas consumers by providing a wider range of options in pipeline services.

13. As natural gas commodity and transportation markets were becoming more competitive, the 1990s saw significant growth in natural gas consumption in the industrial and electric generation segments. This prompted jurisdictional natural gas companies to urge the Commission to expeditiously authorize new projects to meet anticipated growth in demand. Due to the lower capital costs and shorter construction times of advanced combined-cycle gas-fired plants in comparison with conventional coal-fired plants, and the relative environmental benefits of natural gas compared to coal combustion, industry forecasts at the time showed natural gas-fired electric generation demand tripling in the following twenty years and overall gas demand reaching 32 Trillion Cubic Feet (Tcf) by 2020.[42]

14. In addition, in the 1990s, many LDCs were going through significant changes as they implemented retail unbundling programs, also known as customer choice programs, on their systems. Prior to retail unbundling, LDCs, similar to interstate pipelines, provided a composite bundled service to customers that included the bundled price of the gas and associated pipeline capacity and the price of the distribution service. Retail unbundling programs provided residential and commercial customers with access to competitive markets through the ability to purchase gas supplies from retail marketers that may be different from their LDCs. As a result, LDCs were not certain to what degree they would continue to be responsible for purchasing gas supplies and pipeline capacity in order to provide service for their core retail customers. Because of Start Printed Page 18024this uncertainty, many LDCs sought to reduce their firm contract commitments with interstate pipelines, both in terms of the duration and quantity of firm service (this reduction in service is referred to as capacity turnback). In light of the capacity turnback situation and potential stranded cost issues that arose on certain pipelines following restructuring, many LDCs were concerned about the impact any new pipeline expansion construction could have on the value of their existing pipeline capacity contracts, and the potential rate implications of overbuilding.[43] These concerns were exacerbated by the fact that the Commission's pricing policy for new construction prior to the Policy Statement called for expansion project costs to be rolled into existing system costs to derive rolled-in rates in a future NGA section 4 rate case.[44] At that time, the Commission generally ruled in favor of rolled-in rates when the cost impact of the expansion project, spread across the pipeline's system, resulted in a rate impact on existing customers of five percent or less and the expansion provided operational and/or financial benefits to the system.[45] All shippers bore some burden of the expansion project's cost, whether they benefitted from the project or not, without being allowed to adjust their contracted volumes. LDCs and other parties believed that this pricing policy sent the wrong price signals by masking the real costs of an expansion project and could result in overbuilding of capacity and subsidization of an expansion by a pipeline's existing shippers.

D. Proceedings Leading to the Policy Statement, Purpose of the Policy Statement, and the Issues It Sought To Address

15. In response to the concerns described above, the Commission issued the Notice of Proposed Rulemaking (NOPR), Regulation of Short-Term Natural Gas Transportation Services,[46] and the Notice of Inquiry, Regulation of Interstate Natural Gas Transportation Services,[47] to explore issues related to its policies on certification and pricing of new construction projects. In the NOPR, the Commission asked questions relating to many of the issues that have arisen in recent certificate proceedings including: Whether the Commission should look behind the precedent agreements or contracts presented as evidence of market demand to assess independently the market's need for additional gas service; whether the Commission should apply a different standard to precedent agreements or contracts with affiliates than with non-affiliates; whether the Commission should, in an effort to check overbuilding and capacity turnback, take a harder look at proposals that are designed to compete for existing market share rather than bring service to a new customer base; and whether the Commission should apply a different standard to project sponsors who do not plan to use either federal or state-granted rights of eminent domain to acquire right-of-way.[48]

16. Information received in these proceedings, as well as experience evaluating proposals for new pipeline construction, persuaded the Commission to revisit its policy for certificating new construction.[49] The Commission issued the Policy Statement intending that it would provide the natural gas industry with guidance as to how the Commission would evaluate applications for new natural gas projects. The Commission sought “to foster competitive markets, protect captive customers, and avoid unnecessary environmental and community impacts while serving increasing demands for natural gas.” [50]

17. These objectives were realized primarily by a shift from rolled-in pricing to incremental pricing. Under incremental pricing, existing customers using existing facilities do not contribute to, and thereby do not subsidize, the cost of constructing and operating new projects.[51] Applicants can recover the costs of the new facilities only from shippers who use them, and are fully at risk for the cost of the new facilities and will bear the financial burden of any unsubscribed capacity. In the Policy Statement, the Commission reasoned that incremental pricing would send the proper price signals for new construction and indicate whether a project is financially viable.[52]

18. The Policy Statement stated that the Commission will approve an application for a new project only if its public benefits outweigh its residual adverse effects.[53] The Policy Statement described this balancing of benefits and adverse effects as an economic test.[54] In addition to the economic screen established by the Policy Statement, the Commission simultaneously considers the environmental impacts of a proposed project and imposes mitigation measures to address potential environmental impacts.

E. Changed Circumstances Since Issuance of the Policy Statement

19. Over the last decade, the United States has seen an unprecedented change in the dynamics of the natural gas market and the supply and demand forces driving it. Led by advancements in production technologies, primarily in accessing shale reserves, natural gas supplies have increased dramatically. Domestic natural gas production has increased from 21.3 Tcf in 2010 to 26.9 Tcf in 2017.[55] The Energy Information Administration's (EIA) Annual Energy Outlook 2018 forecasts continued supply growth over the next 25 years, increasing to nearly 39 Tcf by 2035 and 43 Tcf by 2050.[56] In addition, driven by liquefied natural gas (LNG) exports, increased pipeline exports to Mexico, and reduced imports from Canada, the EIA shows that the United States became a net exporter of natural gas in 2017.[57]

20. As natural gas production has increased, so has demand, rising from Start Printed Page 1802524.1 Tcf in 2010 to 27.1 Tcf in 2017, driven in part by an increase in gas-fired electric generation.[58] The EIA's 2018 Annual Energy Outlook projects continued growth in domestic demand to over 31.4 Tcf by 2035 and nearly 35 Tcf by 2050.[59]

21. Increases in both domestic and international demand for natural gas produced in the United States, combined with the availability of competitively-priced gas from shale reserves and associated gas extracted in tandem with oil, have reduced prices and price volatility and shifted the emphasis of the types of proposed natural gas infrastructure projects from storage to transportation and exports, leading to the Commission receiving and approving an increased number of pipeline and LNG export terminal applications since 2010.[60] Much of the increased production is attributable to Appalachian shale deposits, predominately the Marcellus and Utica, located in Pennsylvania, West Virginia, Ohio, and New York.[61] Although these areas have historically produced natural gas, the volumes had been relatively small and much of the infrastructure in the area was built to deliver natural gas to traditional regional markets and was not able to transport the burgeoning supply volumes to more distant markets without significant system expansions. In response to this take-away bottleneck, the Commission received a host of applications proposing either to construct greenfield pipelines [62] to transport gas out of the region or to increase the capacity of existing infrastructure through the addition of compression and pipeline looping.[63] Other producing areas have also experienced a dramatic growth in output starting in the mid-2000s, from traditional oil and gas fields in the Permian Basin in West Texas to the more recently developed Bakken Shale Formation in North Dakota. This increased production has also prompted applications to add capacity to transport gas to consumers.

22. In addition, contracting patterns are changing significantly as a result of the supply growth. In the past, LDCs contracted for a large percentage of the total interstate pipeline capacity, transporting supplies from the production area to their customers. Increasingly, however, LDCs are purchasing gas supplies further downstream at market area pooling points or their citygates as other parties increasingly contract for pipeline capacity. Natural gas producers are now contracting for an increasing amount of firm pipeline capacity on expansion projects in an effort to provide a secured commercial outlet for their supplies. For many of these projects, producers are interested in transporting their natural gas to the nearest pooling point on the pipeline system, where the gas can be sold to other parties serving downstream markets. Therefore, an increasing number of projects are being designed to transport gas to a point of distribution on the interstate pipeline grid, which may not correspond to a defined market or end use.

