30924 Federal Register / Vol. 74, No. 123 / Monday, June 29, 2009 / Rules and Regulations 

Subject 

(d) Air Transport Association (ATA) of 

America Code 55: Stabilizers. 

Unsafe Condition 

(e) This AD results from a report of cracks 

found in the right upper aft skin panel of the 

horizontal stabilizer at the aft inboard corner. 

We are issuing this AD to detect and correct 

cracks in the fail-safe structure that may not 

be able to sustain limit load, which could 

result in the loss of overall structural 

integrity of the horizontal stabilizer. 

Compliance 

(f) Comply with this AD within the 

compliance times specified, unless already 

done. 

Inspections 

(g) Except as required by paragraphs (h) 

and (i) of this AD: At the times specified in 

paragraph 1.E., ‘‘Compliance,’’ of Boeing 

Alert Service Bulletin MD90–55A012, dated 

September 23, 2008, do an eddy current 

inspection for cracks of the upper aft skin 

panels on the left and right sides of the 

horizontal stabilizer, and do all applicable 

related investigative and corrective actions, 

in accordance with the Accomplishment 

Instructions of the service bulletin. 

Exceptions to Service Bulletin Specifications 

(h) Where Boeing Alert Service Bulletin 

MD90–55A012, dated September 23, 2008, 

specifies a compliance time after the date on 

the service bulletin, this AD requires 

compliance within the specified compliance 

time after the effective date of this AD. 

(i) If any crack is found during any 

inspection required by this AD, and Boeing 

Alert Service Bulletin MD90–55A012, dated 

September 23, 2008, specifies to contact 

Boeing for appropriate action: Before further 

flight, repair using a method approved in 

accordance with the procedures specified in 

paragraph (k) of this AD. 

Inspections Done According to Multiple 

Operator Message 

(j) Inspections and corrective actions done 

before the effective date of this AD are 

acceptable for compliance with the 

corresponding requirements of this AD, if 

done in accordance with Boeing Multiple 

Operator Message 1–669017091–1, dated 

November 9, 2007. 

Alternative Methods of Compliance 

(AMOCs) 

(k)(1) The Manager, Los Angeles Aircraft 

Certification Office, FAA, ATTN: Roger 

Durbin, Aerospace Engineer, Airframe 

Branch, ANM–120L, FAA, Los Angeles 

Aircraft Certification Office, 3960 Paramount 

Boulevard, Lakewood, California 90712– 

4137; telephone (562) 627–5233; fax (562) 

627–5210; has the authority to approve 

AMOCs for this AD, if requested using the 

procedures found in 14 CFR 39.19. 

(2) To request a different method of 

compliance or a different compliance time 

for this AD, follow the procedures in 14 CFR 

39.19. Before using any approved AMOC on 

any airplane to which the AMOC applies, 

notify your principal maintenance inspector 

(PMI) or principal avionics inspector (PAI), 

as appropriate, in the FAA Flight Standards 

District Office (FSDO), or lacking a principal 

inspector, your local FSDO. The AMOC 

approval letter must specifically reference 

this AD. 

(3) An AMOC that provides an acceptable 

level of safety may be used for any repair 

required by this AD, if it is approved by an 

Authorized Representative for the Boeing 

Commercial Airplanes Delegation Option 

Authorization Organization who has been 

authorized by the Manager, Los Angeles 

ACO, to make those findings. For a repair 

method to be approved, the repair must meet 

the certification basis of the airplane and the 

approval must specifically refer to this AD. 

Material Incorporated by Reference 

(l) You must use Boeing Alert Service 

Bulletin MD90–55A012, dated September 23, 

2008, to do the actions required by this AD, 

unless the AD specifies otherwise. 

(1) The Director of the Federal Register 

approved the incorporation by reference of 

this service information under 5 U.S.C. 

552(a) and 1 CFR part 51. 

(2) For service information identified in 

this AD, contact Boeing Commercial 

Airplanes, Attention: Data & Services 

Management, 3855 Lakewood Boulevard, MC 

D800–0019, Long Beach, California 90846– 

0001; telephone 206–544–5000, extension 2; 

fax 206–766–5683; e-mail 

dse.boecom@boeing.com; Internet https:// 

www.myboeingfleet.com. 

(3) You may review copies of the service 

information at the FAA, Transport Airplane 

Directorate, 1601 Lind Avenue, SW., Renton, 

Washington. For information on the 

availability of this material at the FAA, call 

425–227–1221 or 425–227–1152. 

(4) You may also review copies of the 

service information that is incorporated by 

reference at the National Archives and 

Records Administration (NARA). For 

information on the availability of this 

material at NARA, call 202–741–6030, or go 

to: http://www.archives.gov/federal_register/ 

code_of_federal_regulations/ 

ibr_locations.html. 

Issued in Renton, Washington, on June 16, 

2009. 

Dorr M. Anderson, 

Acting Manager, Transport Airplane 

Directorate, Aircraft Certification Service. 

[FR Doc. E9–14680 Filed 6–26–09; 8:45 am] 

BILLING CODE 4910–13–P 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 35 

[Docket No. RM04–7–006; Order No. 697– 

C] 

Market-Based Rates For Wholesale 

Sales of Electric Energy, Capacity and 

Ancillary Services by Public Utilities 

Issued June 18, 2009. 

AGENCY: Federal Energy Regulatory 

Commission. 

ACTION: Order on rehearing and 

clarification. 

SUMMARY: The Federal Energy 

Regulatory Commission is granting in 

part and denying in part the requests for 

rehearing and clarification of its 

determinations in Order No. 697–B, 

which granted rehearing and 

clarification of certain revisions to 

Commission regulations and to the 

standards for obtaining and retaining 

market-based rate authority for sales of 

energy, capacity and ancillary services 

to ensure that such sales are just and 

reasonable. 

DATES: Effective Date: This order on 

rehearing will become effective July 29, 

2009. 

FOR FURTHER INFORMATION CONTACT: 

Michelle Barnaby (Technical 

Information), Office of Energy Market 

Regulation, Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, (202) 502– 

8407. 

Paige Bullard (Legal Information), Office 

of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426, (202) 502–6462. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

Paragraph No. 

I. Introduction ................................................................................................................................................................................... 1 

II. Background ................................................................................................................................................................................... 2 

III. Discussion ................................................................................................................................................................................... 8 

A. Vertical Market Power ......................................................................................................................................................... 8 

Other Barriers to Entry ...................................................................................................................................................... 8 

B. Mitigation .............................................................................................................................................................................. 23 


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Federal Register / Vol. 74, No. 123 / Monday, June 29, 2009 / Rules and Regulations 30925 

1 18 CFR 35.42 (2008). 

2 Market-Based Rates for Wholesale Sales of 

Electric Energy, Capacity and Ancillary Services by 

Public Utilities, Order No. 697–B, 73 FR 79,610 

(Dec. 30, 2008), FERC Stats. & Regs. ¶ 31,285 (2008). 3 Market-Based Rates for Wholesale Sales of 

Electric Energy, Capacity and Ancillary Services by 

Public Utilities, Order No. 697, FERC Stats. & Regs. 

¶ 31,252 (Order No. 697 or Final Rule), clarified, 

121 FERC ¶ 61,260 (2007), order on reh’g, Order No. 

697–A, 73 FR 25,832 (May 7, 2008), FERC Stats. & 

Regs. ¶ 31,268 (2008); clarified, 124 FERC ¶ 61,055 

(2008) (July 17 Clarification Order), order on reh’g, 

Order No. 697–B, 73 FR 79,610 (Dec. 30, 2008), 

FERC Stats. & Regs. ¶ 31,285 (2008). 

4 Market-Based Rates for Wholesale Sales of 

Electric Energy, Capacity and Ancillary Services by 

Public Utilities, 121 FERC ¶ 61,260 (2007) 

(December 14 Clarification Order). 

5Order No. 697–A, FERC Stats. & Regs. ¶ 31,268 

(2008). 

6 July 17 Clarification Order, 124 FERC ¶ 61,055. 

7 Id. P 5. 

8Order No. 697–B, FERC Stats. & Regs. ¶ 31,285. 

Paragraph No. 

