Final Report: Review of Federal Energy Regulatory Commission Agency Actions Pursuant to Executive Order 13783, Promoting Energy Independence and Economic Growth, 50517-50523 [2017-23722]

Download as PDF Federal Register / Vol. 82, No. 210 / Wednesday, November 1, 2017 / Rules and Regulations DOCUMENT, AND DATE(S) DOCUMENT IS SIGNED]. Note 1 to paragraph (d)(2): When multiple consignees who form a network engaged in a production process (or other type of collaborative activity, such as joint development) will be receiving items under License Exception STA, a single prior consignee statement for multiple consignees may be used for any item eligible for export, reexport, or transfer (in-country) under License Exception STA, provided all of the applicable requirements of License Exception STA are met, including those specified in paragraph (d)(2). Note 2 to paragraph (d)(2): Country Group A:5 and A:6 government consignees are not required to sign or provide a prior consignee statement. Note 1 to paragraph (d)(3): While the exporter, reexporter, and transferor must furnish the applicable ECCN and obtain a consignee statement prior to export, reexport or transfer (in-country) made under License Exception STA in accordance with the requirements of paragraphs (d)(1) and (d)(2) of this section, intangible (i.e., electronic or in an otherwise intangible form) exports, reexports, and transfers (in-country) made under License Exception STA are not subject to the notification requirements of paragraph (d)(3) of this section. However, any export, reexport, or transfer (in-country) made under STA must stay within the scope of the original authorization. * * * * Dated: October 26, 2017. Richard E. Ashooh, Assistant Secretary for Export Administration. [FR Doc. 2017–23712 Filed 10–31–17; 8:45 am] BILLING CODE 3510–33–P DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Chapter I Final Report: Review of Federal Energy Regulatory Commission Agency Actions Pursuant to Executive Order 13783, Promoting Energy Independence and Economic Growth Federal Energy Regulatory Commission, DOE. ACTION: Availability of Final Report. sradovich on DSK3GMQ082PROD with RULES AGENCY: This Final Report on the Review of Federal Energy Regulatory Commission Agency Actions is provided pursuant to Executive Order 13783, Promoting Energy Independence and Economic Growth. DATES: November 1, 2017. SUMMARY: VerDate Sep<11>2014 FEDERAL ENERGY REGULATORY COMMISSION Final Report (3) * * * * Report available through http://www.ferc.gov. FOR FURTHER INFORMATION CONTACT: Nicholas Tackett, Office of Energy Projects, Branch Chief, Division of Hydropower Licensing, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, 202–502–6783 Karin L. Larson, Office of General Counsel, Energy Projects, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, 202–502–8236 SUPPLEMENTARY INFORMATION: ADDRESSES: 17:12 Oct 31, 2017 Jkt 244001 Review of Federal Energy Regulatory Commission Agency Actions Pursuant to Executive Order 13783, Promoting Energy Independence and Economic Growth I. Executive Summary On March 28, 2017, the President signed Executive Order 13783, titled Promoting Energy Independence and Economic Growth (Executive Order).1 Pursuant to section 2(c) of the Executive Order, on May 12, 2017, the Federal Energy Regulatory Commission (FERC, or the Commission) submitted to the Office of Management and Budget (OMB) its plan (Plan) for reviewing its existing regulations, orders, guidance documents, policies, and any other similar agency action (agency actions) that potentially burden the development or use of domestically produced energy resources. On July 26, 2017, pursuant to section 2(d) of the Executive Order, the head of the Commission submitted a draft final report detailing the review undertaken and the results of the review. Given the Commission’s status as an independent regulatory agency, this final report is being submitted on a voluntary basis.2 Of the agency actions reviewed, this final report identifies nine agency actions that potentially materially burden the development or use of domestic energy resources as contemplated by the Executive Order 1 Executive Order 13783, Promoting Energy Independence and Economic Growth, 82 Fed. Reg. 16093 (Mar. 28, 2017). 2 The Commission is a multi-member, independent regulatory agency that must follow applicable federal laws to change its rules, regulations and orders. Because the Commission must ultimately decide what action, if any, to take in response to the Executive Order, this report is a Commission staff analysis of the issues identified for review in the Executive Order and does not specifically recommend actions nor indicate the timing of any potential action. PO 00000 Frm 00027 Fmt 4700 Sfmt 4700 50517 and clarified by OMB’s May 8, 2017 Guidance Memo.3 In addition, these identified agency actions may be addressed in conjunction with the Commission’s ongoing efforts pursuant to Executive Order 13777. II. Background Section 2 of the Executive Order requires the heads of federal agencies to immediately ‘‘review all existing regulations, orders, guidance documents, policies, and any other similar agency actions (collectively, agency actions) that potentially burden the development or use of domestically produced energy resources, with particular attention to oil, natural gas, coal, and nuclear energy resources. Such review shall not include agency actions that are mandated by law, necessary for the public interest, and consistent with the policy set forth in section 1 of this order.’’ On May 8, 2017, OMB issued a Guidance Memo providing additional information regarding compliance with the Executive Order, in particular section 2. The Guidance Memo noted that the Executive Order does not apply to independent agencies as defined in 44 U.S.C. 3502(5), but encouraged independent regulatory agencies, especially those that directly regulate the development or use of domestically produced energy resources, to provide the plan and report that are called for in section 2 of the Executive Order. The Guidance Memo further encourages agencies to coordinate their compliance with Section 2 of Executive Order 13783 with their compliance with Executive Order 13777, which directs agencies to establish Regulatory Reform Task Forces to evaluate existing regulations generally and make recommendations to the agency head regarding their repeal, replacement and modification, consistent with applicable law. In the Plan, the Commission explained that it intended to review agency actions it has taken pursuant to legislative authority under: (1) the Natural Gas Act (NGA), 15 U.S.C. 717, et seq.; (2) the Federal Power Act (FPA), 16 U.S.C. 791a, et seq.; (3) the Interstate Commerce Act, 49 App. U.S.C. 1 et seq.; (4) the Public Utility Regulatory Policies Act of 1978 (PURPA), 16 U.S.C. 2601 et seq., and (5) other statutes for which the Commission’s actions on LNG, natural gas pipeline, and hydropower projects 3 Memo from Dominic J. Mancini, Acting Administrator, Office of Information and Regulatory Affairs to Regulatory Reform Officers and Regulatory Policy Officers at Executive Departments and Agencies regarding Guidance for Section 2 of Executive Order 13783, titled ‘‘Promoting Energy Independence and Economic Growth.’’ E:\FR\FM\01NOR1.SGM 01NOR1 50518 Federal Register / Vol. 82, No. 210 / Wednesday, November 1, 2017 / Rules and Regulations often require compliance, such as the National Environmental Policy Act, the Endangered Species Act, the Coastal Zone Management Act, and the Clean Water Act. III. Commission Review of Agency Actions Pursuant to Section 2 A. Scope of Review sradovich on DSK3GMQ082PROD with RULES Domestic Energy Sources: Section 2 of the Executive Order states that the review should place particular attention on oil, natural gas, coal, and nuclear energy resources. In addition, section 1 of the Executive Order and the Guidance Memo list renewable sources, including flowing water, as domestic energy sources. Therefore, this final report considers agency actions that potentially affect not only oil, natural gas, coal, and nuclear energy resources, but also hydropower and other renewable generation resources. Potentially Material Burdens: Section 2(b) of the Executive Order states that ‘‘burden’’ means ‘‘to unnecessarily obstruct, delay, curtail, or otherwise impose significant costs on the siting, permitting, production, utilization, transmission, or delivery of energy resources.’’ Based on the Executive Order’s definition of ‘‘burden,’’ as informed by the Guidance Memo which highlights agency actions that ‘‘materially’’ affect domestic energy production, this final report considers an agency action ‘‘material’’ if it could: (1) directly affect the development or use of domestic energy resources; or (2) have a primary indirect effect on the development or use of domestic energy resources.4 Given the Commission’s limited jurisdiction, none of the Commission’s agency actions would materially affect the design and/or location of drilling or mining of energy production resources. Agency Actions: This final report considers the following types of binding Commission agency actions in existence as of March 28, 2017 (i.e., the date of issuance of Executive Order 13783): codified regulations published by the Commission (i.e., 18 CFR); final rules; public policy statements and guidance documents; and case-specific orders and opinions that establish policies that are 4 The Guidance Memo indicates that agencies should review actions that both directly and indirectly affect domestic energy sources. This final report uses the term ‘‘primary indirect effect’’ to define the scope of indirect effects that will be considered for review. A primary indirect effect is an effect that is only one step removed from a direct effect. In other words, a primary indirect effect occurs when an agency action affects a factor that, in turn, affects a domestic energy source. VerDate Sep<11>2014 17:12 Oct 31, 2017 Jkt 244001 broadly applied and not otherwise codified by the Commission.5 B. Methodology This final report identifies and classifies the potentially relevant agency actions based on: (1) the type of action undertaken; (2) the energy source potentially affected by that action; and (3) whether the potential effects of the action are direct or indirect. This final report focuses on agency actions in four jurisdictional areas: (1) hydropower licensing; (2) LNG facility, and natural gas pipeline and storage facility siting; (3) centralized electric capacity market policies in PJM Interconnection, L.L.C. (PJM), ISO New England, Inc. (ISO–NE), and New York Independent System Operator, Inc. (NYISO); and (4) electric generator interconnection policies. Commission actions in these four jurisdictional areas have the greatest potential to materially burden domestic energy resources as contemplated under the Executive Order. In particular, the Commission’s hydropower licensing program has the potential to directly affect the design, location, and development of hydropower resources. In addition, the Commission’s jurisdiction over the siting of LNG terminals and natural gas pipelines may affect the delivery to market of natural gas, and have a primary indirect effect on the use of that domestically produced energy resource. Agency actions related to electric capacity market policies and generator interconnection policies may have a primary indirect effect on the development, retention, or retirement of domestic energy resources. As the Commission has recently recognized in its ongoing efforts concerning the interplay of wholesale electric markets and state policy, the centralized electric capacity markets in PJM, ISO–NE, and NYISO are intended to ensure long-term resource adequacy by sending accurate price signals for investment in electric capacity resources, when and where needed. By signaling the value of capacity, including the potential need for new generation resources, these markets serve a function in those regions that would otherwise typically be performed through integrated resource planning, often before a state public service commission. As a result, 5 This report does not consider the issue of grants to third parties to perform agency actions because the Commission does not issue such grants. Commission staff’s analysis included consideration of information collections, including those subject to the Paperwork Reduction Act, to the extent that such collections are within the scope of the agency actions reviewed under the Executive Order. PO 00000 Frm 00028 Fmt 4700 Sfmt 4700 Commission actions related to electric capacity market policies could have a primary indirect effect on the development and use of generation resources. Finally, agency actions involving generator interconnection policies could have a primary indirect effect on the development of domestic energy resources. For example, a wind or solar generator at utility scale typically must interconnect to the transmission grid in order to deliver the electricity produced by those domestic energy resources to the wholesale purchaser. If Commission policies or actions lead to a delay in interconnection or otherwise affect the generator’s ability to interconnect, then the project developer may not develop that energy resource, which would impact the development or use of domestic energy resources. This final report does not review agency actions involving oil and natural gas pipeline rates; electric energy and ancillary service rates and market policies; 6 electric transmission rates, including return on equity issues; demand response resources; mergers; enforcement; reliability; backstop transmission siting authority; and the Public Utilities Regulatory Policies Act. Commission action in these areas may indirectly impact the design, location, development, or use of domestic energy resources, but would not have a primary indirect effect, as discussed above. Pursuant to the Guidance Memo’s recommendation, this effort with respect to Executive Order 13783, to the extent appropriate, was coordinated with the Commission’s Regulatory Reform Task Force created pursuant to Executive Order 13777.7 This final report discusses those agency actions that rose to the level of a potential material burden as contemplated by the Executive Order and clarified by the Guidance Memo. For hydropower licensing and the LNG 6 Commission actions on energy and ancillary service market rules are less directly related to the development and use of domestic energy resources than Commission actions on centralized capacity market rules. While energy and ancillary service markets have an effect on the economic viability and day-to-day use of generation resources, the market rules established by the Commission are intended to ensure recovery of variable costs (e.g., fuel costs) for marginal units, rather than to be the primary source of fixed cost recovery for new generation resources. That is, in regions that do not have capacity markets, there is an additional mechanism to address fixed cost recovery typically administered by the relevant state regulatory commission, in the case of investor-owned public utilities, or the management of public power utilities. 