F. Executive Order 13807, “Establishing Discipline and Accountability in the Environmental Review and Permitting Process for Infrastructure Projects”

23. On August 15, 2017, President Trump issued Executive Order 13807 “Establishing Discipline and Accountability in the Environmental Review and Permitting Process for Infrastructure Projects” to “ensure that the Federal environmental review and permitting process for infrastructure projects is coordinated, predictable, and transparent.” [64] Executive Order 13807 states that inefficiencies in the project decision-making process, including the management of environmental reviews and permit decisions or authorizations, “have delayed infrastructure investments, increased project costs, and blocked the American people from enjoying improved infrastructure that would benefit our economy, society, and environment.” [65] Executive Order 13807 sets forth several components of its policy, including to “ensure that Federal authorities make informed decisions concerning the environmental impacts of infrastructure projects,” “provide transparency and accountability to the public regarding environmental review and authorization decisions,” and “make timely decisions with the goal of completing all Federal environmental reviews and authorization decisions for major infrastructure projects within 2 years.” [66] The Commission is committed to carrying out the goals of Executive Order 13807 to improve the efficiency, timing, and overall predictability of the Commission's certification process.[67]

G. The Commission's Evaluation Under the Policy Statement

24. The Policy Statement explained that the Commission will consider whether a proposed project's anticipated public benefits outweigh its residual adverse effects on economic interests. If so, the Commission will then complete an analysis of the project's environmental impacts and incorporate those findings in reaching a conclusion on whether a project is required by the public convenience and necessity. If not, an application will be denied and there will be no reason to consider environmental impacts.[68]

25. Because the NEPA review typically takes longer than the review of the non-environmental aspects of a proposed project, in practice the Commission often initiates its study of environmental impacts at the applicant's request during pre-filing and before an application is filed. Also, most natural gas projects require approvals from numerous other federal, state, and local agencies or federally recognized Indian tribes.[69] Coordinating with other agencies and ensuring that NEPA documents adequately address the Start Printed Page 18026concerns of agencies, federally recognized tribes,[70] and stakeholders can extend the time needed to complete the NEPA review process.

H. Applying the Policy Statement

1. Threshold Requirement

26. The Policy Statement's threshold requirement is that an applicant financially support the project without relying on subsidization from its existing customers.[71] For greenfield projects, this is the case by definition, as these new projects have no existing customers.[72] For existing jurisdictional natural gas companies, the Policy Statement's adoption of incremental rates as the default pricing mechanism for new capacity ensures that the project sponsor and its expansion customers bear all the economic risks of constructing and operating new facilities, without subsidization from the company's existing customers.[73] When an existing natural gas company proposes to use its existing system rates as initial recourse rates for an expansion, the natural gas company is required to demonstrate that the incremental revenue received would exceed the incremental cost of the new project before being granted approval to roll the costs of the expansion into its system rates, thereby ensuring existing customers will not subsidize the expansion.[74]

2. Factors To Be Balanced in Assessing the Need for a New Project

(a) Potential Adverse Effects on Affected Interests

27. When the no-subsidy threshold requirement is met, the next step in the Commission's analysis is to determine whether the applicant has eliminated or minimized any residual adverse effects the project might have on: (1) The applicant's existing customers, (2) existing pipelines in the market and their captive customers, and (3) landowners and communities affected by the proposed project.[75]

28. The Policy Statement recognized that the interests of an applicant's existing customers may be adversely affected if the proposed expansion results in a degradation in service for existing customers.[76] Furthermore, the interests of an existing pipeline in the same market area and its captive customers may be adversely affected by a new competitor because, under the Commission's current rate model, customer rates on an existing pipeline can rise to cover the costs of any capacity that goes unsubscribed due to volumes (i.e., customers) migrating to a new competing pipeline.

29. The Commission has historically taken a pro-competitive approach in approving new projects, believing that potential adverse impacts on existing competitors through the potential future loss of load are likely to be outweighed by the economic and reliability benefits to natural gas consumers that come from increased access to new supply sources of competitively-priced natural gas.[77] The Commission's longstanding policy has been to allow companies to compete for markets and to uphold the results of that competition absent a showing of anticompetitive or unfair competition.[78] There have been few instances where companies or their customers have raised concerns over the impact that the construction of a new project would have on an existing pipeline system or its captive customers. In those instances, competitor pipelines have argued that their captive shippers would be burdened with stranded costs or discount adjustments.[79] The Commission has historically not been persuaded by the objections, finding that a new pipeline would benefit consumers through increased competition.[80]

30. Finally, under the Policy Statement, the Commission looks at adverse impacts on landowners and communities affected by a proposed project. The Policy Statement noted that “[t]raditionally, the interests of the landowners and the surrounding community have been considered synonymous with the environmental impacts of a project,” but explains that “[l]andowner property rights issues are different in character from other environmental issues considered under [NEPA].” [81] Since issuance of the Policy Statement, the Commission's environmental analyses have come to adopt a more expansive consideration of property rights issues, so issues that previously might not have been routinely reviewed in the environmental document—e.g., a project's potential impact on property values, community development, employment, tax revenue, and disadvantaged populations—now are. Thus, these issues are, in effect, considered twice, once in the context of the Policy Statement assessment focusing on economic impacts, and again in the NEPA review focusing on environmental impacts. Economic impacts on landowners and surrounding communities can be, and often are, mitigated, for example, through alternative routing of the proposed rights-of-way, co-location with existing utility corridors, and negotiating the purchase of rights-of-way.[82]

(b) Public Benefits

31. The Policy Statement identified various public benefits including: (1) Meeting unserved demand (2) eliminating bottlenecks; (3) providing access to new supplies; (4) lowering costs to consumers; (5) providing new interconnects that improve the interstate pipeline network; (6) providing competitive alternatives; (7) increasing electric reliability; and (8) advancing clean air objectives.[83] As evidence of unserved demand following issuance of the Policy Statement, applicants have most often presented precedent agreements with prospective customers for long-term firm service.[84]

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(c) Balancing Public Benefits and Adverse Effects

32. The Policy Statement recognized that, in the context of balancing public benefits against adverse effects, it is difficult to construct bright line standards or tests, as such tests are unlikely to be flexible enough to resolve specific cases and to allow the Commission to take into account different relevant interests. The Policy Statement described a sliding scale approach where the “more interests adversely affected or the more adverse impact a project would have on a particular interest, the greater the showing of public benefits from the project required to balance the adverse impact.” [85]

33. The Policy Statement provided two examples of the sliding scale approach. First, if an applicant is able to acquire all or substantially all of the necessary rights-of-way by negotiation prior to filing the application, and the proposal is to serve a new, previously unserved market, it would not adversely impact the applicant's existing shippers, competing companies or their existing shippers, or affected landowners and communities.[86] Under these circumstances, landowners would not be subject to eminent domain proceedings, and because the proposed project would be new, there would be no existing customers who might be called upon to subsidize the project. In the second example, the Policy Statement recognized that an applicant may not be able to acquire all the necessary rights-of-way by negotiation prior to filing the application.[87] Therefore, the applicant might minimize the effect of the project on landowners by negotiating to acquire as much of the rights-of-way as possible. In this case, the applicant may be called upon to present some evidence of market demand, but under the sliding scale approach, the benefits that would need to be shown would be less than in a case where no rights-of-way had been previously acquired by negotiation. If an applicant had precedent agreements with multiple parties for most of the new capacity, this would be strong evidence of market demand and potential public benefits that could outweigh the inability to negotiate right-of-way agreements with some landowners.