Protecting Mitigated Markets ....................................................................................................................................................... 23 

C. Implementation Process ....................................................................................................................................................... 47 

Clarifications on Implementation Process ........................................................................................................................ 47 

IV. Information Collection Statement .............................................................................................................................................. 49 

V. Document Availability ................................................................................................................................................................ 50 

VI. Effective Date .............................................................................................................................................................................. 53 

Regulatory Text 

Appendix C to Order No. 697–C: Revised Tariff Language 

Appendix D–2 to Order No. 697–C: Revised Regional Review Schedule 

Before Commissioners: Jon Wellinghoff, 

Chairman; Suedeen G. Kelly, Marc Spitzer, 

and Philip D. Moeller. 

Order on Rehearing and Clarification 

I. Introduction 

1. In this order, the Commission 

addresses requests for rehearing and 

clarification of Order No. 697–B. 

Specifically, the Commission clarifies 

the requirement that sellers file a 

notification of change in status when 

they acquire sites for new generation 

capacity development.1 The 

Commission denies the requests for 

rehearing of the tariff provision 

governing mitigated sales at the metered 

boundary and affirms its determination 

in Order No. 697–B to revise the 

mitigated sales tariff provision in order 

to ensure that a mitigated seller making 

market-based rate sales at the metered 

boundary does not sell power into the 

mitigated market either directly or 

through its affiliates.2

II. Background 

2. On June 21, 2007, the Federal 

Energy Regulatory Commission 

(Commission) issued Order No. 697,3

codifying and, in certain respects, 

revising its standards for obtaining and 

retaining market-based rates for public 

utilities. In order to accomplish this, as 

well as streamline the administration of 

the market-based rate program, the 

Commission modified its regulations at 

18 CFR part 35, subpart H, governing 

market-based rate authorization. The 

Commission explained that there are 

three major aspects of its market-based 

regulatory regime: (1) Market power 

analyses of sellers and associated 

conditions and filing requirements; (2) 

market rules imposed on sellers that 

participate in Regional Transmission 

Organization (RTO) and Independent 

System Operator (ISO) organized 

markets; and (3) ongoing oversight and 

enforcement activities. Order No. 697 

focused on the first of the three features 

to ensure that market-based rates 

charged by public utilities are just and 

reasonable. Order No. 697 became 

effective on September 18, 2007. 

3. The Commission issued an order 

clarifying four aspects of Order No. 697 

on December 14, 2007.4 Specifically, 

that order addressed: (1) The effective 

date for compliance with the 

requirements of Order No. 697; (2) 

which entities are required to file 

updated market power analyses for the 

Commission’s regional review; (3) the 

data required for horizontal market 

power analyses; and (4) what constitute 

‘‘seller-specific terms and conditions’’ 

that sellers may list in their marketbased rate tariffs in addition to the 

standard provisions listed in Appendix 

C to Order No. 697. The Commission 

also extended the deadline for sellers to 

file the first set of regional triennial 

studies that were directed in Order No. 

697 from December 2007 to 30 days 

after the date of issuance of the 

December 14 Clarification Order. 

4. On April 21, 2008, the Commission 

issued Order No. 697–A,5 in which it 

responded to a number of requests for 

rehearing and clarification of Order No. 

697. In most respects, the Commission 

affirmed the determinations made in 

Order No. 697 and denied rehearing of 

the issues raised. However, with respect 

to several issues, the Commission 

granted rehearing or provided 

clarification. 

5. On July 17, 2008, the Commission 

issued an order clarifying certain 

aspects of Order No. 697–A related to 

the allocation of simultaneous 

transmission import capability for 

purposes of performing the indicative 

screens.6 Specifically, that order granted 

the requests for rehearing with regard to 

footnote 208 of Order No. 697–A and 

clarified that in performing the 

indicative screen analysis, market-based 

rate sellers may allocate the 

simultaneous import limit capability on 

a pro rata basis (after accounting for the 

seller’s firm transmission rights) based 

on the relative shares of the seller’s (and 

its affiliates’) and competing suppliers’ 

uncommitted generation capacity in 

first-tier markets.7

6. On December 19, 2008, the 

Commission issued Order No. 697–B8

in which it clarified and affirmed the 

determinations made in Order No. 697– 

A. Specifically, the Commission 

provided clarification regarding the 

allocation of seasonal and longer 

transmission reservations. The 

Commission also clarified that it will 

require a seller making an affirmative 

statement as to whether a contractual 

arrangement transfers control to seek a 

‘‘letter of concurrence’’ from other 

affected parties identifying the degree to 

which each party controls a facility, and 

to submit these letters with its filing. 

The Commission denied the request that 

it clarify that only sites for which 

necessary permitting for a generation 

plant has been completed and/or sites 

on which construction for a generation 

plant has begun apply under the 

definition of ‘‘inputs to electric power 

production’’ in § 35.36(a)(4) of the 

Commission’s regulations. The 

Commission also revised the definition 

of ‘‘affiliate’’ in section 35.36(a)(9) of its 

regulations to delete the separate 

definition for exempt wholesale 

generators. In addition, the Commission 

provided a number of other 

clarifications with regard to, among 

others, the pricing of sales of non-power 

goods and services and the tariff 

provision governing sales at the metered 

boundary. 

7. On January 28, 2009, in response to 

Tampa Electric Company’s (Tampa 

Electric) request for extension of time to 

comply with the tariff provision on 


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30926 Federal Register / Vol. 74, No. 123 / Monday, June 29, 2009 / Rules and Regulations 

9 Market-Based Rates for Wholesale Sales of 

Electric Energy, Capacity and Ancillary Services by 

Public Utilities, 126 FERC ¶ 61,072 (2009) (Order 

Granting Extension of Time to Comply). 

10Order No. 697–A, FERC Stats. & Regs. ¶ 31,268 

at Appendix C. 

11Order No. 697, FERC Stats. & Regs. ¶ 31,252 at 

P 440. 

12 Id. 

13Order No. 697–A, FERC Stats. & Regs. ¶ 31,268 

at P 176 (emphasis in original). 

14 Id. 

15Order No. 697–B, FERC Stats. & Regs. ¶ 31,285 

at P 38. 

16American Wind January 21, 2009 Rehearing 

Request at 5. 

17 Id. at 5–6. 

18 Id. at 6–7. 

19 Id. at 7. 

20 Id. 

21 Id. at 8. 

mitigated sales at the metered boundary 

as revised in Order No. 697-B, the 

Commission issued an order granting 

the extension requested by Tampa 

Electric until such time as the 

Commission issues an order on 

rehearing of Order No. 697–B.9 That 

order clarified that affected entities 

must continue to comply with the 

mitigated sales tariff provision adopted 

in Order No. 697–A 10 (which became 

effective on June 6, 2008), until such 

time as the Commission acts on the 

requests for rehearing of Order No. 697– 

B. 

III. Discussion 

A. Vertical Market Power 

Other Barriers to Entry 

Background 

8. Order No. 697 adopted the NOPR 

proposal to consider a seller’s ability to 

erect other barriers to entry as part of 

the vertical market power analysis, but 

modified the requirements when 

addressing other barriers to entry.11 It 

also provided clarification regarding the 

information that a seller must provide 

with respect to other barriers to entry 

(including which inputs to electric 

power production the Commission will 

consider as other barriers to entry) and 

modified the proposed regulatory text in 

that regard.12

9. On rehearing, the Commission 

clarified that it was not its intent for the 

term ‘‘inputs to electric power 

production’’ to encompass every 

instance of a seller entering into a coal 

supply contract with a coal vendor in 

the ordinary course of business. The 

Commission clarified that Order No. 697 

encompasses physical coal sources and 

ownership of or control over who may 

access transportation of coal via barges 

and railcar trains.13 Thus, the 

Commission revised its definition of 

‘‘inputs to electric power production’’ in 

§ 35.36(a)(4) as follows: ‘‘intrastate 

natural gas transportation, intrastate 

natural gas storage or distribution 

facilities; sites for new generation 

capacity development; physical coal 

supply sources and ownership of or 

control over who may access 

transportation of coal supplies.’’ 14

10. In Order No. 697–B, the 

Commission rejected the Electric Power 

Supply Association’s (EPSA) proposal 

that the term ‘‘sites for new generation 

capacity development’’ mean only sites 

with respect to which permits for new 

generation have been obtained or where 

construction of new generation is 

underway, and not encompass land that 

could potentially be used for generation. 