7 As with Executive Order 13783, independent regulatory agencies like the Commission are not subject to Executive Order 13777, but are encouraged to comply. E:\FR\FM\01NOR1.SGM 01NOR1 Federal Register / Vol. 82, No. 210 / Wednesday, November 1, 2017 / Rules and Regulations and natural gas transportation facilities siting programs, the Executive Order review process revealed potentially burdensome agency actions related to regulations promulgated by the Commission. For electric capacity markets and generator interconnection, the Executive Order review process revealed potentially burdensome agency actions related to Commission rulemaking orders and case-specific orders, which typically did not result in the promulgation of regulations. This final report identifies steps the Commission may consider, to the extent permitted by law, to alleviate or eliminate the aspects of the agency actions that may burden the development or use of domestically produced energy resources. sradovich on DSK3GMQ082PROD with RULES C. Discussion 1. Hydropower Licensing Under Part I of the FPA, the Commission has the exclusive authority to issue licenses, small capacity exemptions (up to 10 megawatts (MW)), and conduit exemptions for non-federal hydropower projects. The Commission currently regulates over 1,600 licensed or exempted hydroelectric projects, representing about 56,000 MW of authorized installed capacity, which is more than half of all developed hydropower in the United States. The Commission is responsible for coordinating and managing the processing of hydropower project license and exemption applications, as well as applications for preliminary permits (under which permittees study proposed projects). This includes determining the effects of constructing, operating, and maintaining hydropower projects on environmental resources, and the need for the project’s power. Pursuant to the FPA, issues considered during the review of license applications include power production; fish, wildlife, recreation, and other environmental issues; flood control; irrigation; and other water uses. Various statutory requirements also give other agencies a significant role in project development, and several state and federal agencies have mandatory authorities that limit the Commission’s control of the cost and time required for licensing. Following the issuance of a license or exemption, the Commission oversees compliance with the terms and conditions of the license/exemption for the duration of the license. This includes processing the filing of plans, reports, and license amendments. Additionally, the Commission must determine if it has jurisdiction over VerDate Sep<11>2014 17:12 Oct 31, 2017 Jkt 244001 proposed or unlicensed operating projects; determine and assess headwater benefit charges; approve transfers of licensed projects; resolve complaints alleging noncompliance with license and exemption conditions; and act on applications for license surrenders. The Commission also is responsible for ensuring that the water-retaining features of hydropower projects are designed, constructed, operated, and maintained using current engineering standards and federal guidelines for dam safety. Commission staff inspects projects to investigate potential dam safety problems and, every five years, a Commission-approved independent consulting engineer must inspect and evaluate projects with dams higher than 32.8 feet or with a total storage capacity of more than 2,000 acre-feet. The Commission also requires licensees to prepare emergency action plans and conducts training sessions on how to develop and test these plans. The vast majority of agency actions relating to the Commission’s hydropower program do not present a material burden to hydropower resources. Specifically, most agency actions: (1) are necessary to administer the Commission’s hydropower program and process hydropower license applications in an orderly manner; and/ or (2) do not negatively affect the development of hydropower resources. As outlined below, however, this final report identifies three areas where potential material burdens may exist: licensing processes; exemption processes; and determinations on deficient applications. a. Licensing Processes i. ILP Default Regulation The Commission’s regulations include three hydropower licensing processes for applicants: the Integrated Licensing Process (ILP), the Traditional Licensing Process (TLP), and the Alternative Licensing Process (ALP). The Commission’s regulations assign the ILP as the default process for all license requests, and an applicant must specifically request and justify the use of either the TLP or ALP. Assigning the ILP as the default process could be materially burdensome due to: (1) the time and costs associated with obtaining the Commission’s approval to use the TLP or ALP; and (2) in the event the Commission denies the request to use the TLP/ALP, there may be additional time and costs associated with the ILP, due to the structured nature of the process. The level of burden caused by the ILP default regulation is largely PO 00000 Frm 00029 Fmt 4700 Sfmt 4700 50519 project-specific, and may be negligible/ non-existent for complex proceedings that could benefit from a more structured process such as the ILP. However, any material burden could be alleviated by making the ILP optional, and removing the requirement to seek Commission authorization to use the TLP and ALP (see 18 CFR 4.30, 5.1, 5.3, 5.8, 16.1). ii. Pre-Filing Application Requirement In the final stages of the Commission’s pre-filing process for hydropower projects, the Commission’s regulations require a potential applicant to submit a draft license application or preliminary licensing proposal before submitting a final license application (18 CFR 4.38(c)(4) and 5.16, respectively). The Commission’s regulations include minimum filing requirements for these documents (e.g., study results, analyses, and environmental measures), and a stakeholder review process. The requirement to file the draft application and preliminary licensing proposal may be materially burdensome in terms of the cost and delay associated with the preparation of the documents and the stakeholder review process. To eliminate material burdens, the Commission could consider revising its regulations to make this aspect of the pre-filing process optional for license applicants. iii. Pre-Filing Schedule The ILP contains comment and filing deadlines throughout the pre- and postfiling application process to ensure a structured approach to hydropower licensing. The ILP, however, may be materially burdensome in terms of the schedule established for the pre-filing process (3–3.5 years total). To alleviate this burden, the Commission could consider certain comment and filing deadline reductions to allow for an overall time savings of three months: (1) reduce the time that an applicant has to file a proposed study plan, and the Commission has to issue a second scoping document, from 45 days to 30 days after receiving comments (18 CFR 5.10 and 5.11); (2) reduce the time for entities to file comments on the proposed study plan, from 90 days to 60 days (18 CFR 5.12); (3) reduce the time an applicant has to file a revised study plan, from 30 days to 15 days (18 CFR 5.13); and (4) reduce the time for filing comments on an applicant’s preliminary licensing proposal, from 90 days to 60 days (18 CFR 5.16). E:\FR\FM\01NOR1.SGM 01NOR1 50520 Federal Register / Vol. 82, No. 210 / Wednesday, November 1, 2017 / Rules and Regulations sradovich on DSK3GMQ082PROD with RULES iv. License Term Policy Section 6 of the FPA provides that hydropower licenses shall be issued for a term not to exceed 50 years. There is no minimum license term for original licenses (16 U.S.C. 799). Section 15(e) of the FPA provides that any new license for an existing project (i.e., relicense) shall be for a term that the Commission determines to be in the public interest, but not less than 30 years or more than 50 years (16 U.S.C. 808(e)). Current Commission policy is to set a 30-year license term where there is little or no authorized redevelopment, new construction, or environmental mitigation and enhancement; a 40-year license term for a license involving a moderate amount of these activities; and a 50-year license term where there is an extensive amount of such activity.8 On November 17, 2016, the Commission issued a notice of inquiry in FERC Docket No. RM17–4–000 inviting comments on what changes, if any, should be made to the license term policy. The license terms provide operational certainty and govern the frequency of the license renewal process, which influences the overall cost of development. In turn, shorter license terms could burden development by increasing the cost of development. The Commission currently is considering comments on the license term policy, which it could use to further evaluate the need for any future changes to the license term policy. procedure for small hydroelectric power projects with an installed capacity of 5 MW or less (see 46 FR 55,944 at 55,947 (1981); 16 U.S.C. § 2705). The Hydropower Regulatory Efficiency Act of 2013 has since amended PURPA by increasing the size of a small hydroelectric power project from 5 to 10 MW. Therefore, the 5 MW threshold in 18 CFR 4.40, 4.50, and 4.60 is materially burdensome to projects between 5 and 10 MW, in terms of the cost and time associated with the more onerous filing requirements of Subparts E and F. To eliminate the material burden, the Commission could consider revising its regulations to increase the threshold from 5 MW. v. Minimum Filing Requirements The Commission’s regulations contain minimum filing requirements depending on the size of a project, and whether construction or modification of a dam is needed for project operation. Part 4 of the Commission’s regulations includes three subparts corresponding to these factors: (1) Subpart E— Application for License for Major Unconstructed Project and Major Modified Project (18 CFR 4.40); (2) Subpart F—Application for License for Major Project—Existing Dam (18 CFR 4.50); and (3) Subpart G—Application for License for Minor Water Power Projects and Major Water Power Projects 5 MW or Less (18 CFR 4.60). Subparts E and F apply to projects greater than 5 MW, and include more onerous filing requirements than Subpart G, which applies to projects less than or equal to 5 MW. The 5 MW threshold is based on section 405 of PURPA, which mandated a simplified and expeditious licensing ii. Small Hydropower Conversion Restrictions In the event that the Commission rejects an exemption application, the Commission’s regulations do not explicitly provide an applicant with the ability to convert a small hydropower exemption application to a license application (18 CFR 4.105). The Commission’s Handbook for Hydroelectric Project Licensing and 5 MW Exemptions from Licensing, issued April 2004, explicitly states at section 6.3.2: If the exemption application is dismissed, the process is terminated. There is no opportunity to convert the exemption application to an application for license.9 In comparison, the Commission has established a process for converting a small conduit exemption application to a license application (18 CFR 4.93). The process for small conduits allows the applicant to submit additional information necessary to conform the 8 See City of Danville, Virginia, 58 FERC ¶ 61,318 (1992); and Consumers Power Co., 68 FERC ¶ 61,077, (1994). VerDate Sep<11>2014 17:12 Oct 31, 2017 Jkt 244001 b. Exemption Processes i. Increased Capacity Requirement To qualify for a license exemption under section 405 of PURPA, an applicant must propose to install/ increase the total capacity of a project to not more than 10 MW (18 CFR 4.30(b)(31), 4.31(c), and 4.103(a)). The regulatory requirement to add new capacity at the project is not specifically required by section 405 of PURPA, and it materially burdens existing licensees that would otherwise be eligible to seek an exemption at the end of the existing license term. To eliminate this burden, the Commission could consider revising the regulations to remove the requirement to install or increase the capacity of the facility to qualify for an exemption. 