34. The Policy Statement observed that a few holdout landowners cannot veto a project if the applicant provides evidence of project benefits sufficient to justify a finding of public convenience and necessity and issuance of a certificate.[88] The strength of the benefit showing will need to be proportional to the applicant's anticipated reliance on eminent domain to acquire necessary property rights. If the Commission finds project benefits will outweigh adverse impacts on economic interests, it then proceeds to consider the results of its NEPA review in reaching a decision on whether the proposed project is required by the public convenience and necessity.[89]

I. Commission Precedent and the Evolution of the Implementation of the Policy Statement

35. Prior to adopting the Policy Statement, the Commission required applicants to show that some percentage of proposed capacity was subscribed under long-term firm service agreements.[90] The Policy Statement adopted a new approach, under which the Commission would allow an applicant to rely on a variety of operational, economic, and environmental factors to demonstrate need.[91] In practice, applicants have generally elected to present, and the Commission has accepted, customer commitments as the principal factor in demonstrating project need.[92] Today, many proposed projects are fully, or nearly fully, subscribed under long-term firm service agreements that the Commission accepts as strong evidence that there is market demand for a proposed project.[93] The Commission has not looked beyond contracts for a further determination of market or supply need since the adoption of incremental pricing and the resultant shifting of the risk of constructing new capacity to the pipeline and the expansion shippers. In instances where an applicant has neither entered into any precedent agreements for its project nor submitted other evidence to show need, and the project will cause adverse effects, the Commission has declined to issue a certificate.[94]

36. Stakeholders in some proceedings have raised questions as to whether precedent agreements continue to be an appropriate indicator of project need and whether the Commission should reconsider its approach to examining project need. This includes both the question of the overall need for the proposed project within the energy marketplace, as well as the need for the capacity of individual project shippers. Specific concerns raised have included: (1) Whether existing infrastructure can accommodate the incremental service to be provided by proposed project; (2) whether anticipated demand in the project's markets will truly materialize; (3) the potential for renewable energy to meet future demand for electricity generation and its potential impacts on projects designed to serve natural gas-fired generators; (4) the need for the Commission to evaluate the new natural gas pipeline infrastructure on a region-wide basis; and (5) whether agreements with affiliates constitute a showing of market need.

II. The Commission's NEPA Review

37. Since the early 2000s, the Commission has encouraged jurisdictional natural gas companies to use a voluntary pre-filing program for natural gas pipeline projects.[95] During the pre-filing process, applicants can coordinate with Commission staff and other agencies to identify and resolve major environmental issues on a project before filing an application.[96] Proposed Start Printed Page 18028projects that would typically benefit from this pre-filing process have opted to use it. The pre-filing process allows applicants and staff to engage in enhanced and early outreach efforts with stakeholders, and often results in major and minor route modifications prior to the applicant submitting an application to avoid or minimize impacts on sensitive environmental resources identified by Commission staff, other agencies, federally recognized tribes, and affected landowners.[97] In addition to enhanced outreach efforts, during the pre-filing process Commission staff performs site visits, consults other agencies and federally recognized tribes, reviews drafts of an applicant's environmental resource reports, and provides comments to applicants regarding alternatives, siting concerns, inaccuracies, additional surveys or studies, and needed mitigation plans to improve the quality of an application. These efforts routinely result in improvements and changes to the proposed projects compared to the applicants' initial plan when initiating the pre-filing process. In conducting its assessment of the economic effects of a proposed project after an application is filed, the Commission can include relevant information about residual adverse effects developed in the pre-filing process or during a concurrent environmental review.[98]

38. In reviewing an application, the Commission currently performs a lengthy NEPA review, including numerous opportunities for public involvement, consultation with other federal, state, and local agencies, and an independent evaluation of the environmental impacts of a proposed project. In July 2015, the Commission issued guidance on best practices for stakeholder outreach programs for natural gas projects.[99] This guidance identifies the various opportunities for public engagement by project applicants and Commission staff throughout the pre-filing and NEPA review process, including project briefings to elected officials, open houses, scoping sessions, agency meetings, site visits, and NEPA document comment periods.

39. Commission staff performs a thorough independent review of the environmental impacts of a proposed project through verifying submitted information and comments, issuing information requests to clarify inaccuracies or obtain additional information, and consulting with federal, state, and local agencies and federally recognized tribes. Commission NEPA documents address impacts on various environmental resources, including geology, soils, groundwater, surface water, wetlands, aquatic resources, vegetation, wildlife, special status species, cultural resources, land use, recreation, aesthetics, socioeconomics, air quality, climate change, noise, and reliability and safety.

40. Over the past decade there has been a marked increase in the involvement of federally recognized tribes, affected landowners, and environmental organizations in proposed natural gas project proceedings. Concerns raised have primarily focused on the need for new projects, alternatives, cumulative impacts, and the effects related to the production and consumption of natural gas (particularly the contribution of GHG emissions to global climate change).

A. Alternatives

41. The Commission's NEPA documents address a wide variety of alternatives. These include the no-action alternative (i.e., the status quo), system alternatives (using existing, modified, or other proposed gas facilities), design alternatives (using a different pipeline diameter, looping versus compression, and electric-driven versus gas-driven compressor equipment), and route and siting alternatives that could satisfy the purpose and need of the proposed project. Alternatives considered include those contemplated by the applicant and those proposed by agencies, federally recognized tribes, stakeholders, and Commission staff.

42. Should the Commission find that there is insufficient support for the need for a project, it could select the no-action alternative by rejecting the proposed project. However, the Commission has neither authority to require the construction of any alternative other than the project proposed, nor does it have authority to require the development of nonjurisdictional actions or projects (e.g., renewable projects or energy conservation measures). When an alternative is not reasonable, i.e., when it cannot function as a substitute for the proposed project, the Commission does not consider it in its NEPA analysis.

B. GHG Emissions and Climate Change

43. GHG emissions are unique in that, unlike other environmental impacts studied in pipeline proceedings that have localized effects, emissions from around the globe accumulate in the atmosphere and contribute to climate change impacts worldwide.[100] In 2010, CEQ issued its first draft guidance on how federal agencies can consider the effects of GHG emissions and climate change under NEPA.[101] CEQ revised the draft guidance in 2014,[102] and issued final guidance in 2016.[103] Throughout the guidance's evolution, CEQ consistently advised agencies to quantify GHG emissions and consider both the extent to which a proposed project's GHG emissions would contribute to climate change and also how a changing climate may impact the proposed project in their NEPA documents. In April 2017, CEQ rescinded its 2016 final guidance as directed by Executive Order 13783 Start Printed Page 18029 Promoting Energy Independence and Economic Growth.[104]

44. Since CEQ issued its initial draft guidance, Commission staff has addressed climate change in its NEPA documents. Over the past seven years, Commission staff has expanded its efforts to address GHG emissions and climate change by including GHG emission estimates from project construction (e.g., tailpipe emissions from construction equipment) and operation (e.g., fuel combustion from compressor stations and gas venting and leaks). The Commission's NEPA documents also currently include any mitigation measures the applicant will employ to reduce GHG emissions, including mitigation of methane leaks. Such measures predominantly take the form of best practices and specific technologies developed under the EPA's Natural Gas STAR Program.[105] Further, the Commission's NEPA documents discuss the regulations under the Clean Air Act applicable to GHG emissions, recognize that natural gas infrastructure projects contribute GHG emissions that affect global climate change, identify the existing and projected climate change impacts occurring in a project's geographic region, and explain the impacts that climate change may have on a specific project (e.g., future sea level rise and storm surge).[106] Current and projected regional climate change impacts are based on the most recently issued National Climate Assessment[107] by the United States Global Change Research Program.[108] The current assessment provides a regional analysis of climate change for eight defined United States regions: Northeast, Southeast, Northwest, Southwest, Midwest, Great Plains, Coasts, and Alaska.

45. To the extent there exist relevant federal, regional, state, tribal, or local plans, policies, or laws for GHG emissions reductions or climate adaptations, the Commission's NEPA documents address the consistency of a proposed project's direct impacts (e.g., compressor station emissions) with those known climate goals. Individual plans may range in scope and specificity from, for example, general commitments to reduce GHG emissions, to particular plans to reduce GHG emissions by sector, as well as plans to adapt to a changing climate.

46. Historically, CEQ recognized the difficulty in identifying the extent to which a specific action or project may contribute to overall climate change, given that climate change results from the cumulative buildup of carbon dioxide and other GHGs, rather than from the incremental emissions of any one project. Additionally, there is no standard established by international or federal policy, or by a recognized scientific body that the Commission could rely on in determining whether project-specific GHG emissions are significant. Thus, the Commission has stated that, given the information available to date, any attempt by the Commission to create a significance threshold would be arbitrary.[109] CEQ's revised draft and final guidance cautioned agencies about calculating a proposed project's emissions as a percentage of sector, nationwide, or global emissions in determining significance, “unless the agency determines that such information would be helpful to decision makers and the public to distinguish among alternatives and mitigations. . . . .” [110] Generally, this percentage would be too low to be considered meaningful because project emissions would be miniscule compared to nationwide or global emissions. CEQ's past guidance also stated that agencies need not undertake new research or analysis of potential climate change in the proposed project area, but may instead summarize and incorporate by reference the relevant scientific literature.[111]

47. In recent years, commenters began raising GHG issues on an increasingly frequent basis in Commission proceedings and on appellate review, with emphasis on upstream and downstream GHG emissions.[112] Some commenters suggest that the Commission's current analyses of GHG emissions and climate change are inadequate. They argue that all projects relying on fossil fuels should be considered to cause a significant impact on climate change. Commenters also request that the Commission employ the Social Cost of Carbon tool [113] to monetize climate change impacts from estimated GHG emissions.