The Commission explained that ‘‘sites 

for new generation capacity 

development’’ should be construed to 

include ownership of land that could 

potentially be used for generation, not 

just sites for which permits for new 

generation have been obtained or where 

construction of new generation is 

underway. The Commission also 

clarified that ‘‘sites for new generation 

capacity development’’ does not include 

land that cannot be used for generation 

capacity development.15

Requests for Rehearing 

11. American Wind Energy 

Association (American Wind) requests 

rehearing of Order No. 697–B’s 

clarification that sites for new 

generation capacity development should 

be construed to include ownership of 

land that could potentially be used for 

generation, arguing that the scope and 

intent behind this requirement was not 

fully illuminated until the 

Commission’s clarification of this 

requirement in Order No. 697–B.16

American Wind contends that the 

Commission should grant rehearing of 

the term ‘‘sites for new generation 

capacity development’’ so as to only 

require reporting for sites for new 

generation development that are located 

in load pockets where a ‘‘potential’’ for 

vertical market power may exist, and 

should clarify that it will rely on the 

existing rebuttable presumption that all 

other sites do not create a barrier to 

entry.17

12. American Wind argues that the 

Commission’s interpretation of the 

reporting burden to include sites that 

could potentially be used for generation 

substantially increases the regulatory 

compliance burden on market-based 

rate sellers, and that the increased 

burden can be illustrated with respect to 

the impact on wind energy developers. 

It explains that in developing new wind 

power generation sites, wind energy 

developers seek to initially lease 

approximately 150 acres for each 

turbine. American Wind states that in 

developing a 100 megawatt project 

using 1.5 megawatt wind turbines, a 

developer may seek to initially have 

10,000 acres of land under control. It 

further explains that control over such 

land may result from leases that would 

likely be made with multiple 

landowners over a period of several 

months, and that in regions with 

significant wind development, it would 

not be surprising to find a vast number 

of acres for potential new generation 

sites under some form of control, via 

leases or some other form of agreement, 

by wind energy developers.18

13. According to American Wind, the 

requirement to file notifications of 

change in status every time a marketbased rate seller or its affiliates acquire 

sites that potentially could be used for 

generation would create a substantial 

burden and a competitive risk, while 

not providing any associated benefit to 

the Commission. American Wind asserts 

that wind developers in particular 

would be subjected to increased risk of 

the disclosure of their proprietary and 

competitive information because wind 

developers regularly compete for new 

land that can be used for wind 

development projects.19 It states that in 

the development process, wind energy 

developers spend significant time and 

effort searching for new land that may 

be appropriate for wind development 

sites, and that information as to where 

a wind energy developer is considering 

the development of new generation 

projects is highly proprietary and 

confidential. American Wind contends 

that even assuming a filing submitted at 

the Commission includes information 

‘‘on a summarized, balancing authority 

area basis, given the small size of some 

balancing authorities, the public release 

of such proprietary and confidential 

information could lead to competitive 

harm.’’ 20 American Wind also argues 

that if a seller’s control of potential new 

generation sites were alleged to create a 

new barrier to entry, the Commission, 

either pursuant to a complaint filed by 

a third party or a Commission-initiated 

investigation, would have ample 

authority to take action and challenge 

the rebuttable presumption that 

ownership or control over sites for new 

generation development does not create 

a barrier to entry.21

14. American Wind therefore requests 

that the Commission grant rehearing of 

the term ‘‘sites for new generation 

capacity development’’ so as to only 

require reporting for sites for new 


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Federal Register / Vol. 74, No. 123 / Monday, June 29, 2009 / Rules and Regulations 30927 

22 Id. at 9. 

23 Id. at 11. 

24 Id. 

25See id. at 6 (stating that ‘‘in developing a 100 

MW project using 1.5 MW wind turbines 

(approximately 65 turbines), a developer may seek 

to initially have under control 10,000 acres of 

land.’’). 

26Standardization of Generator Interconnection 

Agreements and Procedures, Order No. 2003, FERC 

Stats. & Regs. ¶ 31,146, at P 270 (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). 

27 Id. P 114. 

28See Order No. 697, FERC Stats. & Regs. 

¶ 31,252 at P 446; 1018 (explaining that the 

Commission will allow intervenors to rebut the 

presumption that a seller’s ownership of, control of 

or affiliation with entities that own or control 

inputs to electric power production do not allow a 

seller to raise entry barriers). 

29Section 1 of the LGIP adopted in Order No. 

2003 defines ‘‘site control’’ as ‘‘documentation 

reasonably demonstrating: (1) Ownership of, a 

leasehold interest in, or a right to develop a site for 

the purpose of constructing the Generating Facility; 

(2) an option to purchase or acquire a leasehold site 

for such purpose; or (3) an exclusivity or other 

business relationship between Interconnection 

Customer and the entity having the right to sell, 

lease or grant Interconnection Customer the right to 

possess or occupy a site for such purpose.’’ Order 

No. 2003, FERC Stats. & Regs. ¶ 31,146, LGIP § 1. 

The same requirements apply to small generators 

and wind generating facilities. See Order No. 2006, 

FERC Stats. & Regs. ¶ 31,180, Small Generator 

Interconnection Procedures § 1.5; 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). 

30See LGIP § 3.3.1 (stating that ‘‘[t]o initiate an 

Interconnection Request, Interconnection Customer 

must submit all of the following: (i) a $10,000 

deposit, (ii) a completed application in the form of 

Appendix 1, and (iii) demonstration of Site Control 

or a posting of an additional deposit of $10,000. 

Such deposits shall be applied toward any 

Interconnection Studies pursuant to the 

Interconnection Request. If Interconnection 

Customer demonstrates Site Control within the cure 

period specified in Section 3.3.3 after submitting its 

Interconnection Request, the additional deposit 

shall be refundable; otherwise, all such deposit(s), 

additional and initial, become non-refundable.’’). 

generation capacity development that 

are located in load pockets where a 

‘‘potential’’ for vertical market power 

may exist. American Wind argues that 

for the purposes of this reporting 

requirement, the Commission could 

define load pockets as submarkets 

where the Commission has determined 

that internal transmission constraints 

make the market smaller than the 

balancing authority area, RTO/ISO 

footprint or RTO/ISO submarket.22

15. If the Commission declines to 

grant its request to only require 

reporting for sites for new generation 

development that are located in load 

pockets where a ‘‘potential’’ for vertical 

market power may exist, American 

Wind requests clarification that the 

Commission will only require reporting 

for sites for new generation capacity 

development when ‘‘site control’’ is first 

required to be demonstrated in the 

interconnection process.23 American 

Wind claims that sites that have not yet 

been required to demonstrate site 

control in the interconnection process 

would not likely be used to enhance a 

seller’s vertical market power, and 

accordingly, there is no need for the 

Commission to be notified of such sites 

prior to when ‘‘site control’’ is required 

to be demonstrated. American Wind 

argues that using this milestone as the 

triggering point for when a seller must 

notify the Commission of sites for new 

generation capacity development 

‘‘would better align the reporting 

requirement with the underlying 

vertical market power concerns that are 

at the heart of the requirement’’ and 

‘‘would strike a better balance between 

the Commission’s regulatory concerns 

and the compliance burden on and 

competitive risks to market-based rate 

sellers.’’ 24

Commission Determination 

16. We will deny American Wind’s 

request for rehearing of the definition of 

‘‘inputs to electric power production’’ 

so that it requires only reporting for 

sites for new generation capacity 

development that are located in load 

pockets where a ‘‘potential’’ for vertical 

market power may exist. Such a revision 

to the requirement is too narrowly 

focused and therefore would not allow 

the Commission to timely monitor for 

potential barriers to entry or affiliate 

abuse involving generation sites. Since 

load pockets typically exist in areas 

(e.g., population centers) that are not 

well-suited for the development of 

renewable generation sources (e.g., large 

wind farms requiring thousands of acres 

of land),25 limiting the reporting of sites 

for new generation development to just 

load pockets would mean that the 

Commission would not be informed of 

most instances where land was being 

acquired for the development of new 

renewable generation capacity. 

17. With respect to American Wind’s 

alternative request that the Commission 

only require reporting for sites for new 

generation capacity development when 

site control is first required to be 

demonstrated in the interconnection 

process, we believe this approach has 

merit, as modified below. Modifications 

are necessary because it is not clear that 

American Wind’s request would address 

both its concerns about the disclosure of 

commercially sensitive information and 

the Commission’s regulatory concerns 

regarding a seller’s ability to erect 

barriers to entry through its acquisition 

of sites for new generation capacity 

development. First, the information 

provided in an interconnection request, 

including the demonstration of site 

control, is not required to be public.26

Second, transmission providers post the 

location of interconnection requests on 

OASIS by county and State, but do not 

post the identity of the interconnection 

customer when the interconnection 

request is made ‘‘because disclosing the 

identity at that early stage may put the 

Interconnection Customer at a 

competitive disadvantage and its project 

at risk.’’ 27 Thus, the American Wind 

alternative approach would require the 

seller to report information that in the 

interconnection process may be 

considered non-public and proprietary. 

