Federal Register / Vol. 82, No. 210 / Wednesday, November 1, 2017 / Rules and Regulations 50517 

1Executive 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.’’ 

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. 

(3) * * * 

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 

AGENCY: Federal Energy Regulatory 

Commission, DOE. 

ACTION: Availability of Final Report. 

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

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. 

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 


sradovich on DSK3GMQ082PROD with RULES
50518 Federal Register / Vol. 82, No. 210 / Wednesday, November 1, 2017 / Rules and Regulations 

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. 

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 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. 

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. 

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

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. 

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 


sradovich on DSK3GMQ082PROD with RULES
Federal Register / Vol. 82, No. 210 / Wednesday, November 1, 2017 / Rules and Regulations 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 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). 


sradovich on DSK3GMQ082PROD with RULES
50520 Federal Register / Vol. 82, No. 210 / Wednesday, November 1, 2017 / Rules and Regulations 

8See City of Danville, Virginia, 58 FERC ¶ 61,318 

(1992); and Consumers Power Co., 68 FERC ¶ 

61,077, (1994). 

9See www.ferc.gov/industries/hydropower/geninfo/handbooks/licensing_handbook.pdf. 

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. 

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. § 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

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 


sradovich on DSK3GMQ082PROD with RULES
Federal Register / Vol. 82, No. 210 / Wednesday, November 1, 2017 / Rules and Regulations 50521 

10The 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. 

13While 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. 

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 

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 

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 administrativelyVerDate Sep<11>2014 17:12 Oct 31, 2017 Jkt 244001 PO 00000 Frm 00031 Fmt 4700 Sfmt 4700 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 

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. 

¶ 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). 

15Standardization 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). 

17Reactive Power Requirements for NonSynchronous 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), clarifying, Order No. 792–A, 146 FERC ¶ 

61,214 (2014). 

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 

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 

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 


sradovich on DSK3GMQ082PROD with RULES
Federal Register / Vol. 82, No. 210 / Wednesday, November 1, 2017 / Rules and Regulations 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 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 

AGENCY: U.S. Customs and Border 

Protection, Department of Homeland 

Security; Department of the Treasury. 

ACTION: Final rule. 

SUMMARY: 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: 

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 

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 12- 

month 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 

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 


sradovich on DSK3GMQ082PROD with RULES