48. The Commission has generally declined to consider the upstream or downstream GHG emissions impacts of natural gas production or end use as indirect impacts of the proposed project because the Commission found no requisite causation and/or because the impacts of such production or end use were speculative and unknown, and therefore not reasonably foreseeable.[114] With respect to the cumulative impacts analysis in which causation is not relevant, no analysis of GHG emissions from upstream and downstream activities was included except where identified upstream production wells (new) or end-use facilities (existing or proposed) were within the geographic and temporal scope of the proposed project's direct and indirect impacts.[115]

49. In late 2016 the Commission began providing the public with additional information, beyond the requirements of NEPA and its implementing regulations, regarding potential impacts associated with upstream unconventional natural gas production and downstream natural gas combustion even where the criteria of causation and reasonable foreseeability Start Printed Page 18030were absent.[116] Recent studies identify, on a generic, high-level basis, potential environmental impacts associated with natural gas production and natural gas-fired power generation.[117] In Commission orders for projects intended to transport gas produced from the Marcellus and Utica shales, the Commission used this information to provide general estimates of production-related GHG emissions, such as methane released from wells and gathering facilities, and production-related land disturbance and water consumption.[118] The Commission estimated downstream GHG emissions by assuming the full combustion of the total volume of gas capable of being transported by the project, typically as part of the cumulative impact analysis.[119] The Commission described the full combustion estimate as a worst-case scenario that is unlikely to reflect actual impacts.[120] However, in a recent order, DTE Midstream Appalachia, LLC,[121] the Commission did not include information on upstream, production-related impacts, stating that “[a] broad analysis, based on generalized assumptions rather than specific information, will not provide meaningful assistance to the Commission in its decision making, e.g., evaluating potential alternatives to a specific proposal.” [122]

50. As for the use of the Social Cost of Carbon tool, the Commission has found that although this tool is appropriate to use as part of cost-benefit analyses associated with certain rulemakings, it is not useful or appropriate to apply in its NEPA documents.[123]

III. Request for Comments

51. As part of ensuring that the Commission continues to meet its statutory obligations, the Commission, on occasion, engages in public inquiry to gauge whether there is a need to add to, modify, or eliminate certain policies or regulatory requirements. In this proceeding, the Commission seeks comments on potential modifications to its approach to determining whether a proposed project is required by the public convenience and necessity. The Commission has identified four general areas of examination in this inquiry: (1) The reliance on precedent agreements to demonstrate need for a proposed project; (2) the potential exercise of eminent domain and landowner interests; (3) the Commission's evaluation of alternatives and environmental effects under NEPA and the NGA; and (4) the efficiency and effectiveness of the Commission's certificate processes. The Commission seeks comment on the questions set forth below, organized according to these four broad categories. Commenters need not answer every question enumerated below.

A. Potential Adjustments to the Commission's Determination of Need

52. In practice, the Commission does not look “behind” or “beyond” precedent agreements when making a determination about the need for new projects or the needs of the individual shippers. The United States Court of Appeals for the District of Columbia Circuit recently found “nothing in the policy statement or in any precedent construing it to suggest that it requires, rather than permits, the Commission to assess a project's benefits by looking beyond the market need reflected by the applicant's existing contracts with shippers.” [124]

53. In retail gas distribution markets, state regulators review LDC commodity and capacity purchases. State regulators also may review electric distribution company fuel purchases. Thus, in these regions, state regulators may review the purchases to determine the prudence of expenditures by the utilities they regulate. For parties purchasing interstate transportation capacity who are not subject to state regulatory oversight, the fact that a purchaser is fully at risk for the cost of the capacity and cannot directly pass through the costs to another party has lessened the need to scrutinize such agreements.

To date, the Commission has not distinguished between affiliate and non-affiliate precedent agreements in considering the need for a proposed project.[125]

54. However, recent changes in the gas industry, whereby producers are contracting for an increasing amount of transportation capacity as well as an increase in the number of shippers that are affiliated with the pipeline companies, have raised questions among some entities as to whether precedent agreements remain an appropriate indicator of need and whether the Commission should examine additional information in evaluating the need for proposed pipeline infrastructure projects. Accordingly, comments are requested on the following questions.

A1. Should the Commission consider changes in how it determines whether there is a public need for a proposed project?

A2. In determining whether there is a public need for a proposed project, what benefits should the Commission consider? For example, should the Commission examine whether the proposed project meets market demand, enhances resilience or reliability, promotes competition among natural gas companies, or enhances the functioning of gas markets?

A3. Currently, the Commission considers precedent agreements, whereby entities intending to be shippers on the contemplated pipeline commit contractually to such shipments, to be strong evidence that there is a public need for a proposed project. If the Commission were to look beyond precedent agreements, what types of additional or alternative evidence should the Commission examine to determine project need? What would such evidence provide that cannot be determined with precedent agreements alone? How should the Commission assess such evidence? Is there any heightened litigation risk or other risk that could result from any broadening of the scope of evidence the Commission considers during a certificate proceeding? If so, how should the Commission safeguard against or otherwise address such risks?

A4. Should the Commission consider distinguishing between precedent agreements with affiliates and non-affiliates in considering the need for a proposed project? If so, how?

A5. Should the Commission consider whether there are specific provisions or Start Printed Page 18031characteristics of the precedent agreements that the Commission should more closely review in considering the need for a proposed project? For example, should the term of the precedent agreement have any bearing on the Commission's consideration of need or should the Commission consider whether the contracts are subject to state review?

A6. In its determinations regarding project need, should the Commission consider the intended or expected end use of the natural gas? Would consideration of end uses better inform the Commission's determination regarding whether there is a need for the project? What are the challenges to determining the ultimate end use of the new capacity a shipper is contracting for? How could such challenges be overcome?

A7. Should the Commission consider requiring additional or alternative evidence of need for different end uses? What would be the effect on pipeline companies, consumers, gas prices, and competition? Examples of end uses could include: LDC contracts to serve domestic use; contracts with marketers to move gas from a production area to a liquid trading point; contracts for transporting gas to an export facility; projects for reliability and/or resilience; and contracts for electric generating resources.

A8. How should the Commission take into account that end uses for gas may not be permanent and may change over time?

A9. Should the Commission assess need differently if multiple pipeline applications to provide service in the same geographic area are pending before the Commission? For example, should the Commission consider a regional approach to a needs determination if there are multiple pipeline applications pending for the same geographic area? Should the Commission change the way it considers the impact of a new project on competing existing pipeline systems or their captive shippers? If so, what would that analysis look like in practice?

A10. Should the Commission consider adjusting its assessment of need to examine (1) if existing infrastructure can accommodate a proposed project (beyond the system alternatives analysis examined in the Commission's environmental review); (2) if demand in a new project's markets will materialize; or (3) if reliance on other energy sources to meet future demand for electricity generation would impact gas projects designed to supply gas-fired generators? If so, how?

B. The Exercise of Eminent Domain and Landowner Interests

55. The Policy Statement described how the Commission takes into account the extent to which an applicant expects to acquire property rights by relying on eminent domain in determining whether a proposed project is needed. Although Commission authorization of a project through the issuance of a certificate of public convenience and necessity under the NGA conveys the right of eminent domain, the Commission itself does not grant the use of eminent domain across specific properties. Only after the Commission authorizes a project can the project sponsor assert the right of eminent domain for outstanding lands for which it could not negotiate an easement.

56. Recently, the Commission has been seeing more proposed projects where applicants are unable to access potential rights-of-way prior to the Commission's decision on an application, which limits the information that can be included in an application.