9 See www.ferc.gov/industries/hydropower/geninfo/handbooks/licensing_handbook.pdf. PO 00000 Frm 00030 Fmt 4700 Sfmt 4700 conduit exemption application to the relevant regulations for a license application, and then be accepted for filing as of the date the exemption application was accepted for filing. The inability of an applicant of a small hydropower exemption to convert its application to a license application is materially burdensome because the applicant must initiate an entirely new license process after its exemption is rejected, thereby causing delay to the development of the resource. To eliminate this burden, the Commission could consider amending its regulations to explicitly provide the small hydropower exemption applicant with the ability to convert its exemption application to a license application if the exemption application is rejected. c. Prohibition on Refiling Subsequent License Applications Pursuant to the authority provided in section 10(i) of the FPA (16 U.S.C. 803), the Commission routinely waives certain sections of Part I of the FPA when it issues a minor license. As relevant, the Commission routinely waives section 15 of the FPA, which governs the Commission’s procedures for issuing a new license to an existing licensee (i.e., a relicense) (16 U.S.C. and 808). Yet, the Commission’s regulations require the licensee to file an application for relicense at least 24 months before the expiration of the existing license (18 CFR 16.20(c)). Moreover, if the Commission rejects the application, it cannot be refiled (18 CFR 16.9(b)(4)). Rejecting a relicense application, and not providing the applicant with the opportunity to refile, is materially burdensome to the use of hydropower resources. To eliminate this burden, the Commission could consider revising its regulations at 18 CFR 16.20 to provide the applicant with the option of resubmitting the application if the deficiencies are corrected. 2. LNG Facility and Natural Gas Pipeline and Storage Facility Siting Under section 7 of the NGA, 15 U.S.C. 717f, the Commission authorizes the construction, operation, or abandonment of interstate natural gas pipeline and storage projects, as well as certain types of LNG facilities (e.g., LNG plants engaged in the storage of interstate natural gas volumes). Similarly, under section 3 of the NGA, 15 U.S.C. 717b(e)(1), the Commission authorizes the siting, construction and operation of LNG terminals through which the commodity passes for export or import. As part of these responsibilities, the Commission conducts both a non-environmental and E:\FR\FM\01NOR1.SGM 01NOR1 sradovich on DSK3GMQ082PROD with RULES Federal Register / Vol. 82, No. 210 / Wednesday, November 1, 2017 / Rules and Regulations an environmental review of the proposed facilities. The nonenvironmental review focuses on the engineering design, rate, and tariff considerations. The Commission carries out the environmental review with the cooperation of numerous federal, state, and local agencies, and with the input of other interested parties. Under the NGA, the Commission also is the lead federal agency for coordinating all applicable federal authorizations (e.g., required permits under the Clean Water Act, Clean Air Act, and Coastal Zone Management Act, among others) and preparing environmental analyses required under the National Environmental Policy Act (NEPA) for all interstate natural gas infrastructure and LNG import/export proposals. There are several distinct phases to the review process for interstate natural gas and LNG facilities under the Commission’s jurisdiction: pre-filing review (if applicable); application review; and post-authorization compliance. During the pre-filing review, Commission staff begins work on the environmental review and engages with stakeholders with the goal of resolving issues before the filing of an application. Throughout the pre-filing process, Commission staff meets with stakeholders, visits the project site, and confers with federal, state, and local agencies. Once a project sponsor files an application with the Commission under NGA section 3 for LNG import/export terminals or under NGA section 7 for interstate pipeline and storage facilities, Commission staff analyzes both environmental and non-environmental aspects for a proposed project, including for LNG terminals safety and engineering. An Environmental Assessment or Environmental Impact Statement typically is issued for public comment, and ultimately, the Commission will issue an order on an application after considering both environmental and non-environmental issues. During the post-authorization compliance period, Commission staff monitors the project sponsor’s compliance with the conditions directed by the Commission. Ultimately, Commission approval is required before the facility can begin operation and provide service. Pursuant to Executive Order 13783, the review encompassed the Commission’s regulations, guidance documents, and policies related to the certification of interstate natural gas transportation facilities, authorization of LNG import and export facilities, authorization of certain transportation VerDate Sep<11>2014 17:12 Oct 31, 2017 Jkt 244001 by interstate and intrastate pipelines, and environmental review under NEPA. The majority of agency actions relating to the siting and construction of interstate natural gas transportation and LNG facilities do not materially burden the transportation or delivery of domestically produced natural gas. Specifically, most of the Commission’s actions: (1) Are necessary for the Commission to review and process NGA section 3 and 7 project applications; and/or (2) do not negatively affect the siting or construction of natural gas pipeline and storage facilities or LNG import/export facilities in a manner that has a direct or primary indirect effect on the development or use of domestic energy production. However, the Commission’s regulations require a prospective applicant for authorization under section 3 of the NGA to site and construct LNG terminals and related jurisdictional natural gas facilities to engage in the Commission’s pre-filing process. (18 CFR 157.21(a)). The Commission’s pre-filing regulations require applicants to use the pre-filing process for a minimum of 180 days before the filing of an application for any project that is required to engage in pre-filing. (18 CFR 157.21(a)(2)(1) and 153.6(c)). While, in general, the prefiling process is designed to expedite the processing of applications, the mandatory imposition of the pre-filing process on LNG terminals and related pipeline projects for at least 180 days before an application can be filed may be materially burdensome for some projects in terms of the potential delay and costs associated with the process. Although the 180 day pre-filing process is required by statute for LNG terminals, 15 U.S.C. 717b–1(a), the statute did not mandate that the Commission also require ‘‘related jurisdictional natural gas facilities’’ to engage in pre-filing. However, related jurisdictional natural gas pipeline facilities need to be evaluated concurrent with a proposed LNG terminal to avoid segmentation under the National Environmental Policy Act. Further, the pre-filing process allows stakeholders to become involved in the overall Project at an early stage, and applicants can benefit from stakeholder’s early identification and resolution of issues that may overlap with the LNG terminal. Without using the pre-filing process for related jurisdictional natural gas facilities, delays could occur during the application review, when issues are first identified and need resolution. Thus, although this regulation may result in delays or additional costs to the applicant early on in a project’s PO 00000 Frm 00031 Fmt 4700 Sfmt 4700 50521 development, its overall result is a more timely application review by considering all issues regarding a project concurrently. As such, there is no need for the Commission to consider any revision to this regulation. 3. Centralized Electric Capacity Market Policies Three of the Regional Transmission Operator/Independent System Operator (RTO/ISO) markets in the eastern U.S. have adopted centralized capacity markets to help address resource adequacy concerns.10 In particular, PJM, ISO–NE, and NYISO have implemented centralized capacity markets that were designed, in part, to ensure long-term resource adequacy by sending accurate price signals for investment in capacity resources, when and where needed.11 As a result, agency actions related to capacity market policies could have a primary indirect effect on the development and use of generation resources, including renewables, natural gas, and nuclear facilities.12 The centralized capacity markets require load-serving entities to secure, either through self-supply 13 or participation in the capacity auction, sufficient resources to meet their capacity obligation at a future time. All three centralized capacity markets allow participation by any resource that is technically qualified to provide the capacity product being procured and each market generally models locational constraints. Each conducts a capacity auction where eligible offers to sell capacity are compared to the demand for capacity resources, which is established through an administratively10 The Commission has defined resource adequacy as ‘‘the availability of an adequate supply of generation or demand responsive resources to support safe and reliable operation of the grid.’’ Cal. Indep. Sys. Operator Corp., 122 FERC ¶ 61,017, at P 3 (2008). 11 ‘‘Capacity is not actual electricity. It is a commitment to produce electricity or forgo consumption of electricity when required.’’ Advanced Energy Mgmt. All. v. FERC, No. 16–1234, 2017 WL 2636455, at *1 (D.C. Cir. Jun. 20, 2017); see Conn. Dep’t of Pub. Util. Control v. FERC, 569 F.3d 477, 482 (D.C. Cir. 2009) (explaining that capacity ‘‘amounts to a kind of call option that electricity transmitters purchase from parties— generally, generators—who can either produce more or consumer less when required’’). 12 It is important to note that the Commission has not required RTOs/ISOs to implement centralized capacity markets; rather, the determination to include such markets has been a voluntary decision by the stakeholders in each particular RTO/ISO. However, once an RTO/ISO decides to implement such a capacity market, the Commission must ensure that the tariff provisions establishing the capacity market rules are just and reasonable and not unduly discriminatory or preferential. 13 While the specific rules vary by RTO/ISO, loadserving entities can own or construct resources or contract bilaterally for capacity from resources owned by other entities. E:\FR\FM\01NOR1.SGM 01NOR1 sradovich on DSK3GMQ082PROD with RULES 50522 Federal Register / Vol. 82, No. 210 / Wednesday, November 1, 2017 / Rules and Regulations determined demand curve. Generally speaking, the market clears based on the intersection between the supply and demand curves. All cleared resources receive the market clearing price for capacity regardless of resource type. The Commission has issued multiple agency actions (i.e., Commission orders addressing the capacity market designs of the relevant organized markets) that govern the rules and design of the centralized capacity markets. Agency actions related to electric capacity markets were reviewed to determine if they impose a material burden on the development and use of domestic energy resources. In general, agency actions regarding centralized electricity capacity market design do not impose a material burden on the development and use of domestic energy resources because they generally seek to ensure adequate resources, and thereby facilitate the development of domestic energy resources, rather than create material burdens to the development and use of these resources. However, this final report discusses Commission actions regarding one aspect of centralized electricity capacity markets, buyer-side market power mitigation rules, due to the potentially material burdens Commission actions may have on the development of domestic energy resources. All three eastern RTOs/ISOs use some form of a minimum offer price rule (MOPR) as approved by Commission order. MOPRs as currently designed establish offer floors for certain new resources to protect against subsidized new entry that has the potential to artificially suppress capacity market prices. New resources that trigger this rule are required to submit offers into the capacity market auction at or above the floor. If the resource’s mitigated offer price is too high to clear in the market, then the resource would not receive a capacity obligation and the associated market payments. Depending on the terms of any out-of-market contracts, the resource also may not be eligible to receive out-of-market payments if it does not clear in the capacity market auction. Without such compensation, the developer may conclude it is not economic to develop the resource. In this way, Commission actions on the MOPR arguably impose a burden on certain new resources. However, Commission actions on the MOPR do not rise to the level of a material burden, as the term is defined in the Executive Order and Guidance Memo. While application of the MOPR to a generator’s bid may conceivably result in the developer deciding not to develop its generation resource, an VerDate Sep<11>2014 17:12 Oct 31, 2017 Jkt 244001 individual generation developer’s decision not to develop as a result of being subject to a MOPR would not in and of itself materially affect the use or development of oil, natural gas, coal, nuclear energy, or other domestic energy resources in the U.S. Therefore, Commission actions on MOPRs do not negatively affect the development and use of domestic energy resources by the electricity sector, despite the potential burden on those individual resources that are mitigated. Furthermore, from the perspective of other resources in the market, the MOPR can help preserve the integrity of the market price signals and revenue streams, thereby facilitating development and retention of other resources that might use domestic energy resources. 