While American Wind’s concerns about 

the disclosure of commercially sensitive 

information could be addressed by 

allowing sellers to file site information 

with the Commission confidentially, we 

do not believe that it is appropriate to 

routinely permit change in status 

reports to be filed at the Commission as 

non-public documents. One of the 

purposes of the change of status 

reporting requirement is to provide 

interested parties the opportunity to 

intervene and comment if they believe 

the seller’s acquisition of sites for new 

generation capacity development creates 

a barrier to entry, which could be 

undermined if such reports were 

routinely filed with confidential 

information redacted.28

18. Accordingly, in order to address 

our regulatory concerns and the 

concerns of American Wind, we grant 

rehearing and revise section 35.42 of our 

regulations to require, for all entities 

with market-based rate authorization, 

quarterly reporting of a seller’s 

acquisition of a site or sites for new 

generation capacity development for 

which site control has been 

demonstrated in the interconnection 

process and for which the potential 

number of megawatts that are 

reasonably commercially feasible on the 

site or sites for new generation capacity 

development is equal to 100 megawatts 

or more. For the purposes of this 

reporting requirement, we will use the 

definition of ‘‘site control’’ that is 

provided in section 1 of the Standard 

Large Generator Interconnection 

Procedures (LGIP).29 To the extent that 

a seller elects to make a monetary 

deposit so that it may demonstrate site 

control at a later time in the 

interconnection process,30 such deposit 

will trigger this quarterly reporting 

requirement instead of the 

demonstration of site control if the 


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30928 Federal Register / Vol. 74, No. 123 / Monday, June 29, 2009 / Rules and Regulations 

31We note that if a term other than ‘‘site control’’ 

is used to describe the specific means by which site 

control is demonstrated in the interconnection 

process, then the reporting requirement will be 

triggered when a demonstration of site control is 

made under that term. For example, ‘‘site 

exclusivity’’ is considered as the specific means by 

which site control is determined in the California 

Independent System Operator’s (CAISO’s) 

Generator Interconnection Process Reform tariff 

amendment. See California Independent System 

Operator Corp., 124 FERC ¶ 61,292, at P 40–41, 63 

(2008). Therefore, the demonstration of ‘‘site 

exclusivity’’ in the interconnection process set forth 

in the CAISO’s Generator Interconnection Process 

Reform tariff amendment will trigger the quarterly 

requirement to report a seller’s acquisition of 

control of a site or sites for new generation capacity 

development. 

32 In this context, ‘‘control’’ refers to ‘‘site 

control’’ as it is defined in the LGIP, or as explained 

in footnote 31. 

33A change in status includes, but is not limited 

to, the following: Ownership or control of 

generation capacity that results in net increases of 

100 MW or more, or of inputs to electric power 

production, or ownership, operation or control of 

transmission facilities, or affiliation with any entity 

not disclosed in the application for market-based 

rate authority that owns or controls generation 

facilities or inputs to electric power production or 

that owns, operates or controls transmission 

facilities, or affiliation with any entity that has a 

franchised service area. See 18 CFR 35.42. 

34The relevant geographic markets include those 

defined in Order No. 697 and those defined in 

subsequent Commission orders. Order No. 697, 

FERC Stats. & Regs. ¶ 31,252 at P 231–32, 237. 

35We note that if a site is later expanded to allow 

for additional generation capacity development and 

such expansion results in an increase of 100 

megawatts or more, a seller will be required to file 

a notification of change in status to notify the 

Commission of such a change within 30 days after 

the end of that quarter. 

potential number of megawatts that are 

reasonably commercially feasible on the 

site or sites for new generation capacity 

development is equal to 100 megawatts 

or more.31 All market-based rate sellers 

will be required to report the acquisition 

of control of sites for new generation 

capacity development on a quarterly 

basis instead of within 30 days of the 

acquisition.32 Such quarterly filings 

must be submitted within 30 days after 

the end of each quarter, e.g., by April 30 

for the first quarter. Thus, the time 

period in which sellers are required to 

report the acquisition of control of sites 

for new generation capacity 

development is being extended, which 

will ease some of the administrative 

burden about which American Wind 

has raised concerns. For all changes in 

status other than the acquisition of 

control of sites for new generation 

capacity development, all sellers will 

still be required to file a change in status 

report no later than 30 days after the 

change in status occurs.33

19. The quarterly reports that entities 

will be submitting to report the 

acquisition of control of a site or sites 

for new generation capacity 

development must include: (a) The 

number of sites acquired; (b) the 

relevant geographic market in which the 

sites are located; 34 and (c) the 

maximum potential number of 

megawatts that are reasonably 

commercially feasible on the sites 

reported, which must be justified.35 The 

information regarding the maximum 

potential number of megawatts for the 

sites may be reported on an aggregate 

basis for each relevant geographic 

market(s) in which the site(s) are 

located, i.e., without providing the 

specific location of particular sites. 

Sellers must provide a justification for 

the number of megawatts that they 

estimate could be developed on the site 

or sites. Such justification must be 

based on the maximum potential 

number of megawatts that could be 

produced on the site with the 

technology for which the site was 

acquired. Sellers must be forthright in 

estimating and reporting the maximum 

potential number of megawatts that are 

reasonably commercially feasible on the 

site or sites for new generation capacity 

development. The Commission will use 

all of this reported information to 

identify sellers that may be erecting 

barriers to entry. We will revise section 

35.42 of our regulations to reflect this 

site acquisition change to the change in 

status reporting requirement. 

20. Separate and apart from the above 

reporting requirement, and in order to 

address our concern that Sellers may 

acquire land that is not used for the 

development of new generation 

capacity, and that is instead acquired for 

the purpose of preventing new 

generation capacity from being 

developed on that land, a Seller must 

also report any land it has acquired, 

taken a leasehold interest in, obtained 

an option to purchase or lease, or 

entered into an exclusivity or other 

arrangement to acquire for the purpose 

of developing a generation site and for 

which site control has not yet been 

demonstrated (as discussed above) 

during the prior three years (triggering 

event), and for which the potential 

number of megawatts that are 

reasonably commercially feasible on the 

land for new generation capacity 

development is equal to 100 megawatts 

or more. A Seller must report each such 

triggering event in a single report by 

January 1 of the year following the 

calendar year in which the triggering 

event occurred. Thus, for example, if a 

Seller acquires land for new generation 

capacity development in January 2009, 

and additional land in March 2009 and 

it has not demonstrated site control for 

generation projects on that land (as 

described above) as of January and 

March 2012, respectively, then such 

Seller must file a change in status report 

notifying the Commission of both 

acquisitions by January 1, 2013. The 

information that must be provided and 

the aggregation of the maximum 

potential number of megawatts by 

relevant geographic market is the same 

as required in the quarterly reports, as 

described above. We will revise section 

35.42 of our regulations to reflect this 

additional change to the change in 

status reporting requirement. 

21. Finally, for acquired, leased or 

optioned land lacking site control that 

have already been held for three years 

or more prior to the effective date of this 

order, a Seller must report the required 

information by January 1, 2010, unless 

this information has been previously 

provided to the Commission. 

22. We believe that our revision to 

this requirement strikes a balance by 

addressing American Wind’s concern 

regarding the burden of the existing 

requirement and its concern that 

commercially sensitive information 

about sites for wind generation 

development will be made public, and 

by also providing the Commission with 

the information necessary to evaluate a 

seller’s ability to erect barriers to entry. 

In particular, permitting the information 

on sites for new generation capacity 

development to be provided on an 

aggregate basis for each relevant 

geographic market reduces any potential 

competitive harm that could result from 

reporting the location of the sites (since 

reporting will be on an aggregate basis), 

and also enables the Commission, 

which evaluates vertical market power 

by examining the relevant geographic 

market in which a seller is located, to 

obtain the information it needs to 

evaluate a seller’s ability to exercise 

market power in a particular relevant 

geographic market. Requiring quarterly 

(and yearly, as necessary) reporting of 

sites acquired for new generation 

capacity development also reduces the 

administrative burden on sellers, which 

previously were required to report the 

acquisition of sites within 30 days of the 

acquisition. In addition, requiring 

reporting on a quarterly basis (and 

yearly, as necessary) will likely reduce 

any potential competitive harm that 

could result from the disclosure of the 

nominal information regarding the 

location of the site or sites for new 

generation capacity development. 