57. Historically, an applicant's inability to complete on-site survey work has not precluded the Commission from completing a meaningful review of a proposal since partial on-site surveys, in combination with aerial overflight and data from other sources, can provide an adequate basis for the Commission to reach an informed decision. The Commission's NEPA documents are based on the best available data at the time of development.[126] When information from other data sources is used to complete a NEPA review, the Commission routinely conditions its authorizations requiring applicants to perform on-site surveys to verify this information, prior to construction. In addition, the Commission has developed standard and effective construction mitigation, and restoration and rehabilitation procedures applicable to wetlands and waterbodies, cultural resources, and endangered, threatened, and special concern species.[127] Because project sponsors must adhere to these established procedures, if survey work is incomplete at the time a Commission certificate order is issued, these procedures assure that impacts on resources are adequately minimized during construction. The Commission invites comments on the following questions.

B1. Should the Commission consider adjusting its consideration of the potential exercise of eminent domain in reviewing project applications? If so, how should the Commission adjust its approach?

B2. Should applicants take additional measures to minimize the use of eminent domain? If so, what should such measures be? How would that affect a project's overall costs? How could such a requirement affect an applicant's ability to adjust a proposed route based on public input received during the Commission's project review?

B3. For proposed projects that will potentially require the exercise of eminent domain, should the Commission consider changing how it balances the potential use of eminent domain against the showing of need for the project? Since the amount of eminent domain used cannot be established with certainty until after a Commission order is issued, is it possible for the Commission to reliably estimate the amount of eminent domain a proposed project may use such that the Commission could use that information during the consideration of an application?

B4. Does the Commission's current certificate process adequately take landowner interests into account? Are there steps that applicants and the Commission should implement to better take landowner interests into account and encourage landowner participation in the process? If so, what should the steps be?

B5. Should the Commission reconsider how it addresses applications where the applicant is unable to access portions of the right-of-way? Should the Commission consider changes in how it considers environmental information gathered after an order authorizing a project is issued?

C. The Commission's Consideration of Environmental Impacts

58. Among the goals in the Policy Statement is the avoidance of unnecessary disruption of the environment. The Commission incorporates a proposed project's environmental impacts into the balance of factors under the public convenience and necessity standard. Although the Commission performs a comprehensive and independent NEPA review, as described above, there has been increased stakeholder interest regarding the alternatives that the Commission evaluates in its public interest determination, how the Commission addresses climate change, and the evolving science behind GHG emissions and climate change. Therefore, the Commission invites comments on the following ways that the Commission could review its environmental evaluations within the bounds of NEPA and the NGA:

Start Printed Page 18032

C1. NEPA and its implementing regulations require an agency to consider reasonable alternatives to the proposed action. Currently the Commission considers the no-action alternative, system alternatives, design alternatives, and route alternatives. Should the Commission consider broadening its environmental analysis to consider alternatives beyond those that are currently included? If so, what specific types of additional alternatives should the Commission consider?

C2. Are there any environmental impacts that the Commission does not currently consider in its cumulative impact analysis that could be captured with a broader regional evaluation? If so, how broadly should regions be defined (e.g., which states or geographic boundaries best define different regions), and which environmental resources considered in NEPA would be affected on a larger, regional scale?

C3. In conducting an analysis of a project, should the Commission consider calculating the potential GHG emissions from upstream activities (e.g., the drilling of natural gas wells)? What information would be necessary for the Commission to reliably and accurately conduct this calculation? Should the Commission also evaluate the significance of these upstream impacts? If so, what criteria would be used to determine the significance of these impacts?

C4. In conducting an analysis of a project, should the Commission consider calculating the potential GHG emissions from the downstream consumption of the gas? If so, should the Commission base this calculation on total consumption, or some other amount? What information would be necessary for the Commission to reliably and accurately conduct this calculation? Should the Commission also evaluate the significance of these downstream impacts? If so, what criteria would be used to determine the significance of these impacts?

C5. How would additional information related to the GHG impacts upstream or downstream of a proposed project inform the Commission's decision on an application? What topics or criteria should be included in this additional information?

C6. As part of the Commission's public interest determination, should the Commission consider changing how it weighs a proposed project's adverse environmental impacts against favorable economic benefits to determine whether the proposed project is required by the public convenience and necessity and still provide regulatory certainty to stakeholders?

C7. Should the Commission reconsider how it uses the Social Cost of Carbon tool in its environmental review of a proposed project? How could the Commission use the Social Cost of Carbon tool in its weighing of the costs versus benefits of a proposed project? How could the Commission acquire complete information to appropriately quantify all of the monetized costs/negative impacts and monetized benefits of a proposed project?

D. Improvements to the Efficiency of the Commission's Review Process

59. It is the Commission's desire to improve the transparency, timing, and predictability of the Commission's certification process.[128] In addition, as noted above, Executive Order 13807 encourages agencies to make timely decisions with the goal of completing all Federal environmental reviews and authorization decisions for major infrastructure projects within 2 years. Inefficiencies in project decision-making can delay infrastructure investments, increase project costs, and block infrastructure that would benefit the economy.

60. The Commission seeks comment on the following questions regarding its certificate application review process:

D1. Should certain aspects of the Commission's application review process (i.e., pre-filing, post-filing, and post-order-issuance) be shortened, performed concurrently with other activities, or eliminated, to make the overall process more efficient? If so, what specific changes could the Commission consider implementing?

D2. Should the Commission consider changes to the pre-filing process? How can the Commission ensure the most effective participation by interested stakeholders during the pre-filing process and how would any such changes affect the implementation and duration of the pre-filing process?

D3. Are there ways for the Commission to work more efficiently and effectively with other agencies, federal and state, that have a role in the certificate review process? If so, how?

D4. Are there classes of projects that should appropriately be subject to a shortened process? What would the shortened process entail?

IV. Comment Procedures

61. The Commission invites interested persons to submit comments on the matters and issues proposed in this notice, including any related matters or alternative proposals that commenters may wish to discuss. Comments are due June 25, 2018. Comments must refer to Docket No. PL18-1-000, and must include the commenter's name, the organization they represent, if applicable, and their address in their comments.

62. The Commission encourages comments to be filed electronically via the eFiling link on the Commission's website at The Commission accepts most standard word-processing formats. Documents created electronically using word-processing software should be filed in native applications or print-to-PDF format and not in a scanned format. Commenters filing electronically do not need to make a paper filing.

63. Commenters that are not able to file comments electronically must send an original of their comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE, Washington, DC 20426.

64. All comments will be placed in the Commission's public files and may be viewed, printed, or downloaded remotely as described in the Document Availability section below. Commenters on this proposal are not required to serve copies of their comments on other commenters.

V. Document Availability

65. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the internet through the Commission's Home Page ( and in the Commission's Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. eastern time) at 888 First Street NE, Room 2A, Washington, DC 20426.

66. From the Commission's Home Page on the internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field.

67. User assistance is available for eLibrary and the Commission's website during normal business hours from the Commission's Online Support at 202-502-6652 (toll free at 1-866-208-3676) or email at, or the Public Reference Room at (202) 502-8371, TTY (202) 502-8659. Email the Public Reference Room at

Start Signature

By direction of the Commission.

Issued: April 19, 2018.

Nathaniel J. Davis, Sr.,

Deputy Secretary.

End Signature End Supplemental Information


1.  Certification of New Interstate Natural Gas Pipeline Facilities, 88 FERC ¶ 61,227 (1999), clarified, 90 FERC ¶ 61,128, further clarified, 92 FERC ¶ 61,094 (2000) (Policy Statement).

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3.  The total miles of interstate natural gas pipeline authorized by the Commission on an annual basis has fluctuated over time, but in recent years reached a high of 2,739 miles in 2017. See generally Federal Energy Regulatory Commission, 2017 State of the Markets Report, at 4 (Apr. 2018),​market-oversight/​market-oversight.asp (providing the number of approved pipelines projects and miles for 2017).

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5.  Policy Statement, 88 FERC ¶ 61,227 at 61,737.

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6.  The Commission is aware that some of the issues raised in this Notice of Inquiry may overlap with issues raised in pending matters. In this Notice of Inquiry proceeding, the Commission will consider only generic issues, and will not consider any comments that refer to open, contested Commission proceedings.

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8.  Id. 717f(c)(1)(A).

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9.  Id. 717f(e).

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10.  See generally 18 CFR 157.1-157.22 (regulations governing applications); id. pt. 380 (implementing NEPA, the Endangered Species Act, and the National Historic Preservation Act, and prescribing environmental reports for Natural Gas Act applications).