4. Generator Interconnection Policies Electric generators use domestic energy resources to produce electricity. Electric generators at utility scale must interconnect to the transmission system to deliver the electricity they produce to customers and receive benefits from the wholesale electric markets. The interconnection process is designed to ensure a new resource can safely and reliably deliver its output to end-users and to assign the costs to the party causing the costs of any system upgrades required to maintain safety and reliability. If a generator is not able to interconnect to the transmission system, or if it is too difficult or expensive to do so, the developer may decide not to pursue investment in the electric generation resource. Therefore, the ability of an electric generator to interconnect to a transmission system could affect the development or use of domestic energy resources. The Commission has issued multiple agency actions that govern and facilitate the interconnection of electric generators to public utility transmission systems. They include: Order No. 2003: In Order No. 2003, the Commission created standard large generator interconnection procedures and adopted a standard large generator interconnection agreement for the interconnection of electric generators larger than 20 MW, regardless of resource type.14 Order No. 2006: In Order No. 2006, the Commission created standard small 14 Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, FERC Stats. & Regs. ¶ 31,146 (2003), order on reh’g, Order No. 2003–A, FERC Stats. & Regs. ¶ 31,160, order on reh’g, Order No. 2003–B, FERC Stats. & Regs. ¶ 31,171 (2004), order on reh’g, Order No. 2003–C, FERC Stats. & Regs. ¶ 31,190 (2005), aff’d sub nom. Nat’l Ass’n of Regulatory Util. Comm’rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552 U.S. 1230 (2008). PO 00000 Frm 00032 Fmt 4700 Sfmt 4700 generator interconnection procedures and a standard small generator interconnection agreement for the interconnection of electric generators no larger than 20 MW.15 Order No. 661: In Order No. 661, the Commission required public utilities to add standard procedures and technical requirements for the interconnection of large wind generation resources to their standard large generator interconnection procedures and large generator interconnection agreements in their open access transmission tariffs.16 Order No. 827: In Order No. 827, the Commission revised the interconnection agreements for both large and small non-synchronous generators to eliminate exemptions for wind generators from providing reactive power.17 Order No. 828: In Order No. 828, the Commission modified the small generator interconnection agreement as set forth in Order Nos. 2006 and 792 to require newly interconnecting small generating facilities to ride through abnormal frequency and voltage events and not disconnect during such events.18 Order No. 792: In Order No. 792, the Commission revised the standard small generator interconnection procedures and standard small generator interconnection agreement for the interconnection of electric generators no larger than 20 MW.19 None of these orders materially burden the development or use of domestic energy resources. The Commission’s generator interconnection orders establish an orderly, uniform process for all types of generators to interconnect to the grid safely and reliably, facilitating their development by providing them with the means to deliver the electricity they produce to the purchaser. As such, these requirements will not unnecessarily obstruct, delay, curtail or otherwise 15 Standardization of Small Generator Interconnection Agreements and Procedures, Order No. 2006, FERC Stats. & Regs. ¶ 31,180, order on reh’g, Order No. 2006–A, FERC Stats. & Regs. ¶ 31,196 (2005), order granting clarification, Order No. 2006–B, FERC Stats. & Regs. ¶ 31,221 (2006). 16 Interconnection for Wind Energy, Order No. 661, FERC Stats. & Regs. ¶ 31,186, order on reh’g, Order No. 661–A, FERC Stats. & Regs. ¶ 31,198 (2005). 17 Reactive Power Requirements for NonSynchronous Generators, Order No. 827, FERC Stats. & Regs. ¶ 31,385, order on reh’g, 157 FERC ¶ 61,003 (2016). 18 Requirements for Frequency and Voltage Ride Through Capability of Small Generating Facilities, Order No. 828, 156 FERC ¶ 61,062 (2016). 19 Small Generator Interconnection Agreements and Procedures, Order No. 792, 145 FERC ¶ 61,159 (2013), clarifying, Order No. 792–A, 146 FERC ¶ 61,214 (2014). E:\FR\FM\01NOR1.SGM 01NOR1 Federal Register / Vol. 82, No. 210 / Wednesday, November 1, 2017 / Rules and Regulations impose significant costs on the siting, permitting, production, utilization, transmission, or delivery of energy resources and therefore they will not materially burden the production or use of domestic energy resources. Dated: October 25, 2017. Kimberly D. Bose, Secretary. [FR Doc. 2017–23722 Filed 10–31–17; 8:45 am] BILLING CODE 6717–01–P DEPARTMENT OF HOMELAND SECURITY U.S. Customs and Border Protection DEPARTMENT OF THE TREASURY 19 CFR Parts 24 and 111 [USCBP–2017–0025; CBP Dec. 17–16] RIN 1515–AE25 Procedures To Adjust Customs COBRA User Fees To Reflect Inflation U.S. Customs and Border Protection, Department of Homeland Security; Department of the Treasury. ACTION: Final rule. AGENCY: This document adopts as a final rule, with changes, the amendments proposed to the U.S. Customs and Border Protection (CBP) regulations to reflect that customs user fees and limitations established by the Consolidated Omnibus Budget Reconciliation Act (COBRA) will be adjusted for inflation in accordance with the Fixing America’s Surface Transportation Act (FAST Act). DATES: Effective November 1, 2017. FOR FURTHER INFORMATION CONTACT: Bruce Ingalls, Director—Revenue Division, 317–298–1107, bruce.ingalls@ cbp.dhs.gov; or Tina Ghiladi, Director— Fee Strategy, Communications, and Integration, 202–344–3722, tina.ghiladi@cbp.dhs.gov. SUPPLEMENTARY INFORMATION: SUMMARY: sradovich on DSK3GMQ082PROD with RULES Background On December 4, 2015, the Fixing America’s Surface Transportation Act (FAST Act, Pub. L. 114–94) was signed into law. Section 32201 of the FAST Act amends section 13031 of the Consolidated Omnibus Budget Reconciliation Act (COBRA) of 1985 (19 U.S.C. 58c) by requiring certain customs COBRA user fees and corresponding limitations to be adjusted by the Secretary of the Treasury (Secretary) to reflect certain increases in inflation. The specific fees and corresponding VerDate Sep<11>2014 17:12 Oct 31, 2017 Jkt 244001 limitations to be adjusted for inflation are set forth in Appendix A and Appendix B of part 24 in this final rule and include the commercial vessel arrival fees, commercial truck arrival fees, railroad car arrival fees, private vessel arrival fees, private aircraft arrival fees, commercial aircraft and vessel passenger arrival fees, dutiable mail fees, customs broker permit user fees, barges and other bulk carriers arrival fees, and merchandise processing fees as well as the corresponding limitations. (19 U.S.C. 58c(a) and (b)). Further, the FAST Act includes a particular measure of inflation for these purposes and special rules when considering adjustments. According to the FAST Act, the customs COBRA user fees and limitations were to be adjusted on April 1, 2016, and at the beginning of each fiscal year to reflect the percent increase (if any) in the Consumer Price Index (CPI) for the preceding 12-month period compared to the CPI for fiscal year 2014. The statute permits the Secretary to ignore any CPI increase of less than one (1) percent from the time of the previous adjustment. As a result, if the increase in the CPI since the previous adjustment is less than one (1) percent, the Secretary has discretion to determine whether the fees should be adjusted. On June 15, 2016, CBP published a notice in the Customs Bulletin announcing the April 2016 determination that no adjustment to the customs COBRA user fees and limitations was necessary based on the FAST Act provision as the increase of the CPI was less than one (1) percent. (Customs Bulletin, Vol. 50, No. 24, p. 13). CBP published a second notice in the Customs Bulletin on December 7, 2016, announcing that, based on a less than one (1) percent increase in inflation, no adjustment was necessary for fiscal year 2017. (Customs Bulletin Vol. 50, No. 49, p. 4). Proposed Rule On July 17, 2017, CBP published a notice of proposed rulemaking (NPRM) in the Federal Register (82 FR 32661) proposing to amend title 19 of the Code of Federal Regulations (19 CFR) to set forth the methodology for determining the required adjustments. The FAST Act specifies that the customs COBRA user fees and corresponding limitations should be adjusted to reflect the percentage of the increase (if any) in the average of the CPI for the preceding 12month period compared to the CPI for fiscal year 2014. CBP determined that the 12-month period for comparison will be June through May. This timeframe was proposed to allow for PO 00000 Frm 00033 Fmt 4700 Sfmt 4700 50523 sufficient notice to the public of any adjustments prior to any changes becoming effective for each fiscal year. The FAST Act further requires the Secretary to round the amount of any increase in the CPI to the nearest dollar. The rounding requirement applies to the difference in the CPI from the comparison year to the current year when determining whether an adjustment is necessary. As written, the rounding requirement does not apply to the fee amount resulting from any adjustment. As noted above, if the difference in the CPI since the last adjustment is less than one (1) percent, the Secretary may elect not to adjust the fees and limitations. The statute requires CBP to use the Consumer Price Index—All Urban Consumers, U.S. All items, 1982–84 (CPI–U) which can be found on the U.S. Department of Labor, Bureau of Labor Statistics Web site: www.bls.gov/cpi/. The proposed rule provided that CBP’s Office of Finance will determine annually whether an adjustment to the fees and limitations is necessary and a notice specifying the amount of the fees and limitations will be published in the Federal Register for each fiscal year at least 30 days prior to the effective date of the new fees and limitations. Technical Corrections In addition, CBP proposed technical updates to paragraph (g) of 19 CFR 24.22 to reflect the elimination of the user fee exemption for passengers arriving from Canada, Mexico or one of the adjacent islands pursuant to the United States— Colombia Trade Promotion Agreement Implementation Act. (Colombia TPA, Pub. L. 112–42, October 21, 2011). Section 601 of the Colombia TPA amended 19 U.S.C. 58c(b)(1)(A)(i) to limit the fee exemption exclusively to passengers whose journey originated in a territory or possession of the United States, or originated in the United States and was limited to the territories and possessions of the United States. (19 U.S.C. 58c(b)(1)(A)(i)). Since the law became effective on November 5, 2011,CBP has been collecting only the non-exempt user fees. In accordance with the statute, CBP is removing the exemption for passengers arriving from Canada, Mexico, or one of the adjacent islands, from the regulations found in paragraphs (g)(1)(i), (g)(1)(i)(A), (g)(1)(i)(B), (g)(1)(ii), (g)(1)(iii), (g)(2)(i), the chart in paragraph (g)(2)(iv), and the collection procedures in paragraphs (g)(4)(ii)(A), (g)(4)(ii)(B), (g)(4)(ii)(C), (g)(4)(iii)(A), (g)(4)(iii)(B), and (g)(4)(iii)(C). (19 CFR 24.22(g)). CBP is also removing the definition of ‘‘adjacent islands’’ from paragraph E:\FR\FM\01NOR1.SGM 01NOR1