Further, in their applications for marketbased rate authority and their updated 

market power analyses, sellers are 

obligated to make an affirmative 

statement that they have not erected 

barriers to entry into the relevant market 

and will not erect barriers to entry into 


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36Order No. 697, FERC Stats. & Regs. ¶ 31,252 at 

P 447. 

37 Id. P 817 (citing North American Electric 

Reliability Corporation, Glossary of Terms Used in 

Reliability Standards at 2 (2007), available at 

ftp://www.nerc.com/pub/sys/all_updl/standards/rs/ 

Glossary_02May07.pdf)). 

38 Id. P 830. 

39Order No. 697–A, FERC Stats. & Regs. ¶ 31,268 

at P 333. 

40 Id. P 334. 

41 Id. n.464. 

42 Id. P 335. 

43 Id. P 336. 

44Order No. 697–B, FERC Stats. & Regs. ¶ 31,285 

at P 77 (citing Order No. 697–A, FERC Stats. & Regs. 

¶ 31,268 at P 336). 45E.ON January 21, 2009 Rehearing Request at 3, 

5. 

46 Id. at 8. 

the relevant market. This continuing 

obligation provides assurance to the 

Commission that a seller is not erecting 

barriers to entry.36

B. Mitigation 

Protecting Mitigated Markets 

Sales at the Metered Boundary 

Background 

23. In Order No. 697, the Commission 

stated that it would continue to apply 

mitigation to all sales in the balancing 

authority area in which a seller is found, 

or presumed, to have market power. 

However, the Commission said it would 

allow mitigated sellers to make marketbased rate sales at the metered boundary 

between a balancing authority area in 

which a seller is found, or presumed, to 

have market power and a balancing 

authority area in which the seller has 

market-based rate authority, under 

certain circumstances.37 The 

Commission also adopted a requirement 

that mitigated sellers wishing to make 

market-based rate sales at the metered 

boundary between a balancing authority 

area in which the seller was found, or 

presumed, to have market power and a 

balancing authority area in which the 

seller has market-based rate authority 

maintain sufficient documentation and 

use a specific tariff provision for such 

sales.38

24. On rehearing in Order No. 697–A, 

the Commission revised the tariff 

language governing market-based rate 

sales at the metered boundary to 

conform with the discussion in the 

December 14 Clarification Order 

regarding use of the term ‘‘mitigated 

market.’’ The Commission stated that, as 

explained in the December 14 

Clarification Order, ‘‘balancing 

authority area in which a seller is found, 

or presumed, to have market power’’ is 

a more accurate way to describe the area 

in which a seller is mitigated.39

25. In addition, after considering 

comments regarding the difficulty of 

determining and documenting intent, 

the Commission decided in Order No. 

697–A to eliminate the intent element of 

the tariff provision, which stated that 

‘‘any power sold hereunder is not 

intended to serve load in the seller’s 

mitigated market.’’ Because the 

Commission eliminated the seller’s 

intent requirement, it modified the tariff 

provision to require that ‘‘the mitigated 

seller and its affiliates do not sell the 

same power back into the balancing 

authority area where the seller is 

mitigated.’’ 40 In this regard, the 

Commission noted that ‘‘[t]o provide 

additional regulatory certainty for 

mitigated sellers, the Commission 

clarified that once the power has been 

sold at the metered boundary at marketbased rates, the mitigated seller and its 

affiliates may not sell that same power 

back into the mitigated balancing 

authority area, whether at cost-based or 

market-based rates.’’ 41 The Commission 

also stated that because it was 

eliminating the intent requirement, it 

need not address issues raised regarding 

documentation necessary to 

demonstrate the mitigated seller’s 

intent. 

26. Further, in response to a request 

for clarification submitted by the 

Pinnacle West Companies (Pinnacle), 

the Commission also clarified in Order 

No. 697–A that mitigated sellers and 

their affiliates are prohibited from 

selling power at market-based rates in 

the balancing authority area in which a 

seller is found, or presumed, to have 

market power.42 Accordingly, the 

Commission clarified that an affiliate of 

a mitigated seller is prohibited from 

selling power that was purchased at a 

market-based rate at the metered 

boundary back into the balancing 

authority area in which the seller has 

been found, or presumed, to have 

market power. The Commission stated 

that to the extent that the mitigated 

seller or its affiliates believe that it is 

not practical to track such power, they 

can either choose to make no marketbased rate sales at the metered boundary 

or limit such sales to sales to end users 

of the power, thereby eliminating the 

danger that they will violate their tariff 

by re-selling the power back into a 

balancing authority in which they are 

mitigated.43

27. In Order No. 697–B, in response 

to the rehearing request of E.ON U.S. 

LLC (E.ON), the Commission explained 

that it appreciated concerns regarding 

the difficulty of defining the term ‘‘same 

power.’’ For this reason, the 

Commission revised the tariff provision 

for market-based rate sales at the 

metered boundary, which included 

revising the provision stating that the 

‘‘Seller and its affiliates do not sell the 

same power back into the balancing 

authority area where the seller is 

mitigated,’’ to state that ‘‘if the Seller 

wants to sell at the metered boundary of 

a mitigated balancing authority area at 

market-based rates, then neither it nor 

its affiliates can sell into that mitigated 

balancing authority area from the 

outside.’’ The Commission noted that 

this revised tariff language will prevent 

a mitigated seller making market-based 

rate sales at the metered boundary from 

selling power into the mitigated market 

through its affiliates. It also explained 

that sellers may choose to make no 

market-based rate sales at the metered 

boundary, or to limit such sales to end 

users of the power, thereby eliminating 

the danger they will violate their tariff 

by re-selling power back into a 

balancing authority in which they are 

mitigated.44

Requests for Rehearing 

28. On rehearing of Order No. 697–B, 

E.ON again takes issue with the 

mitigated sales tariff provision, arguing 

that the Commission erred in revising 

the mitigated sales tariff provision in 

Order No. 697–B. E.ON contends that 

the revised tariff provision is overbroad 

and prohibits legitimate transactions. It 

argues that the tariff provision should be 

revised to state that ‘‘(ii) if the Seller 

sells at the metered boundary of a 

mitigated balancing authority area at 

market-based rates, then neither it nor 

its affiliates can sell into that mitigated 

balancing authority area from the 

outside at the same border for delivery 

at the same time except pursuant to 

long-term (one-year or longer) 

agreements or as a result of changed 

circumstances.’’ 45 E.ON argues that, as 

revised in Order No. 697–B, the tariff 

provision governing mitigated sales 

does not expressly state that a border 

sale need actually occur. E.ON suggests 

that the Commission should change the 

words ‘‘wants to sell’’ to ‘‘sells’’ to 

eliminate any risk of misinterpretation. 

In support of its proposal, E.ON argues 

that the mitigated sales tariff provision 

should contain a ‘‘temporal limitation’’ 

so that it cannot be read to prohibit a 

mitigated seller or its affiliates from ever 

selling from the outside into the 

mitigated balancing authority area. 

E.ON believes that the Commission 

intended only to stop the ‘‘looping’’ of 

power in a manner that circumvents the 

mitigation imposed on an entity.46

29. E.ON also argues that the 

mitigated sales tariff provision should 

contain an exemption for retail or 


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47 Id. at 10. 

48 Id. at 12. 

49 Id. at 13. 

50Pinnacle January 21, 2009 Rehearing Request at 

5. 

51 Id. at 3–4. 

52 Id. at 4. 

53MidAmerican January 21, 2009 Rehearing 

Request at 6. 

54 Id. at 7–8. 

55 Id. at 8. 

56 Xcel January 21, 2009 Request for Clarification 

at 7. 