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12.  Atl. Refining Co. v. Pub. Serv. Comm'n of N.Y., 360 U.S. 378, 391 (1959).

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13.  NAACP v. Fed. Power Comm'n, 425 U.S. 662, 669-70 (1976).

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16.  Fed. Power Comm'n v. Transcontinental Gas Pipe Line Corp., 365 U.S. 1, 23 (1961).

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18.  See, e.g., Transcontinental Gas Pipe Line Corp., 365 U.S. at 17 (the Commission “can only exercise a veto power over proposed transportation and it can only do this when a balance of all the circumstances weighs against certification”).

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19.  Policy Statement, 88 FERC ¶ 61,227 at 61,747.

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20.  NGA section 1(b) states that Commission authority applies to interstate transportation of natural gas and sales for resale, “but shall not apply to any other transportation or sale of natural gas or to the local distribution of natural gas or to the facilities used for such distribution or to the production or gathering of natural gas.” 15 U.S.C. 717(b).

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21.  Section 201 of the Federal Power Act states, the Commission “shall not have jurisdiction, except as specifically provided in this Part and the Part next following, over facilities used for the generation of electric energy.” 16 U.S.C. 824.

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23.  Baltimore Gas & Elec. Co. v. Nat. Res. Defense Council, Inc., 462 U.S. 87, 97 (1983) (discussing the twin aims of NEPA).

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25.  Id. 1501.4 (detailing when to prepare an EA versus an EIS).

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26.  Robertson v. Methow Valley Citizen's Council, 490 U.S. 332, 350 (1989); see also Baltimore Gas & Elec. Co., 462 U.S. at 97 (citing Stryckers' Bay Neighborhood Council v. Karlen, 444 U.S. 223, 227 (1980)).

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27.  40 CFR 1508.9 (describing requirements for an EA).

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28.  Colo. Envtl. Coal. v. Dombeck, 185 F.3d 1162, 1175 (10th Cir. 1999).

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29.  Forty Most Asked Questions Concerning CEQ's National Environmental Policy Act Regulations, 46 FR 18026, 18027 (Mar. 23, 1981).

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30.  Citizens Against Burlington, Inc. v. Busey, 938 F.2d 190, 195, 199 (DC Cir. 1991).

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31.  40 CFR 1502.14(a). See, e.g., Bradwood Landing LLC, 126 FERC ¶ 61,035, at P 158 (2009); Broadwater Energy LLC, 124 FERC ¶ 61,225, at PP 187-189 (2008) (rejecting alternatives that were not technically and economically feasible and practical, or did not offer significant environmental advantages over the proposed project or its components, or were unavailable and/or incapable of being implemented, or do not meet the applicants' stated project objectives).

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33.  Id. 1508.25(a)(1)-(2).

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34.  Id. 1508.25(a)(3).

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35.  Id. 1508.8(b).

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36.  Id. 1508.7.

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37.  “[A] consideration of cumulative impacts must also consider `[c]losely related and proposed or reasonably foreseeable actions that are related by timing or geography.'” O'Reilly v. U.S. Army Corps of Engineers, 477 F.3d 225 at 234 (5th Cir. 2007) (quoting Vieux Carre Prop. Owners, Residents, & Assocs., Inc. v. Pierce, 719 F.2d 1272, 1277 (5th Cir. 1983)); see also CEQ, Considering Cumulative Effects Under the National Environmental Policy Act, at 12-16 (Jan. 1997),​sites/​prod/​files/​nepapub/​nepa_​documents/​RedDont/​G-CEQ-ConsidCumulEffects.pdf.

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39.  Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, FERC Stats. & Regs. ¶ 30,665 (1985), vacated and remanded, Associated Gas Distribs. v. FERC, 824 F.2d 981 (D.C. Cir. 1987), readopted on an interim basis, Order No. 500, FERC Stats. & Regs. ¶ 30,761 (1987), remanded, Am. Gas Ass'n v. FERC, 888 F.2d 136 (D.C. Cir. 1989), readopted, Order No. 500-H, FERC Stats. & Regs. ¶ 30,867 (1989), reh'g granted in part and denied in part, Order No. 500-I, FERC Stats. & Regs. ¶ 30,880 (1990), aff'd in part and remanded in part, Am. Gas Ass'n v. FERC, 912 F.2d 1496 (D.C. Cir. 1990), order on remand, Order No. 500-J, FERC Stats. & Regs. ¶ 30,915, order on remand, Order No. 500-K, FERC Stats. & Regs. ¶ 30,917, reh'g denied, Order No. 500-L (1991).

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40.  Public Law 101-60, 103 Stat. 157 (1989).

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41.  Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation; and Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, Order No. 636, FERC Stats. & Regs. ¶ 30,939, at 30,391 (footnote omitted), order on reh'g, Order No. 636-A, FERC Stats. & Regs. ¶ 30,950, order on reh'g, Order No. 636-B, 61 FERC ¶ 61,272 (1992), order on reh'g, 62 FERC ¶ 61,007 (1993), aff'd in part and remanded in part sub nom. United Dist. Cos. v. FERC, 88 F.3d 1105 (D.C. Cir. 1996), order on remand, Order No. 636-C, 78 FERC ¶ 61,186 (1997).

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42.  Energy Information Administration (EIA), Natural Gas 1998: Issues and Trends, DOE/EIA-0560(98), at 71, 109, 115 (Apr. 1999).

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43.  See, e.g., Policy Statement, 88 FERC ¶ 61,227 at 61,741 (summarizing comments from the American Gas Association, Baltimore Gas and Electric Company, and Philadelphia Gas Works requesting that pipelines not be allowed to impose the costs of unsubscribed capacity created through the construction of excess capacity on existing shippers).

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44.  Pricing Policy for New and Existing Facilities Constructed by Interstate Natural Gas Pipelines, 71 FERC ¶ 61,241 (1995), order on reh'g, 75 FERC¶ 61,105 (1996).

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45.  Id., 71 FERC ¶ 61,241 at 61,916-61,917.

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46.  Regulation of Short-Term Natural Gas Transportation Services, Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,533 (1998) (cross-referenced at 84 FERC ¶ 61,085).

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47.  Regulation of Interstate Natural Gas Transportation Services, Notice of Inquiry, FERC. Stats. & Regs. ¶ 35,533 (1998) (cross-referenced at 84 FERC ¶ 61,087).

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48.  NOPR, FERC Stats. & Regs. ¶ 32,533 at 33,489-90.

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49.  Policy Statement, 88 FERC ¶ 61,227 at 61,737.

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50.  Id. at 61,743. These same aims apply to this Notice of Inquiry.

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51.  The Policy Statement recognized there may be instances where expansion project costs should be rolled into the rates of existing customers; for example, when inexpensive expansibility is made possible because of earlier, costly construction. In such a case, “because the existing customers bear the cost of the earlier, more costly construction in their rates, incremental pricing could result in the new customers receiving a subsidy from the existing customers because the new customers would not face the full cost of the construction that makes their new service possible.” Policy Statement, 88 FERC ¶ 61,227 at 61,746.

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53.  Id. at 61,745.

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55.  EIA, Natural Gas Summary (Mar. 30, 2018) (in table see row labeled “Dry Production;” click link in the final column to view history) (Natural Gas Summary),​dnav/​ng/​ng_​sum_​lsum_​dcu_​nus_​a.htm.

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56.  EIA, Annual Energy Outlook 2018, at tbl.13 (Feb. 6, 2018) (in table see row labeled “Dry Gas Production” under the reference case) (Annual Energy Outlook 2018),​outlooks/​aeo/​data/​browser/​#/​ ?id=13-AEO2018&cases=ref2018&sourcekey=0.

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57.  Natural Gas Summary (in table compare rows labeled “Imports” and “Exports”).

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58.  Id. (in table see row labeled “Total Consumption;” click link in the final column to view history).

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59.  Annual Energy Outlook 2018, at tbl.13 (in table see row labeled “Consumption by Sector” under the reference case).