Agencies

[Federal Register Volume 82, Number 210 (Wednesday, November 1, 2017)]
[Rules and Regulations]
[Pages 50517-50523]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2017-23722]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Chapter I


Final Report: Review of Federal Energy Regulatory Commission 
Agency Actions Pursuant to Executive Order 13783, Promoting Energy 
Independence and Economic Growth

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Availability of Final Report.

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SUMMARY: This Final Report on the Review of Federal Energy Regulatory 
Commission Agency Actions is provided pursuant to Executive Order 
13783, Promoting Energy Independence and Economic Growth.

DATES: November 1, 2017.

ADDRESSES: Report available through http://www.ferc.gov.

FOR FURTHER INFORMATION CONTACT: 

Nicholas Tackett, Office of Energy Projects, Branch Chief, Division of 
Hydropower Licensing, Federal Energy Regulatory Commission, 888 First 
Street NE., Washington, DC 20426, 202-502-6783
Karin L. Larson, Office of General Counsel, Energy Projects, Federal 
Energy Regulatory Commission, 888 First Street NE., Washington, DC 
20426, 202-502-8236

SUPPLEMENTARY INFORMATION: 

FEDERAL ENERGY REGULATORY COMMISSION

Final Report

Review of Federal Energy Regulatory Commission Agency Actions Pursuant 
to Executive Order 13783, Promoting Energy Independence and Economic 
Growth

I. Executive Summary

    On March 28, 2017, the President signed Executive Order 13783, 
titled Promoting Energy Independence and Economic Growth (Executive 
Order).\1\ Pursuant to section 2(c) of the Executive Order, on May 12, 
2017, the Federal Energy Regulatory Commission (FERC, or the 
Commission) submitted to the Office of Management and Budget (OMB) its 
plan (Plan) for reviewing its existing regulations, orders, guidance 
documents, policies, and any other similar agency action (agency 
actions) that potentially burden the development or use of domestically 
produced energy resources. On July 26, 2017, pursuant to section 2(d) 
of the Executive Order, the head of the Commission submitted a draft 
final report detailing the review undertaken and the results of the 
review. Given the Commission's status as an independent regulatory 
agency, this final report is being submitted on a voluntary basis.\2\
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    \1\ Executive Order 13783, Promoting Energy Independence and 
Economic Growth, 82 Fed. Reg. 16093 (Mar. 28, 2017).
    \2\ The Commission is a multi-member, independent regulatory 
agency that must follow applicable federal laws to change its rules, 
regulations and orders. Because the Commission must ultimately 
decide what action, if any, to take in response to the Executive 
Order, this report is a Commission staff analysis of the issues 
identified for review in the Executive Order and does not 
specifically recommend actions nor indicate the timing of any 
potential action.
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    Of the agency actions reviewed, this final report identifies nine 
agency actions that potentially materially burden the development or 
use of domestic energy resources as contemplated by the Executive Order 
and clarified by OMB's May 8, 2017 Guidance Memo.\3\ In addition, these 
identified agency actions may be addressed in conjunction with the 
Commission's ongoing efforts pursuant to Executive Order 13777.
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    \3\ Memo from Dominic J. Mancini, Acting Administrator, Office 
of Information and Regulatory Affairs to Regulatory Reform Officers 
and Regulatory Policy Officers at Executive Departments and Agencies 
regarding Guidance for Section 2 of Executive Order 13783, titled 
``Promoting Energy Independence and Economic Growth.''
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II. Background

    Section 2 of the Executive Order requires the heads of federal 
agencies to immediately ``review all existing regulations, orders, 
guidance documents, policies, and any other similar agency actions 
(collectively, agency actions) that potentially burden the development 
or use of domestically produced energy resources, with particular 
attention to oil, natural gas, coal, and nuclear energy resources. Such 
review shall not include agency actions that are mandated by law, 
necessary for the public interest, and consistent with the policy set 
forth in section 1 of this order.''
    On May 8, 2017, OMB issued a Guidance Memo providing additional 
information regarding compliance with the Executive Order, in 
particular section 2. The Guidance Memo noted that the Executive Order 
does not apply to independent agencies as defined in 44 U.S.C. 3502(5), 
but encouraged independent regulatory agencies, especially those that 
directly regulate the development or use of domestically produced 
energy resources, to provide the plan and report that are called for in 
section 2 of the Executive Order. The Guidance Memo further encourages 
agencies to coordinate their compliance with Section 2 of Executive 
Order 13783 with their compliance with Executive Order 13777, which 
directs agencies to establish Regulatory Reform Task Forces to evaluate 
existing regulations generally and make recommendations to the agency 
head regarding their repeal, replacement and modification, consistent 
with applicable law.
    In the Plan, the Commission explained that it intended to review 
agency actions it has taken pursuant to legislative authority under: 
(1) the Natural Gas Act (NGA), 15 U.S.C. 717, et seq.; (2) the Federal 
Power Act (FPA), 16 U.S.C. 791a, et seq.; (3) the Interstate Commerce 
Act, 49 App. U.S.C. 1 et seq.; (4) the Public Utility Regulatory 
Policies Act of 1978 (PURPA), 16 U.S.C. 2601 et seq., and (5) other 
statutes for which the Commission's actions on LNG, natural gas 
pipeline, and hydropower projects

[[Page 50518]]

often require compliance, such as the National Environmental Policy 
Act, the Endangered Species Act, the Coastal Zone Management Act, and 
the Clean Water Act.