57 Id. at 5. 

58 Id. at 8. 

59We note that EEI’s request for rehearing of the 

mitigated sales tariff provision is out-of-time insofar 

as EEI did not raise issues concerning mitigated 

sales at the metered boundary on rehearing of Order 

wholesale cost-based requirements 

contracts into the mitigated balancing 

authority area from the outside so that 

long-term purchases from outside a 

mitigated market used to serve retail or 

cost-based wholesale requirements 

customers do not restrict the ability of 

a mitigated seller from making a spot 

‘‘outbound’’ border sale. According to 

E.ON, failure to modify the condition in 

this manner would severely restrict the 

ability of its public utility subsidiaries 

Louisville Gas and Electric Company 

and Kentucky Utilities Company to 

make truly ‘‘outbound’’ off-system sales 

at the border of their control area, 

leading to higher prices.47 E.ON also 

proposes adding language to the 

condition so as to carve out long-term 

agreements of one-year or more in 

duration that provide for the sale of 

power into the mitigated market from 

the outside. E.ON contends that as 

revised in Order No. 697–B, the 

mitigated sales tariff provision could 

prohibit transactions necessitated by 

reserve sharing agreements or changed 

operational circumstances, and could 

have a chilling effect on forward 

contracting by forcing mitigated sellers 

to only transact in real time because of 

their concerns that they may guess 

wrong and need to buy power at the last 

minute if they are short, or sell power 

at the last minute if called upon under 

a reserve sharing agreement.48 In 

addition, E.ON asserts that the revised 

mitigated sales tariff provision could 

prohibit opportunity purchases by 

utilities that seek to reduce the costs of 

serving load.49

30. Pinnacle, too, seeks further 

revision to the mitigated sales tariff 

provision and argues that the 

Commission erred in linking all marketbased rate sales made at the metered 

boundary to all incoming sales into a 

mitigated balancing authority area. 

Pinnacle requests that the Commission 

clarify that making a border sale does 

not prohibit all future sales of a 

mitigated seller or its affiliates from 

entering the mitigated balancing 

authority area. It states that, at a 

minimum, the Commission should 

clarify that it does not intend for the 

revised provision to capture cost-based 

sales into or out of a mitigated balancing 

authority area.50 Pinnacle states that if 

the revised provision is interpreted to 

prohibit any subsequent sales of a 

mitigated seller or its affiliates from 

entering the mitigated balancing 

authority area, this would completely 

preclude the mitigated seller from 

selling into the mitigated balancing 

authority area. Such a result, Pinnacle 

contends, could endanger the stability 

of the Phoenix Valley Load Pocket in 

the event of an emergency,51 and could 

result in Pinnacle violating its mustoffer requirements. Specifically, 

Pinnacle states that if it is not permitted 

to make sales into the mitigated 

balancing authority area, or is 

effectively prohibited from making sales 

at border points, its posting of available 

capacity will be less effective for the 

Southwest in that Pinnacle would have 

to withhold available generation due to 

its inability to make sales in certain 

areas.52

31. MidAmerican Energy Company 

(MidAmerican) and American Electric 

Power Service Corporation (AEP) also 

seek rehearing of the mitigated sales 

tariff provision as revised in Order No. 

697–B. These petitioners argue that the 

Commission erred in adopting an overly 

broad mitigation provision that could 

restrict legitimate transactions. They 

contend that under the tariff provision 

adopted in Order No. 697–B, mitigated 

utilities are presented with three 

alternatives, each of which 

‘‘unnecessarily and unfairly’’ 

disadvantages their customers: (i) 

Decline to make market-based rate sales 

and thereby forego revenues used to 

reduce system costs; (ii) decline to 

import power from ‘‘the outside’’ and 

thereby forego least-cost resources that 

could be used to reliably serve load and 

make sales within the mitigated market; 

or (iii) make sales to customers within 

the mitigated market at prices that may 

not recover incremental costs, thereby 

unfairly subsidizing those 

transactions.53 MidAmerican and AEP 

therefore assert that the Commission 

should rescind Order No. 697–B’s 

revision and revert to the mitigated sales 

tariff provision adopted in Order No. 

697. According to these petitioners, the 

tariff provision adopted in Order No. 

697 captures transactions purposefully 

structured to evade mitigation while 

permitting utilities to continue to 

engage in legitimate transactions from 

the ‘‘outside,’’ even when energy 

scheduled under those transactions 

subsequently is reflected in the price for 

opportunity sales made within the 

balancing authority area.54

32. MidAmerican and AEP argue that 

if the Commission declines to grant 

rehearing, it should clarify that the 

mitigated sales tariff provision applies 

only to short-term purchases made from 

the ‘‘outside’’ by the mitigated seller 

and not to deliveries scheduled from the 

mitigated seller’s own generation 

originating ‘‘outside’’ the mitigated 

balancing authority area or from longterm capacity contracts entered into to 

meet load requirements. These 

petitioners contend that these 

arrangements ‘‘do not involve the 

Commission’s ricochet concern and 

should not be swept within the Order 

No. 697–B mitigation provision.’’ 55

33. Xcel Energy Services Inc. (Xcel) 

requests clarification that the 

prohibition on sales into the mitigated 

balancing authority area does not 

prevent a mitigated seller from engaging 

in a purchase of economy power from 

outside the mitigated balancing 

authority area in order to lower costs for 

serving native load. It argues that 

mitigated sellers that make sales of 

power at border locations may have 

opportunities to enter into legitimate 

economy purchases outside the 

balancing authority area that would 

serve to lower overall generation costs 

to their native load customers. Xcel 

contends that one mitigation option is to 

‘‘track the power from a border sale with 

the possibility of retroactive repricing.’’ 56

34. Xcel requests clarification that 

mitigated sellers are only prohibited 

from making sales into a mitigated 

balancing authority area if the seller is 

simultaneously engaged in a sale at the 

metered boundary.57 In support of this 

request, Xcel argues that during periods 

when the seller is not making sales at 

the border of its mitigated balancing 

authority area, there would be no way 

for the seller or its affiliates to benefit 

from their market power in the 

mitigated balancing authority area 

through a sale that originates outside of 

that mitigated balancing authority 

area.58 Xcel therefore asks for 

clarification that it is permitted to enter 

into a sale at a delivery point located 

outside of the mitigated balancing 

authority area to a counterparty within 

the balancing authority area. 

35. The Edison Electric Institute (EEI) 

likewise seeks rehearing of the mitigated 

sales tariff provision as set forth in 

Order No. 697–B.59 EEI contends that 


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Federal Register / Vol. 74, No. 123 / Monday, June 29, 2009 / Rules and Regulations 30931 

Nos. 697 and 697–A and appears to be an attempt 

to re-litigate the determinations made by the 

Commission in those orders. 

60EEI January 22, 2009 Corrected Rehearing 

Request at 5–6. 

61 Id. at 3. 

62 Id. at 8–9. 

63 Id. at 9. 

64 In its request for an extension of time to comply 

with the revised mitigated sales tariff provision, 

Tampa Electric states that it supports EEI’s request 

for rehearing. On January 28, 2009, the Commission 

issued an order granting Tampa Electric’s request 

for an extension of time to comply with the tariff 

provision on mitigated sales at the metered 

boundary as revised in Order No. 697–B until such 

time as the Commission issues an order on 

rehearing of Order No. 697–B. Order Granting 

Extension of Time to Comply, 126 FERC ¶ 61,072; 

see supra P 6. 

65NRECA and APPA January 27, 2009 Answer at 

1–2. 

66 Id. at 3–4. 

67 5 U.S.C. 705 (2006). 

68Pinnacle West Capital Corp., 115 FERC 

¶ 61,064, at P 8 (2006) (citing CMS Midland, Inc., 

Midland Cogeneration Venture Limited Partnership, 

56 FERC ¶ 61,177, at 61,361 (1991), aff’d sub nom. 

Michigan Municipal Cooperative Group v. FERC, 

990 F.2d 1377 (D.C. Cir. 1993), cert. denied, 510 

U.S. 990 (1993)). 

69 Id. 

70 Id. 

71CMS Midland, Inc., Midland Cogeneration 

Venture Limited Partnership, Midland Cogeneration 

Venture Limited Partnership, 56 FERC ¶ 61,177, at 

61,631 (1991) (footnote omitted). 

72Pinnacle West Capital Corp., 115 FERC 

¶ 61,064, at P 8 (2006) (citing The Montana Power 

Company, Confederated Salish and Kootenai Tribes 

of the Flathead Reservation, 85 FERC ¶ 61,400, at 

62,535 (1998)). 

the revised provision will unnecessarily 

constrain sales by mitigated sellers and 

their affiliates to the detriment of 

customers in all markets. EEI argues that 

as revised in Order No. 697–B, the 

mitigated sales tariff provision could be 

interpreted to prohibit all sales by 

mitigated sellers and their affiliates into 

a mitigated market from the outside if 

the sellers opt to engage in one or more 

metered boundary sales. EEI asserts that 

this interpretation would completely 

exclude all sales into the mitigated 

balancing authority area by a mitigated 

seller and its affiliates, removing these 

sellers from the marketplace and 

exacerbating any potential imbalance of 

market power in the mitigated balancing 

authority area.60 EEI contends that the 

revised tariff language could be 

interpreted to violate certain must-offer 

and load-following requirements. 