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60.  In 2010, the Commission authorized about 24 pipeline projects comprising 9.2 billion cubic feet (Bcf) per day, 20 storage projects comprising 149 Bcf per day capacity with 5.6 Bcf per day deliverability, and no LNG import/export facilities. In 2017, the Commission authorized about 49 pipeline projects comprising 30.8 Bcf per day and 2 storage projects comprising no new capacity but increased deliverability. Between 2014 and 2017 the Commission also authorized 13 LNG import/export projects for 16 Bcf per day deliverability.

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61.  New York's shale reserves remain undeveloped due to a prohibition on high-volume hydraulic fracturing in effect since 2008.

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62.  A greenfield pipeline is defined as a new pipeline system that is operated as a separately regulated company with its own rates and tariff. For example, the NEXUS Project is a greenfield pipeline. NEXUS Gas Transmission, LLC, 160 FERC ¶ 61,022 (2017).

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63.  A pipeline loop is a segment of pipe constructed parallel to an existing pipeline to increase capacity. For example, Southern Natural Gas Company, L.L.C.'s Fairburn Expansion Project includes a 1.6-mile-long, 30-inch-diameter pipeline loop to add capacity to the system. S. Nat. Gas Co., L.L.C., 162 FERC ¶ 61,122 (2018).

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64.  Exec. Order No. 13807, 82 FR 40463, 40463 (Aug. 15, 2017).

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66.  Id. Executive Order 13807 defines “major infrastructure project” as “an infrastructure project for which multiple authorizations by Federal agencies will be required to proceed with construction, the lead Federal agency has determined that it will prepare an environmental impact statement” under NEPA “and the project sponsor has identified the reasonable availability of funds sufficient to complete the project.” Id. 40464.

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67.  The Commission is a signatory to the Memorandum of Understanding Implementing the One Federal Decision under Executive Order 13807, which is available at​wp-content/​uploads/​2018/​04/​MOU-One-Federal-Decision-m-18-13-Part-2.pdf.

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68.  E.g., Turtle Bayou Gas Storage Co., LLC, 135 FERC ¶ 61,233 (2014) (Turtle Bayou).

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69.  For example, projects may require Clean Water Act section 401 water quality certifications, Clean Air Act permits, and concurrence letters or Biological Opinions from the National Marine Fisheries Service or United States Fish and Wildlife Service.

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70.  The Commission consults with potentially affected federally recognized Indian tribes as set forth in our tribal consultation policy statement. Policy Statement on Consultation with Indian Tribes in Commission Proceedings, Order No. 635, FERC Stats. & Regs. ¶ 31,148 (2003) (cross-referenced at 104 FERC ¶ 61,108).

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71.  Policy Statement, 88 FERC ¶ 61,227 at 61,746.

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72.  E.g., Sierrita Gas Pipeline, LLC, 147 FERC ¶ 61,192 (2014).

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73.  Trailblazer Pipeline Co., 95 FERC ¶ 61,258 (2001); see also E. Tenn. Nat. Gas LLC, 154 FERC ¶ 61,161 (2016).

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74.  The Policy Statement also allows projects that are designed to improve service to existing customers (i.e., by replacing existing capacity or improving reliability) to be rolled into system rates. The Policy Statement explained that increasing the rates of the existing customers to pay for these improvements is not a subsidy. Policy Statement, 88 FERC ¶ 61,227 at 61,746 n.12.

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75.  Id at 61,745.

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76.  As part of the certification process the Commission confirms through engineering analyses that the proposed facilities are appropriately designed to provide the proposed new services and verifies that the proposed project will not adversely affect the services the applicant is obligated to provide to its existing customers. See, e.g., Tex. Gas Transmission, LLC, 152 FERC ¶ 61,160 (2015).

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77.  E.g., Ruby Pipeline, L.L.C., 128 FERC ¶ 61,224, at PP 37-39 (2009); Guardian Pipeline, L.L.C., 91 FERC ¶ 61,285, at 61,976-61,977 (2000).

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78.  Ruby Pipeline, 128 FERC ¶ 61,224 at P 35; Guardian Pipeline, 91 FERC ¶ 61,285 at 61,977.

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79.  Ruby Pipeline, 128 FERC ¶ 61,224 at PP 22-26; Guardian Pipeline, 91 FERC ¶ 61,285 at 61,974-61,975.

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80.  Ruby Pipeline, 128 FERC ¶ 61,224 at P 37; Guardian Pipeline, 91 FERC ¶ 61,285 at 61,976-61,977.

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81.  Policy Statement, 88 FERC ¶ 61,227 at 61,748.

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82.  For example, Columbia Gas Transmission, LLC, incorporated eight route variations between issuance of the draft EIS and final EIS of its Leach XPress Project to address landowner requests. Final EIS, at 2-5 (Sept. 1, 2016) (Docket No. CP15-514-000). Also, Algonquin Gas Transmission, LLC, collocated 93 percent of its Algonquin Incremental Market Project pipeline facilities within or adjacent to existing right-of-ways, including its own pipelines, public roadways, railways and electric transmission line corridors. Final EIS, at 2-12 (Jan. 23, 2014) (Docket No. CP14-96-000).

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83.  Policy Statement, 88 FERC ¶ 61,227 at 61,748.

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84.  In the order authorizing a new project, the Commission requires that prior to construction, the certificate-holder must file a written statement affirming that it has executed contracts that reflect the service commitments described in precedent agreements.

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85.  Policy Statement, 88 FERC ¶ 61,227 at 61,749.

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88.  Policy Statement, 88 FERC ¶ 61,227 at 61,749.

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89.  In practice the environmental document is prepared concurrently with the analysis of the economic considerations. However, as described above, if a project's anticipated public benefits fail to outweigh its residual adverse effects on economic interests, the proposal will be denied and there will be no need to consider what the environmental impacts of the project would have been.

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90.  E.g., El Paso Nat. Gas Co., 65 FERC ¶ 61,276, at 61,270-61,271 (1993) (requiring applicant to submit “long-term” contracts or precedent agreements for a “substantial amount” of proposed firm transportation capacity); Tex. E. Transmission Corp., 82 FERC ¶ 61,238, at 61,915-61,917 (1998) (explaining that a minimum level of 25 percent evolved after El Paso Natural Gas).

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91.  Policy Statement, 88 FERC ¶ 61,227 at 61,747 (“the Commission will consider all relevant factors reflecting on the need for the project. These might include, but would not be limited to, precedent agreements, demand projections, potential cost savings to consumers, or a comparison of projected demand with the amount of capacity currently serving the market.”).

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92.  See, e.g., PennEast Pipeline Co., LLC, 162 FERC ¶ 61,053, at PP 27-36 (2018) (PennEast); Atlantic Coast Pipeline, LLC, 161 FERC ¶ 61,042, at PP 56-63 (2017) (Atlantic Coast).

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93.  Policy Statement, 88 FERC ¶ 61,227 at 61,743; see, e.g., PennEast, 162 FERC ¶ 61,053 (990,000 Dth/d of 1,107,000 Dth/d capacity subscribed); Mountain Valley Pipeline, LLC, 161 FERC ¶ 61,043 (2017) (2,000,000 Dth/d fully subscribed); Atlantic Coast, 161 FERC ¶ 61,042 (1,440,000 Dth/d of 1,500,000 Dth/d capacity subscribed); Rover Pipeline LLC, 158 FERC ¶ 61,109, at P 44 (2017) (3,100,000 Dth/d of 3,250,000 Dth/d capacity subscribed).

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94.  See, e.g., Jordan Cove Energy Project, L.P., 154 FERC ¶ 61,190, reh'g denied, 157 FERC ¶ 61,194 (2016); Turtle Bayou, 135 FERC ¶ 61,233.

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95.  In addition, in response to the Energy Policy Act of 2005, the Commission established pre-filing regulations, which are mandatory for LNG terminal facilities. 18 CFR 157.21.

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96.  The Kern River 2003 Expansion Project (Docket No. CP01-422-000) was the first project to use the Commission's Pre-filing Process.

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97.  For example, after participating in the pre-filing process and holding over 200 meetings with public officials, as well as 15 “informational sessions” for impacted landowners, PennEast incorporated 70 of 101 identified route variations into its final proposed route. PennEast, 162 FERC ¶ 61,053 at P 39.