III. Commission Review of Agency Actions Pursuant to Section 2

A. Scope of Review

    Domestic Energy Sources: Section 2 of the Executive Order states 
that the review should place particular attention on oil, natural gas, 
coal, and nuclear energy resources. In addition, section 1 of the 
Executive Order and the Guidance Memo list renewable sources, including 
flowing water, as domestic energy sources. Therefore, this final report 
considers agency actions that potentially affect not only oil, natural 
gas, coal, and nuclear energy resources, but also hydropower and other 
renewable generation resources.
    Potentially Material Burdens: Section 2(b) of the Executive Order 
states that ``burden'' means ``to unnecessarily obstruct, delay, 
curtail, or otherwise impose significant costs on the siting, 
permitting, production, utilization, transmission, or delivery of 
energy resources.'' Based on the Executive Order's definition of 
``burden,'' as informed by the Guidance Memo which highlights agency 
actions that ``materially'' affect domestic energy production, this 
final report considers an agency action ``material'' if it could: (1) 
directly affect the development or use of domestic energy resources; or 
(2) have a primary indirect effect on the development or use of 
domestic energy resources.\4\ Given the Commission's limited 
jurisdiction, none of the Commission's agency actions would materially 
affect the design and/or location of drilling or mining of energy 
production resources.
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    \4\ The Guidance Memo indicates that agencies should review 
actions that both directly and indirectly affect domestic energy 
sources. This final report uses the term ``primary indirect effect'' 
to define the scope of indirect effects that will be considered for 
review. A primary indirect effect is an effect that is only one step 
removed from a direct effect. In other words, a primary indirect 
effect occurs when an agency action affects a factor that, in turn, 
affects a domestic energy source.
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    Agency Actions: This final report considers the following types of 
binding Commission agency actions in existence as of March 28, 2017 
(i.e., the date of issuance of Executive Order 13783): codified 
regulations published by the Commission (i.e., 18 CFR); final rules; 
public policy statements and guidance documents; and case-specific 
orders and opinions that establish policies that are broadly applied 
and not otherwise codified by the Commission.\5\
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    \5\ This report does not consider the issue of grants to third 
parties to perform agency actions because the Commission does not 
issue such grants. Commission staff's analysis included 
consideration of information collections, including those subject to 
the Paperwork Reduction Act, to the extent that such collections are 
within the scope of the agency actions reviewed under the Executive 
Order.
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B. Methodology

    This final report identifies and classifies the potentially 
relevant agency actions based on: (1) the type of action undertaken; 
(2) the energy source potentially affected by that action; and (3) 
whether the potential effects of the action are direct or indirect.
    This final report focuses on agency actions in four jurisdictional 
areas: (1) hydropower licensing; (2) LNG facility, and natural gas 
pipeline and storage facility siting; (3) centralized electric capacity 
market policies in PJM Interconnection, L.L.C. (PJM), ISO New England, 
Inc. (ISO-NE), and New York Independent System Operator, Inc. (NYISO); 
and (4) electric generator interconnection policies.
    Commission actions in these four jurisdictional areas have the 
greatest potential to materially burden domestic energy resources as 
contemplated under the Executive Order. In particular, the Commission's 
hydropower licensing program has the potential to directly affect the 
design, location, and development of hydropower resources. In addition, 
the Commission's jurisdiction over the siting of LNG terminals and 
natural gas pipelines may affect the delivery to market of natural gas, 
and have a primary indirect effect on the use of that domestically 
produced energy resource.
    Agency actions related to electric capacity market policies and 
generator interconnection policies may have a primary indirect effect 
on the development, retention, or retirement of domestic energy 
resources. As the Commission has recently recognized in its ongoing 
efforts concerning the interplay of wholesale electric markets and 
state policy, the centralized electric capacity markets in PJM, ISO-NE, 
and NYISO are intended to ensure long-term resource adequacy by sending 
accurate price signals for investment in electric capacity resources, 
when and where needed. By signaling the value of capacity, including 
the potential need for new generation resources, these markets serve a 
function in those regions that would otherwise typically be performed 
through integrated resource planning, often before a state public 
service commission. As a result, Commission actions related to electric 
capacity market policies could have a primary indirect effect on the 
development and use of generation resources.
    Finally, agency actions involving generator interconnection 
policies could have a primary indirect effect on the development of 
domestic energy resources. For example, a wind or solar generator at 
utility scale typically must interconnect to the transmission grid in 
order to deliver the electricity produced by those domestic energy 
resources to the wholesale purchaser. If Commission policies or actions 
lead to a delay in interconnection or otherwise affect the generator's 
ability to interconnect, then the project developer may not develop 
that energy resource, which would impact the development or use of 
domestic energy resources.
    This final report does not review agency actions involving oil and 
natural gas pipeline rates; electric energy and ancillary service rates 
and market policies; \6\ electric transmission rates, including return 
on equity issues; demand response resources; mergers; enforcement; 
reliability; backstop transmission siting authority; and the Public 
Utilities Regulatory Policies Act. Commission action in these areas may 
indirectly impact the design, location, development, or use of domestic 
energy resources, but would not have a primary indirect effect, as 
discussed above.
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    \6\ Commission actions on energy and ancillary service market 
rules are less directly related to the development and use of 
domestic energy resources than Commission actions on centralized 
capacity market rules. While energy and ancillary service markets 
have an effect on the economic viability and day-to-day use of 
generation resources, the market rules established by the Commission 
are intended to ensure recovery of variable costs (e.g., fuel costs) 
for marginal units, rather than to be the primary source of fixed 
cost recovery for new generation resources. That is, in regions that 
do not have capacity markets, there is an additional mechanism to 
address fixed cost recovery typically administered by the relevant 
state regulatory commission, in the case of investor-owned public 
utilities, or the management of public power utilities.
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    Pursuant to the Guidance Memo's recommendation, this effort with 
respect to Executive Order 13783, to the extent appropriate, was 
coordinated with the Commission's Regulatory Reform Task Force created 
pursuant to Executive Order 13777.\7\
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    \7\ As with Executive Order 13783, independent regulatory 
agencies like the Commission are not subject to Executive Order 
13777, but are encouraged to comply.
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    This final report discusses those agency actions that rose to the 
level of a potential material burden as contemplated by the Executive 
Order and clarified by the Guidance Memo. For hydropower licensing and 
the LNG

[[Page 50519]]

and natural gas transportation facilities siting programs, the 
Executive Order review process revealed potentially burdensome agency 
actions related to regulations promulgated by the Commission. For 
electric capacity markets and generator interconnection, the Executive 
Order review process revealed potentially burdensome agency actions 
related to Commission rulemaking orders and case-specific orders, which 
typically did not result in the promulgation of regulations. This final 
report identifies steps the Commission may consider, to the extent 
permitted by law, to alleviate or eliminate the aspects of the agency 
actions that may burden the development or use of domestically produced 
energy resources.

C. Discussion

1. Hydropower Licensing
    Under Part I of the FPA, the Commission has the exclusive authority 
to issue licenses, small capacity exemptions (up to 10 megawatts (MW)), 
and conduit exemptions for non-federal hydropower projects. The 
Commission currently regulates over 1,600 licensed or exempted 
hydroelectric projects, representing about 56,000 MW of authorized 
installed capacity, which is more than half of all developed hydropower 
in the United States.
    The Commission is responsible for coordinating and managing the 
processing of hydropower project license and exemption applications, as 
well as applications for preliminary permits (under which permittees 
study proposed projects). This includes determining the effects of 
constructing, operating, and maintaining hydropower projects on 
environmental resources, and the need for the project's power. Pursuant 
to the FPA, issues considered during the review of license applications 
include power production; fish, wildlife, recreation, and other 
environmental issues; flood control; irrigation; and other water uses. 
Various statutory requirements also give other agencies a significant 
role in project development, and several state and federal agencies 
have mandatory authorities that limit the Commission's control of the 
cost and time required for licensing.
    Following the issuance of a license or exemption, the Commission 
oversees compliance with the terms and conditions of the license/
exemption for the duration of the license. This includes processing the 
filing of plans, reports, and license amendments. Additionally, the 
Commission must determine if it has jurisdiction over proposed or 
unlicensed operating projects; determine and assess headwater benefit 
charges; approve transfers of licensed projects; resolve complaints 
alleging noncompliance with license and exemption conditions; and act 
on applications for license surrenders.
    The Commission also is responsible for ensuring that the water-
retaining features of hydropower projects are designed, constructed, 
operated, and maintained using current engineering standards and 
federal guidelines for dam safety. Commission staff inspects projects 
to investigate potential dam safety problems and, every five years, a 
Commission-approved independent consulting engineer must inspect and 
evaluate projects with dams higher than 32.8 feet or with a total 
storage capacity of more than 2,000 acre-feet. The Commission also 
requires licensees to prepare emergency action plans and conducts 
training sessions on how to develop and test these plans.
    The vast majority of agency actions relating to the Commission's 
hydropower program do not present a material burden to hydropower 
resources. Specifically, most agency actions: (1) are necessary to 
administer the Commission's hydropower program and process hydropower 
license applications in an orderly manner; and/or (2) do not negatively 
affect the development of hydropower resources. As outlined below, 
however, this final report identifies three areas where potential 
material burdens may exist: licensing processes; exemption processes; 
and determinations on deficient applications.
a. Licensing Processes
i. ILP Default Regulation
    The Commission's regulations include three hydropower licensing 
processes for applicants: the Integrated Licensing Process (ILP), the 
Traditional Licensing Process (TLP), and the Alternative Licensing 
Process (ALP). The Commission's regulations assign the ILP as the 
default process for all license requests, and an applicant must 
specifically request and justify the use of either the TLP or ALP. 
Assigning the ILP as the default process could be materially burdensome 
due to: (1) the time and costs associated with obtaining the 
Commission's approval to use the TLP or ALP; and (2) in the event the 
Commission denies the request to use the TLP/ALP, there may be 
additional time and costs associated with the ILP, due to the 
structured nature of the process. The level of burden caused by the ILP 
default regulation is largely project-specific, and may be negligible/
non-existent for complex proceedings that could benefit from a more 
structured process such as the ILP. However, any material burden could 
be alleviated by making the ILP optional, and removing the requirement 
to seek Commission authorization to use the TLP and ALP (see 18 CFR 
4.30, 5.1, 5.3, 5.8, 16.1).
ii. Pre-Filing Application Requirement
    In the final stages of the Commission's pre-filing process for 
hydropower projects, the Commission's regulations require a potential 
applicant to submit a draft license application or preliminary 
licensing proposal before submitting a final license application (18 
CFR 4.38(c)(4) and 5.16, respectively). The Commission's regulations 
include minimum filing requirements for these documents (e.g., study 
results, analyses, and environmental measures), and a stakeholder 
review process. The requirement to file the draft application and 
preliminary licensing proposal may be materially burdensome in terms of 
the cost and delay associated with the preparation of the documents and 
the stakeholder review process. To eliminate material burdens, the 
Commission could consider revising its regulations to make this aspect 
of the pre-filing process optional for license applicants.
iii. Pre-Filing Schedule
    The ILP contains comment and filing deadlines throughout the pre- 
and post-filing application process to ensure a structured approach to 
hydropower licensing. The ILP, however, may be materially burdensome in 
terms of the schedule established for the pre-filing process (3-3.5 
years total). To alleviate this burden, the Commission could consider 
certain comment and filing deadline reductions to allow for an overall 
time savings of three months: (1) reduce the time that an applicant has 
to file a proposed study plan, and the Commission has to issue a second 
scoping document, from 45 days to 30 days after receiving comments (18 
CFR 5.10 and 5.11); (2) reduce the time for entities to file comments 
on the proposed study plan, from 90 days to 60 days (18 CFR 5.12); (3) 
reduce the time an applicant has to file a revised study plan, from 30 
days to 15 days (18 CFR 5.13); and (4) reduce the time for filing 
comments on an applicant's preliminary licensing proposal, from 90 days 
to 60 days (18 CFR 5.16).