36. EEI argues that the Commission 

should return to the intent-based 

concept adopted in Order No. 697, 

while also identifying five types of 

transactions that would be permitted 

without first needing to demonstrate 

intent even if a mitigated seller does 

engage in market-based rate sales at the 

metered boundary.61 EEI asserts that the 

following five types of transactions 

should be permitted without first 

needing to demonstrate intent, even if a 

mitigated seller does engage in marketbased rate border sales: (1) Sales at 

‘‘liquid trading hubs’’ or into ISO and 

RTO markets outside of the seller’s 

mitigated market; (2) cost-based sales in 

which title transfers within the 

mitigated market (whether they are 

sourced and sunk in the mitigated 

market, are sourced ‘‘into’’ the mitigated 

market from the outside by the seller or 

its affiliates, or are wheeled ‘‘out of’’ the 

mitigated market by a purchaser); (3) 

sales to load-serving entities such as 

investor-owned utilities, municipalities, 

and cooperatives that serve retail load 

outside the mitigated market, even if 

those entities may at times need to sell 

power back into the mitigated market if 

their supply is too great (since the 

timing and occurrence of such excesspower sales back into the mitigated 

market will be beyond the control of the 

mitigated seller); (4) other types of 

transactions that are independent of the 

border sales, such as sales of blocks of 

power to be delivered at dates and times 

other than the border sale block of 

power, power made available under 

must-offer requirements, and loadfollowing power; and (5) to bolster 

reliability, the Commission should 

clarify that the border sale constraints 

do not require a mitigated seller or its 

affiliates, which otherwise would be 

precluded from selling power into the 

mitigated area from the outside, to 

withhold making those sales during 

times at which the seller or affiliates are 

called on to act to maintain system 

reliability. EEI argues that at a 

minimum, the Commission should 

clarify that the border sales constraints 

will not prevent emergency sales, sales 

that are required to maintain reserve 

levels or to comply with system 

redispatch obligations, or sales that are 

otherwise authorized by the 

Commission either generically or caseby-case.62

37. EEI also includes an expedited 

motion for partial stay in its rehearing 

request in which it asks that the 

Commission stay the effectiveness of the 

border sales constraints set forth in 

Order Nos. 697, 697–A and 697–B until 

at least 30 days after the Commission 

has acted on the merits of EEI’s request 

for rehearing.63

38. Separately, Tampa Electric 

submitted a motion for an extension of 

time to comply with the revised 

mitigated sales tariff provision set forth 

in Order No. 697–B. Tampa Electric 

requests that the Commission defer the 

effective date of the modified language 

governing mitigated sales at the metered 

boundary pending Commission action 

on requests for rehearing of Order No. 

697–B on this issue.64 Tampa Electric 

also states that it supports EEI’s request 

for rehearing. 

39. On January 27, 2009, the National 

Rural Electric Cooperative Association 

(NRECA) and the American Public 

Power Association (APPA) filed an 

answer in response to EEI’s motion for 

partial stay. NRECA and APPA argue 

that EEI’s motion for partial stay should 

be denied because EEI does not 

demonstrate that a stay is appropriate. 

They argue that EEI does not specify any 

irreparable injury that EEI or its member 

companies will suffer absent a stay, 

does not address whether the requested 

stay would substantially harm other 

parties, and does not show that the stay 

is in the public interest. They point out 

that EEI’s request for rehearing is the 

third time in this proceeding that sellers 

have requested the Commission to 

modify the restrictions on market-based 

sale at the metered boundaries of 

mitigated balancing authority areas.65

NRECA and APPA also argue that 

ending all restrictions on market based 

rate sales at the metered boundary of 

balancing authority areas in which a 

seller is mitigated, even temporarily, 

would harm wholesale markets and 

customers.66

Commission Determination 

Procedural Issues 

40. We find that EEI does not provide 

the required justification for a stay of 

the mitigated sales tariff provision. 

Under section 705 of the Administrative 

Procedure Act (APA), the Commission 

may stay its action when it finds that 

‘‘justice so requires.’’ 67 In addressing 

motions for stay, the Commission 

considers: (1) Whether the moving party 

will suffer irreparable injury without a 

stay; (2) whether issuing a stay will 

substantially harm other parties; and (3) 

whether a stay is in the public 

interest.68 The Commission’s general 

policy is to refrain from granting a stay 

of its orders, to assure definiteness and 

finality in Commission proceedings.69

The key element in the inquiry is 

irreparable injury to the moving party.70

If a party is unable to demonstrate that 

it will suffer irreparable harm absent a 

stay, we need not examine the other 

factors.71 However, the Commission 

may examine the other factors where 

appropriate.72

41. EEI’s request for stay does not 

address whether it will suffer 

irreparable injury without a stay of the 

mitigated sales tariff provision, and also 

does not address whether issuing a stay 


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30932 Federal Register / Vol. 74, No. 123 / Monday, June 29, 2009 / Rules and Regulations 

73EEI January 21, 2009 Rehearing Request at 9. 

74 In Wisconsin Gas v. FERC, 758 F.2d 669, 674 

(D.C. Cir. 1985) the court stated that, to meet the 

irreparable injury test for granting a stay: 

‘‘First, the injury must be both certain and great; 

it must be actual and not theoretical. Injunctive 

relief ‘‘will not be granted against something merely 

feared as liable to occur at some indefinite time,’’ 

Connecticut v. Massachusetts, 282 U.S. 660, 674, 75 

L. Ed. 602, 51 S. Ct. 286 (1931); the party seeking 

injunctive relief must show that ‘‘the injury 

complained of [is] of such imminence that there is 

a ‘clear and present’ need for equitable relief to 

prevent irreparable harm.’’ Ashland Oil, Inc. v. FTC, 

409 F. Supp. 297, 307 (D.D.C.), aff’d, 179 U.S. App. 

D.C. 22, 548 F.2d 977 (D.C. Cir. 1976) (citations and 

internal quotations omitted).’’ 

75 In granting Tampa Electric’s request for 

extension of time to comply with the tariff 

provision on mitigated sales at the metered 

boundary as revised in Order No. 697–B, the 

Commission clarified that affected entities must 

continue to comply with the mitigated sales tariff 

provision adopted in Order No. 697–A until such 

time as the Commission acts on the requests for 

rehearing of Order No. 697–B. Order Granting 

Extension of Time to Comply, 126 FERC ¶ 61,072. 

76Order No. 697–B, FERC Stats. & Regs. ¶ 31,285 

at Appendix C. 

77 Id. P 66–67, 69; E.ON May 21, 2008 Rehearing 

Request at 12–14, Pinnacle May 21, 2008 Rehearing 

Request at 4–6. 

78Order No. 697, FERC Stats. & Regs. ¶ 31,252 at 

P 819. The Commission also stated ‘‘While we 

generally agree that it is desirable to allow marketbased rate sales into markets where the seller has 

not been found to have market power, we do not 

agree that it is reasonable to allow a mitigated seller 

to make market-based rate sales anywhere within a 

mitigated market. It is unrealistic to believe that 

sales made anywhere in a balancing authority area 

can be traced to ensure that no improper sales are 

taking place. Such an approach would also place 

customers and competitors at an unreasonable 

disadvantage because the mitigated seller has 

dominance in the very market in which it is making 

market-based rate sales.’’ Id.; see also Westar 

Energy, Inc. v. FERC, No. 08–1196, slip op. at 5 

(D.C. Cir. June 12, 2009) (stating that in Order No. 

697 the Commission concluded that ‘‘it ‘is 

unrealistic to believe that’ such sales ‘can be traced 

to ensure that no improper sales are taking place.’ ’’) 

(citation omitted); Order No. 697–A, FERC Stats. & 

Regs. ¶ 31,268 at P 321. 

79See Order No. 697–A, FERC Stats. & Regs. 

¶ 31,268 at P 335. 