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98.  The early elimination or refinement of proposals before and during Commission review leads to a high rate of project certification, subject to protective conditions. This does not demonstrate a bias in favor of certification, as past participants have claimed. See, e.g., NO Gas Pipeline v. FERC, 756 F.3d 764, 770 (DC Cir. 2014) (“Presumably under most regulatory schemes, by the time applicants and their expert counsel have worked through changes, adaptations, and amendments, they are not likely to pursue many certificates that are hopeless. The fact that they generally succeed in choosing to expend their resources on applications that serve their own financial interests does not mean that an agency which recognizes merit in such applications is biased.”); Minisink Residents for Envtl. Pres. and Safety v. FERC, 762 F.3d 97, 108 n.7 (DC Cir. 2014) (Minisink) (same).

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99.  FERC, Suggested Best Practices for Industry Outreach Programs to Stakeholders, (2015),​industries/​gas/​enviro/​guidelines/​stakeholder-brochure.pdf. See also FERC, Guidelines for Reporting on Cultural Resources Investigations for Natural Gas Projects (2017),​industries/​gas/​enviro/​guidelines/​cultural-guidelines-final.pdf.

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100.  On December 15, 2009, the Environmental Protection Agency (EPA) defined air pollution to include the mix of six long-lived and directly emitted GHGs, finding that the presence of GHGs in the atmosphere may endanger public health and welfare through climate change. Endangerment Finding and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act, 74 FR 66496 (Dec. 15, 2009).

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101.  CEQ, Draft NEPA Guidance on Consideration of the Effects of Climate Change and Greenhouse Gas Emissions, (Feb. 18, 2010),​docs/​ceq-regulations-and-guidance/​20100218-nepa-consideration-effects-ghg-draft-guidance.pdf.

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102.  Revised Draft Guidance for Federal Departments and Agencies on Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in NEPA Reviews, 79 FR 77802 (Dec. 18, 2014) (Revised Draft GHG Guidance).

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103.  CEQ, Final Guidance for Federal Departments and Agencies on Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in National Environmental Policy Act Reviews, (Aug. 1, 2016) (Final GHG Guidance),​docs/​ceq-regulations-and-guidance/​nepa_​final_​ghg_​guidance.pdf.

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104.  Exec. Order No. 13783, 82 FR 16576 (Apr. 5, 2017).

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105.  EPA's Natural Gas STAR program is a voluntary partnership between the EPA and industry to “encourage oil and natural gas companies to adopt cost-effective technologies and best practices that improve operational efficiency and reduce methane emissions.”

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107.  The current report is the Third National Climate Assessment, issued in May 2014.​. The United States Global Change Research Program anticipates releasing the Fourth National Climate Assessment in late 2018.

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108.  The United States Global Change Research Program consists of 13 federal agencies and is overseen by the Subcommittee on Global Change Research of the National Science and Technology Council's Committee on Environment, Natural Resources and Sustainability, and the White House Office of Science and Technology Policy. The federal agencies are the Departments of Agriculture, Commerce, Defense, Energy, Health and Human Services, Interior, State, and Transportation, as well as the EPA, the National Aeronautics and Space Administration, the National Science Foundation, the Smithsonian Institution, and the United States Agency for International Development.

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109.  Fla. Se. Connection, LLC, 162 FERC ¶ 61,233, at PP 26-27 (2018) (LaFleur and Glick, Comm'rs, dissenting).

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110.  Revised Draft GHG Guidance, 79 FR at 77808; accord Final GHG Guidance at 11, 15-16.

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111.  Final GHG Guidance at 22.

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112.  See, e.g., Atlantic Coast, 161 FERC ¶ 61,042; Transcontinental Gas Pipe Line Co., LLC, 158 FERC ¶ 61,125, order amending certificate, 159 FERC¶ 62,181, order on reh'g, 161 FERC ¶ 61,250 (2017), order denying reh'g, 162 FERC ¶ 61,192 (2018).

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113.  See generally Interagency Working Group on Social Cost of Carbon, United States Government, Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866 (Aug. 2016),​sites/​production/​files/​2016-12/​documents/​sc_​co2_​tsd_​august_​2016.pdf.

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114.  See, e.g., Cent. N.Y. Oil & Gas Co., 137 FERC ¶ 61,121, at PP 95-105, on reh'g, 138 FERC¶ 61,104, at PP 46-48 (2012), aff'd sub nom. Coal. For Responsible Growth & Res. Conservation v. FERC, 485 F. App'x 472 (2d Cir. 2012) (unpublished opinion).

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115.  For example, in the EIS for the proposed Aguirre Offshore GasPort, a jurisdictional floating storage regasification unit and subsea pipeline to deliver gas to an existing non-jurisdictional generating complex, Commission staff disclosed the expected emissions, including GHG emissions, from both the jurisdictional project and non-jurisdictional generating station. Final EIS for the Aquirre Offshore GasPort Project,— at 4-221, tbl.4.12.2-1 (Feb. 20, 2015) (Docket No. CP13-193-000).

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116.  See, e.g., Columbia Gas Transmission, LLC, 158 FERC ¶ 61,046, at PP 116-120 (2017).

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117.  E.g., National Energy Technology Laboratory, U.S. Department of Energy, Life Cycle Analysis of Natural Gas Extraction and Power Generation, DOE/NETL-2015/1714 (2016),​energy-analyses/​temp/​LifeCycleAnalysisofNaturalGasExtractionandPowerGeneration_​083016.pdf.

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118.  E.g., PennEast, 162 FERC ¶ 61,053 at PP 193-210; Millennium Pipeline Co., LLC, 161 FERC¶ 61,229, PP 151-165 (2017) (Millennium).

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119.  This information was initially included in certificate orders (in cases where NEPA documents had already been finalized), and subsequently in new NEPA documents. Typically, the end use of the gas to be transported by a project is not known.

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120.  E.g., Millennium, 161 FERC ¶ 61,229, at P 164 (2017) (“We note that this CO2e [carbon dioxide equivalents] estimate represents an upper bound for the amount of end-use combustion that could result from the gas transported by this project. This is because some of the gas may displace other fuels (i.e., fuel oil and coal) that could result in lower total CO2e emissions. It may also displace gas that otherwise would be transported via different systems, resulting in no change in CO2e emissions, or be used as a feedstock. This estimate also assumes the maximum capacity is transported 365 days per year, which is rarely the case because many projects are designed for peak use.

Consequently, it is unlikely that this total amount of GHG emissions would occur, and emissions are likely to be significantly lower than the above estimate.”).

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121.  162 FERC ¶ 61,238 (2018) (LaFleur and Glick Comm'rs, dissenting).

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122.  Id. at P 54 (footnote omitted).

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123.  Fla. Se. Connection, 162 FERC ¶ 61,233 at PP 37-38 (LaFleur and Glick, Comm'rs, dissenting).

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124.  Myersville Citizens for a Rural Cmty. Inc. v FERC, 783 F.3d 1301, 1311 (D.C. Cir. 2015) (citing Minisink, 762 F.3d at 111 n.10).

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125.  See, e.g., E. Shore Nat. Gas Co., 132 FERC¶ 61,204, at P 31 (2010); Millennium Pipeline Co., L.P., 100 FERC ¶ 61,277, at P 57 (2002).

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126.  An agency reasonably uses “the best information available when it [begins] its analysis and then check[s] the assumptions . . . as new information [becomes] available . . . .” Village of Bensenville v. FAA, 457 F.3d 52, 71 (DC Cir. 2006). See also 40 CFR 1502.22(b)(3) (if relevant information is unavailable, “the agency shall include . . . a summary of existing credible scientific evidence”) (emphasis added).

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127.  The Commission's Upland Erosion Control, Revegetation, and Maintenance Plan establishes baseline mitigation measures that project sponsors must implement, except when specifically exempted by Commission staff, to minimize erosion and enhance revegetation associated with their proposed projects.​industries/​gas/​enviro/​plan.pdf. The Commission's Wetland and Waterbody Construction and Mitigation Procedures establishes baseline mitigation measures that project sponsors must implement, except when specifically exempted by Commission staff, to minimize the extent and duration of project-related disturbance on wetlands and waterbodies.​industries/​gas/​enviro/​procedures.pdf.

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128.  E.g., Tenn. Gas Pipeline Co., L.L.C., 162 FERC ¶ 61,167, at PP 49-51 (2018) (order addressing timely intervention).

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[FR Doc. 2018-08658 Filed 4-24-18; 8:45 am]