[[Page 50520]]

iv. License Term Policy
    Section 6 of the FPA provides that hydropower licenses shall be 
issued for a term not to exceed 50 years. There is no minimum license 
term for original licenses (16 U.S.C. 799). Section 15(e) of the FPA 
provides that any new license for an existing project (i.e., relicense) 
shall be for a term that the Commission determines to be in the public 
interest, but not less than 30 years or more than 50 years (16 U.S.C. 
808(e)). Current Commission policy is to set a 30-year license term 
where there is little or no authorized redevelopment, new construction, 
or environmental mitigation and enhancement; a 40-year license term for 
a license involving a moderate amount of these activities; and a 50-
year license term where there is an extensive amount of such 
activity.\8\ On November 17, 2016, the Commission issued a notice of 
inquiry in FERC Docket No. RM17-4-000 inviting comments on what 
changes, if any, should be made to the license term policy. The license 
terms provide operational certainty and govern the frequency of the 
license renewal process, which influences the overall cost of 
development. In turn, shorter license terms could burden development by 
increasing the cost of development. The Commission currently is 
considering comments on the license term policy, which it could use to 
further evaluate the need for any future changes to the license term 
policy.
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    \8\ See City of Danville, Virginia, 58 FERC ] 61,318 (1992); and 
Consumers Power Co., 68 FERC ] 61,077, (1994).
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v. Minimum Filing Requirements
    The Commission's regulations contain minimum filing requirements 
depending on the size of a project, and whether construction or 
modification of a dam is needed for project operation. Part 4 of the 
Commission's regulations includes three subparts corresponding to these 
factors: (1) Subpart E--Application for License for Major Unconstructed 
Project and Major Modified Project (18 CFR 4.40); (2) Subpart F--
Application for License for Major Project--Existing Dam (18 CFR 4.50); 
and (3) Subpart G--Application for License for Minor Water Power 
Projects and Major Water Power Projects 5 MW or Less (18 CFR 4.60). 
Subparts E and F apply to projects greater than 5 MW, and include more 
onerous filing requirements than Subpart G, which applies to projects 
less than or equal to 5 MW. The 5 MW threshold is based on section 405 
of PURPA, which mandated a simplified and expeditious licensing 
procedure for small hydroelectric power projects with an installed 
capacity of 5 MW or less (see 46 FR 55,944 at 55,947 (1981); 16 U.S.C. 
Sec.  2705). The Hydropower Regulatory Efficiency Act of 2013 has since 
amended PURPA by increasing the size of a small hydroelectric power 
project from 5 to 10 MW. Therefore, the 5 MW threshold in 18 CFR 4.40, 
4.50, and 4.60 is materially burdensome to projects between 5 and 10 
MW, in terms of the cost and time associated with the more onerous 
filing requirements of Subparts E and F. To eliminate the material 
burden, the Commission could consider revising its regulations to 
increase the threshold from 5 MW.
b. Exemption Processes
i. Increased Capacity Requirement
    To qualify for a license exemption under section 405 of PURPA, an 
applicant must propose to install/increase the total capacity of a 
project to not more than 10 MW (18 CFR 4.30(b)(31), 4.31(c), and 
4.103(a)). The regulatory requirement to add new capacity at the 
project is not specifically required by section 405 of PURPA, and it 
materially burdens existing licensees that would otherwise be eligible 
to seek an exemption at the end of the existing license term. To 
eliminate this burden, the Commission could consider revising the 
regulations to remove the requirement to install or increase the 
capacity of the facility to qualify for an exemption.
ii. Small Hydropower Conversion Restrictions
    In the event that the Commission rejects an exemption application, 
the Commission's regulations do not explicitly provide an applicant 
with the ability to convert a small hydropower exemption application to 
a license application (18 CFR 4.105). The Commission's Handbook for 
Hydroelectric Project Licensing and 5 MW Exemptions from Licensing, 
issued April 2004, explicitly states at section 6.3.2:
    If the exemption application is dismissed, the process is 
terminated. There is no opportunity to convert the exemption 
application to an application for license.\9\
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    \9\ See www.ferc.gov/industries/hydropower/gen-info/handbooks/licensing_handbook.pdf.
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    In comparison, the Commission has established a process for 
converting a small conduit exemption application to a license 
application (18 CFR 4.93). The process for small conduits allows the 
applicant to submit additional information necessary to conform the 
conduit exemption application to the relevant regulations for a license 
application, and then be accepted for filing as of the date the 
exemption application was accepted for filing. The inability of an 
applicant of a small hydropower exemption to convert its application to 
a license application is materially burdensome because the applicant 
must initiate an entirely new license process after its exemption is 
rejected, thereby causing delay to the development of the resource. To 
eliminate this burden, the Commission could consider amending its 
regulations to explicitly provide the small hydropower exemption 
applicant with the ability to convert its exemption application to a 
license application if the exemption application is rejected.
c. Prohibition on Refiling Subsequent License Applications
    Pursuant to the authority provided in section 10(i) of the FPA (16 
U.S.C. 803), the Commission routinely waives certain sections of Part I 
of the FPA when it issues a minor license. As relevant, the Commission 
routinely waives section 15 of the FPA, which governs the Commission's 
procedures for issuing a new license to an existing licensee (i.e., a 
relicense) (16 U.S.C. and 808). Yet, the Commission's regulations 
require the licensee to file an application for relicense at least 24 
months before the expiration of the existing license (18 CFR 16.20(c)). 
Moreover, if the Commission rejects the application, it cannot be 
refiled (18 CFR 16.9(b)(4)). Rejecting a relicense application, and not 
providing the applicant with the opportunity to refile, is materially 
burdensome to the use of hydropower resources. To eliminate this 
burden, the Commission could consider revising its regulations at 18 
CFR 16.20 to provide the applicant with the option of resubmitting the 
application if the deficiencies are corrected.
2. LNG Facility and Natural Gas Pipeline and Storage Facility Siting
    Under section 7 of the NGA, 15 U.S.C. 717f, the Commission 
authorizes the construction, operation, or abandonment of interstate 
natural gas pipeline and storage projects, as well as certain types of 
LNG facilities (e.g., LNG plants engaged in the storage of interstate 
natural gas volumes). Similarly, under section 3 of the NGA, 15 U.S.C. 
717b(e)(1), the Commission authorizes the siting, construction and 
operation of LNG terminals through which the commodity passes for 
export or import. As part of these responsibilities, the Commission 
conducts both a non-environmental and

[[Page 50521]]

