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).1Pursuant 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.' 

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.3In addition, these identified agency actions may be addressed in conjunction 

with the Commission's ongoing efforts pursuant to Executive Order 13777. 

Executive Order 13783, Promoting Energy Independence and Economic Growth, 

82 Fed. Reg. 16093 (Mar. 28, 2017). 

2The 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. 

3Memo 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 

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 
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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.4Given 

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 C.F.R.); 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 

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. 

4The 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. 

5This 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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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;6electric 

6Commission 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 
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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 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 nonfederal 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; 

public utilities, or the management of public power utilities. 

7As 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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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 darn 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 
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process. The level of burden caused by the ILP default regulation is largely projectspecific, 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 C.F.R. § 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 C.F.R. § 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 prefiling 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 C.F.R. § 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 C.F.R. 

§ 5.12); (3) reduce the time an applicant has to file a revised study plan, from 30 days to 

15 days (18 C.F.R. § 5.13); and (4) reduce the time for filing comments on an applicant's 

preliminary licensing proposal, from 90 days to 60 days (18 C.F.R. § 5.16). 

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 
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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.' 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. 

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 C.F.R. § 4.40); (2) Subpart F - Application for License 

for Major Project — Existing Dam (18 C.F.R. § 4.50); and (3) Subpart G - Application for 

License for Minor Water Power Projects and Major Water Power Projects 5 MW or Less 

(18 C.F.R. § 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. § 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 C.F.R. § 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. 

See City of Danville, Virginia, 58 FERC ¶ 61,318 (1992); and Consumers Power 

Co., 68 FERC IT 61,077, (1994). 
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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 

C.F.R. § 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 C.F.R. § 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.' 

In comparison, the Commission has established a process for converting a small conduit 

exemption application to a license application (18 C.F.R. § 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. 

9 See www.ferc.gov/industries/hydropower/gen-info/handbooks/licensinK_handbook.pdf 
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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 C.F.R. § 16.20(c)). Moreover, if the Commission rejects the 

application, it cannot be refiled (18 C.F.R. § 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 C.F.R. § 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 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 C.F.R. 

§ 157.21(a)). The Commission's pre-filing regulations require applicants to use the prefiling 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 C.F.R. § 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 prefiling. 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 
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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." In particular, PJM, ISO-NE, and NYISO have 

implemented centralized capacity markets that were designed, in part, to ensure longterm resource adequacy by sending accurate price signals for investment in capacity 

resources, when and where needed." 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.' 

The centralized capacity markets require load-serving entities to secure, either through 

self-supply13or participation in the capacity auction, sufficient resources to meet their 

11)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"). 

12It is important to note that the Commission has not required RT0s/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. 

13While 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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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-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 RT0s/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 outof-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 
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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 generator 

interconnection procedures and a standard small generator interconnection agreement for 

the interconnection of electric generators no larger than 20 MW.15 

14Standardization 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. ij 31,171(2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. If 31,190 

(2005), affd 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). 

15 Standardization of Small Generator Interconnection Agreements and 

Procedures, Order No. 2006, FERC Stats. & Regs. ¶ 31,180, order on reh'g, Order No. 
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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.' 

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.' 

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.' 

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." 

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 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. 

2006-A, FERC Stats. & Regs. If 31,196 (2005), order granting clarification, Order No. 

2006-B, FERC Stats. & Regs. If 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 Non-Synchronous Generators, Order No. 827, 

FERC Stats. & Regs. ¶ 31,385, order on reh'g, 157 FERC ¶ 61,003 (2016). 

18Requirements for Frequency and Voltage Ride Through Capability of Small 

Generating Facilities, Order No. 828, 156 FERC ¶ 61,062 (2016). 

19Small Generator Interconnection Agreements and Procedures, Order No. 792, 

145 FERC ¶ 61,159 (2013), clarifting, Order No. 792-A, 146 FERC ¶ 61,214 (2014).