an environmental review of the proposed facilities. The non-
environmental review focuses on the engineering design, rate, and 
tariff considerations. The Commission carries out the environmental 
review with the cooperation of numerous federal, state, and local 
agencies, and with the input of other interested parties. Under the 
NGA, the Commission also is the lead federal agency for coordinating 
all applicable federal authorizations (e.g., required permits under the 
Clean Water Act, Clean Air Act, and Coastal Zone Management Act, among 
others) and preparing environmental analyses required under the 
National Environmental Policy Act (NEPA) for all interstate natural gas 
infrastructure and LNG import/export proposals.
    There are several distinct phases to the review process for 
interstate natural gas and LNG facilities under the Commission's 
jurisdiction: pre-filing review (if applicable); application review; 
and post-authorization compliance. During the pre-filing review, 
Commission staff begins work on the environmental review and engages 
with stakeholders with the goal of resolving issues before the filing 
of an application. Throughout the pre-filing process, Commission staff 
meets with stakeholders, visits the project site, and confers with 
federal, state, and local agencies.
    Once a project sponsor files an application with the Commission 
under NGA section 3 for LNG import/export terminals or under NGA 
section 7 for interstate pipeline and storage facilities, Commission 
staff analyzes both environmental and non-environmental aspects for a 
proposed project, including for LNG terminals safety and engineering. 
An Environmental Assessment or Environmental Impact Statement typically 
is issued for public comment, and ultimately, the Commission will issue 
an order on an application after considering both environmental and 
non-environmental issues.
    During the post-authorization compliance period, Commission staff 
monitors the project sponsor's compliance with the conditions directed 
by the Commission. Ultimately, Commission approval is required before 
the facility can begin operation and provide service.
    Pursuant to Executive Order 13783, the review encompassed the 
Commission's regulations, guidance documents, and policies related to 
the certification of interstate natural gas transportation facilities, 
authorization of LNG import and export facilities, authorization of 
certain transportation by interstate and intrastate pipelines, and 
environmental review under NEPA.
    The majority of agency actions relating to the siting and 
construction of interstate natural gas transportation and LNG 
facilities do not materially burden the transportation or delivery of 
domestically produced natural gas. Specifically, most of the 
Commission's actions: (1) Are necessary for the Commission to review 
and process NGA section 3 and 7 project applications; and/or (2) do not 
negatively affect the siting or construction of natural gas pipeline 
and storage facilities or LNG import/export facilities in a manner that 
has a direct or primary indirect effect on the development or use of 
domestic energy production.
    However, the Commission's regulations require a prospective 
applicant for authorization under section 3 of the NGA to site and 
construct LNG terminals and related jurisdictional natural gas 
facilities to engage in the Commission's pre-filing process. (18 CFR 
157.21(a)). The Commission's pre-filing regulations require applicants 
to use the pre-filing process for a minimum of 180 days before the 
filing of an application for any project that is required to engage in 
pre-filing. (18 CFR 157.21(a)(2)(1) and 153.6(c)). While, in general, 
the pre-filing process is designed to expedite the processing of 
applications, the mandatory imposition of the pre-filing process on LNG 
terminals and related pipeline projects for at least 180 days before an 
application can be filed may be materially burdensome for some projects 
in terms of the potential delay and costs associated with the process. 
Although the 180 day pre-filing process is required by statute for LNG 
terminals, 15 U.S.C. 717b-1(a), the statute did not mandate that the 
Commission also require ``related jurisdictional natural gas 
facilities'' to engage in pre-filing. However, related jurisdictional 
natural gas pipeline facilities need to be evaluated concurrent with a 
proposed LNG terminal to avoid segmentation under the National 
Environmental Policy Act. Further, the pre-filing process allows 
stakeholders to become involved in the overall Project at an early 
stage, and applicants can benefit from stakeholder's early 
identification and resolution of issues that may overlap with the LNG 
terminal. Without using the pre-filing process for related 
jurisdictional natural gas facilities, delays could occur during the 
application review, when issues are first identified and need 
resolution. Thus, although this regulation may result in delays or 
additional costs to the applicant early on in a project's development, 
its overall result is a more timely application review by considering 
all issues regarding a project concurrently. As such, there is no need 
for the Commission to consider any revision to this regulation.
3. Centralized Electric Capacity Market Policies
    Three of the Regional Transmission Operator/Independent System 
Operator (RTO/ISO) markets in the eastern U.S. have adopted centralized 
capacity markets to help address resource adequacy concerns.\10\ In 
particular, PJM, ISO-NE, and NYISO have implemented centralized 
capacity markets that were designed, in part, to ensure long-term 
resource adequacy by sending accurate price signals for investment in 
capacity resources, when and where needed.\11\ As a result, agency 
actions related to capacity market policies could have a primary 
indirect effect on the development and use of generation resources, 
including renewables, natural gas, and nuclear facilities.\12\
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    \10\ The Commission has defined resource adequacy as ``the 
availability of an adequate supply of generation or demand 
responsive resources to support safe and reliable operation of the 
grid.'' Cal. Indep. Sys. Operator Corp., 122 FERC ] 61,017, at P 3 
(2008).
    \11\ ``Capacity is not actual electricity. It is a commitment to 
produce electricity or forgo consumption of electricity when 
required.'' Advanced Energy Mgmt. All. v. FERC, No. 16-1234, 2017 WL 
2636455, at *1 (D.C. Cir. Jun. 20, 2017); see Conn. Dep't of Pub. 
Util. Control v. FERC, 569 F.3d 477, 482 (D.C. Cir. 2009) 
(explaining that capacity ``amounts to a kind of call option that 
electricity transmitters purchase from parties--generally, 
generators--who can either produce more or consumer less when 
required'').
    \12\ It is important to note that the Commission has not 
required RTOs/ISOs to implement centralized capacity markets; 
rather, the determination to include such markets has been a 
voluntary decision by the stakeholders in each particular RTO/ISO. 
However, once an RTO/ISO decides to implement such a capacity 
market, the Commission must ensure that the tariff provisions 
establishing the capacity market rules are just and reasonable and 
not unduly discriminatory or preferential.
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    The centralized capacity markets require load-serving entities to 
secure, either through self-supply \13\ or participation in the 
capacity auction, sufficient resources to meet their capacity 
obligation at a future time. All three centralized capacity markets 
allow participation by any resource that is technically qualified to 
provide the capacity product being procured and each market generally 
models locational constraints. Each conducts a capacity auction where 
eligible offers to sell capacity are compared to the demand for 
capacity resources, which is established through an administratively-

[[Page 50522]]

determined demand curve. Generally speaking, the market clears based on 
the intersection between the supply and demand curves. All cleared 
resources receive the market clearing price for capacity regardless of 
resource type.
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    \13\ While the specific rules vary by RTO/ISO, load-serving 
entities can own or construct resources or contract bilaterally for 
capacity from resources owned by other entities.
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    The Commission has issued multiple agency actions (i.e., Commission 
orders addressing the capacity market designs of the relevant organized 
markets) that govern the rules and design of the centralized capacity 
markets. Agency actions related to electric capacity markets were 
reviewed to determine if they impose a material burden on the 
development and use of domestic energy resources. In general, agency 
actions regarding centralized electricity capacity market design do not 
impose a material burden on the development and use of domestic energy 
resources because they generally seek to ensure adequate resources, and 
thereby facilitate the development of domestic energy resources, rather 
than create material burdens to the development and use of these 
resources. However, this final report discusses Commission actions 
regarding one aspect of centralized electricity capacity markets, 
buyer-side market power mitigation rules, due to the potentially 
material burdens Commission actions may have on the development of 
domestic energy resources.
    All three eastern RTOs/ISOs use some form of a minimum offer price 
rule (MOPR) as approved by Commission order. MOPRs as currently 
designed establish offer floors for certain new resources to protect 
against subsidized new entry that has the potential to artificially 
suppress capacity market prices. New resources that trigger this rule 
are required to submit offers into the capacity market auction at or 
above the floor. If the resource's mitigated offer price is too high to 
clear in the market, then the resource would not receive a capacity 
obligation and the associated market payments. Depending on the terms 
of any out-of-market contracts, the resource also may not be eligible 
to receive out-of-market payments if it does not clear in the capacity 
market auction. Without such compensation, the developer may conclude 
it is not economic to develop the resource. In this way, Commission 
actions on the MOPR arguably impose a burden on certain new resources.
    However, Commission actions on the MOPR do not rise to the level of 
a material burden, as the term is defined in the Executive Order and 
Guidance Memo. While application of the MOPR to a generator's bid may 
conceivably result in the developer deciding not to develop its 
generation resource, an individual generation developer's decision not 
to develop as a result of being subject to a MOPR would not in and of 
itself materially affect the use or development of oil, natural gas, 
coal, nuclear energy, or other domestic energy resources in the U.S. 
Therefore, Commission actions on MOPRs do not negatively affect the 
development and use of domestic energy resources by the electricity 
sector, despite the potential burden on those individual resources that 
are mitigated. Furthermore, from the perspective of other resources in 
the market, the MOPR can help preserve the integrity of the market 
price signals and revenue streams, thereby facilitating development and 
retention of other resources that might use domestic energy resources.
4. Generator Interconnection Policies
    Electric generators use domestic energy resources to produce 
electricity. Electric generators at utility scale must interconnect to 
the transmission system to deliver the electricity they produce to 
customers and receive benefits from the wholesale electric markets. The 
interconnection process is designed to ensure a new resource can safely 
and reliably deliver its output to end-users and to assign the costs to 
the party causing the costs of any system upgrades required to maintain 
safety and reliability. If a generator is not able to interconnect to 
the transmission system, or if it is too difficult or expensive to do 
so, the developer may decide not to pursue investment in the electric 
generation resource. Therefore, the ability of an electric generator to 
interconnect to a transmission system could affect the development or 
use of domestic energy resources.
    The Commission has issued multiple agency actions that govern and 
facilitate the interconnection of electric generators to public utility 
transmission systems. They include:
    Order No. 2003: In Order No. 2003, the Commission created standard 
large generator interconnection procedures and adopted a standard large 
generator interconnection agreement for the interconnection of electric 
generators larger than 20 MW, regardless of resource type.\14\
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    \14\ Standardization of Generator Interconnection Agreements and 
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146 (2003), 
order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ] 31,160, 
order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ] 31,171 
(2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. ] 
31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util. 
Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552 
U.S. 1230 (2008).
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    Order No. 2006: In Order No. 2006, the Commission created standard 
small generator interconnection procedures and a standard small 
generator interconnection agreement for the interconnection of electric 
generators no larger than 20 MW.\15\
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    \15\ Standardization of Small Generator Interconnection 
Agreements and Procedures, Order No. 2006, FERC Stats. & Regs. ] 
31,180, order on reh'g, Order No. 2006-A, FERC Stats. & Regs. ] 
31,196 (2005), order granting clarification, Order No. 2006-B, FERC 
Stats. & Regs. ] 31,221 (2006).
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    Order No. 661: In Order No. 661, the Commission required public 
utilities to add standard procedures and technical requirements for the 
interconnection of large wind generation resources to their standard 
large generator interconnection procedures and large generator 
interconnection agreements in their open access transmission 
tariffs.\16\
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    \16\ Interconnection for Wind Energy, Order No. 661, FERC Stats. 
& Regs. ] 31,186, order on reh'g, Order No. 661-A, FERC Stats. & 
Regs. ] 31,198 (2005).
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    Order No. 827: In Order No. 827, the Commission revised the 
interconnection agreements for both large and small non-synchronous 
generators to eliminate exemptions for wind generators from providing 
reactive power.\17\
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    \17\ Reactive Power Requirements for Non-Synchronous Generators, 
Order No. 827, FERC Stats. & Regs. ] 31,385, order on reh'g, 157 
FERC ] 61,003 (2016).
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    Order No. 828: In Order No. 828, the Commission modified the small 
generator interconnection agreement as set forth in Order Nos. 2006 and 
792 to require newly interconnecting small generating facilities to 
ride through abnormal frequency and voltage events and not disconnect 
during such events.\18\
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    \18\ Requirements for Frequency and Voltage Ride Through 
Capability of Small Generating Facilities, Order No. 828, 156 FERC ] 
61,062 (2016).
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    Order No. 792: In Order No. 792, the Commission revised the 
standard small generator interconnection procedures and standard small 
generator interconnection agreement for the interconnection of electric 
generators no larger than 20 MW.\19\
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    \19\ Small Generator Interconnection Agreements and Procedures, 
Order No. 792, 145 FERC ] 61,159 (2013), clarifying, Order No. 792-
A, 146 FERC ] 61,214 (2014).
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    None of these orders materially burden the development or use of 
domestic energy resources. The Commission's generator interconnection 
orders establish an orderly, uniform process for all types of 
generators to interconnect to the grid safely and reliably, 
facilitating their development by providing them with the means to 
deliver the electricity they produce to the purchaser. As such, these 
requirements will not unnecessarily obstruct, delay, curtail or 
otherwise

[[Page 50523]]

impose significant costs on the siting, permitting, production, 
utilization, transmission, or delivery of energy resources and 
therefore they will not materially burden the production or use of 
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domestic energy resources.

    Dated: October 25, 2017.
Kimberly D. Bose,
Secretary.
[FR Doc. 2017-23722 Filed 10-31-17; 8:45 am]
 BILLING CODE 6717-01-P