80 Id. P 336. 

81As the Court of Appeals for the District of 

Columbia Circuit recently confirmed, ‘‘a wholesaler 

* * * can easily comply with the [Commission] 

rule and still make sales into other regions at 

market-based rates. A wholesaler simply needs to 

ensure that title passes at or beyond the metered 

boundary between the mitigated and non-mitigated 

areas, instead of inside a mitigated area.’’ Westar 

Energy, Inc. v. FERC, No. 08–1196, slip op. at 5 

(D.C. Cir. June 12, 2009) (citation omitted). 

will substantially harm other parties or 

whether a stay is in the public interest. 

Rather, EEI’s request for stay consists 

only of the following statement: ‘‘[g]iven 

the serious, negative potential effects of 

the border sales related constraints set 

out in Orders No. 697, 697–A, and 697– 

B on market participants and customers 

in mitigated and non-mitigated markets, 

EEI requests that the Commission stay 

the effectiveness of those constraints 

until at least 30 days after the 

Commission has acted on the merits of 

EEI’s request for rehearing.’’ 73 This 

claim is too broad and speculative to 

justify the granting of injunctive relief.74

We also note that EEI did not raise 

issues concerning mitigated sales at the 

metered boundary on rehearing of Order 

Nos. 697 and 697–A. Because EEI fails 

to provide the required justification for 

a stay of the mitigated sales tariff 

provision, EEI’s motion for a partial stay 

is denied.75

Substantive Issues 

42. We deny the requests for rehearing 

concerning the mitigated sales tariff 

provision. However, we agree with 

E.ON that the tariff provision should be 

revised to state ‘‘if the Seller sells’’ 

instead of ‘‘if the Seller wants to sell 

* * *.’’ We clarify that it is not the 

seller’s intent, but rather the seller’s 

action that triggers the limitation set 

forth in the mitigated sales tariff 

provision. We affirm our determination 

to revise the mitigated sales tariff 

provision in Order No. 697–B in order 

to ensure that a mitigated seller making 

market-based rate sales at the metered 

boundary does not sell power into the 

mitigated market either directly or 

through its affiliates. Thus, we will 

revise the mitigated sales tariff 

provision to provide that ‘‘if the Seller 

sells at the metered boundary of a 

mitigated balancing authority area at 

market-based rates, then neither it nor 

its affiliates can sell into that mitigated 

balancing authority area from the 

outside.’’ 76 Petitioners’ arguments on 

rehearing of Order No. 697–A indicated 

that they cannot guarantee that sales at 

the metered boundary ultimately serve 

load in a competitive market beyond the 

balancing authority area where the 

seller is mitigated.77 As explained in 

Order No. 697, ‘‘[a]llowing market-based 

rate sales by a seller that has been found 

to have market power, or has so 

conceded, in the very market in which 

market power is a concern is 

inconsistent with the Commission’s 

responsibility under the FPA to ensure 

that rates are just and reasonable and 

not unduly discriminatory.’’ 78

Accordingly, mitigated sellers and their 

affiliates are prohibited from selling 

power at market-based rates in the 

balancing authority area in which the 

seller is found, or presumed, to have 

market power.79 Thus, we affirm the 

Commission’s determination to revise 

the mitigated sales tariff provision in 

Order No. 697–B in order to ensure that 

a mitigated seller making market-based 

rate sales at the metered boundary does 

not sell power into the mitigated market 

either directly or through its affiliates. 

We also reiterate that mitigated sellers 

may choose to make no market-based 

rates sales at the metered boundary, or 

to limit such sales to end users, thereby 

eliminating the risk that they will re-sell 

power back to the balancing authority 

area where they are mitigated.80

43. With respect to petitioners’ 

arguments that the mitigated sales tariff 

provision adopted in Order No. 697–B 

interferes with must-offer and reliability 

requirements, reserve sharing 

agreements, and cost-based requirement 

contracts, we note that if a mitigated 

seller does not make market-based rate 

sales at the border, either that mitigated 

seller or its affiliates may make sales at 

cost-based rates into the balancing 

authority area in which it is mitigated. 

A mitigated seller can perform each of 

the above-enumerated functions either 

by selling at cost-based rates within its 

restricted balancing authority area, 

selling at cost-based rates at the metered 

boundary of its restricted balancing 

authority area, or by selling at marketbased rates at the metered boundary as 

long as it makes sure that title to the 

power sold transfers at or beyond the 

metered boundary. Moreover, we note 

that our restrictions on sales at the 

border only apply to new agreements 

that the seller enters into prospective 

from the date that Order No. 697–B 

became effective. No existing 

agreements are upset or need to be 

revised in any way provided that the 

seller abides by our restrictions on any 

new agreements that it enters into 

prospectively. Of the rehearing requests 

that have been filed in this proceeding 

on this issue, none have identified in 

this rehearing why it is burdensome or 

unreasonably costly for sellers to enter 

into new power sales agreements where 

title transfers at or beyond the metered 

boundary between the mitigated and 

non-mitigated balancing authority 

areas.81 Given that many petitioners 

have acknowledged that the approaches 

in Order No. 697 and 697–A would be 

extremely difficult to enforce because 

even the sellers themselves cannot 

guarantee that power sold on the seller’s 

side of the metered boundary will not 

somehow find its way back into the 

restricted market, we do not believe it 

is appropriate to return to a rule that is 

difficult not only for sellers to comply 

with but also for the Commission to 

enforce. Such an impracticable rule will 

not enable the Commission to ensure 

that market power is not being exercised 

in the restricted market. 

44. With respect to petitioners’ 

requests that the Commission return to 

the intent-based concept first used in 

Order No. 697, we note that in Order 


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Federal Register / Vol. 74, No. 123 / Monday, June 29, 2009 / Rules and Regulations 30933 

82Order No. 697–A, FERC Stats. & Regs. ¶ 31,268 

at P 334. 

83The revised tariff language set forth in the 

paragraph above is effective as of the effective date 

of Order No. 697–A. 

84See Order No. 697, FERC Stats. & Regs. ¶ 

31,252 at Appendix D. The regions include the 

Northeast, Southeast, Central, Southwest Power 

Pool, Southwest, and Northwest. 85Order No. 697–A, FERC Stats. & Regs. ¶ 31,268 

at P 374 (citing December 14 Clarification Order, 

121 FERC ¶ 61,260 at P 9) (emphasis in original). 

86 Id. 

87These entities were included in the Regional 

Market Power Update Schedule provided in 

Appendix D to Order No. 697. 

88 5 CFR 1320.11. 

No. 697–A, the Commission revised the 

mitigated sales tariff provision to 

remove the intent element in response 

to petitioners’ requests, including 

Pinnacle, who questioned how the 

Commission could ensure that a 

mitigated seller knows what an 

unaffiliated buyer intends to do with 

power, and complained that it is 

difficult and administratively 

burdensome to determine and document 

intent.82 In Order No. 697–A, the 

Commission agreed with petitioners that 

it would be difficult to determine and 

document intent, and therefore decided 

to eliminate the intent element of the 

tariff provision. On rehearing of Order 

No. 697–B, petitioners have not 

provided any new arguments that 

persuade us that returning to the intentbased concept first used in Order No. 

697 will not present the same problems 

regarding the ability to determine and 

document intent. 

45. In addition, the mitigated sales 

tariff provision in Appendix C of Order 

Nos. 697–A and 697–B inadvertently 

omitted language that was included in 

the provision adopted in Order No. 697. 

Accordingly, we will revise the tariff 

provision for market-based rate sales at 

the metered boundary as follows (bold 

font indicates new text): 

Sales of energy and capacity are 

permissible under this tariff in all balancing 

authority areas where the Seller has been 

granted market-based rate authority. Sales of 

energy and capacity under this tariff are also 

permissible at the metered boundary between 

the Seller’s mitigated balancing authority 

area and a balancing authority area where the 

Seller has been granted market-based rate 

authority provided: (i) Legal title of the 

power sold transfers at the metered boundary 

of the balancing authority area where the 

seller has market-based rate authority; and 

(ii) if the Seller sells at the metered boundary 

of a mitigated balancing authority area at 

market-based rates, then neither it nor its 

affiliates can sell into that mitigated 

balancing authority area from the outside. 

Seller must retain, for a period of five years 

from the date of the sale, all data and 

information related to the sale that 

demonstrates compliance with items (i) and 

(ii) above. 

46. Sellers that have already adopted 

the tariff language prescribed in Order 

No. 697–B are directed to revise the 

provision in accordance with this order 

on the next occasion when they 

otherwise would be required to file 

revised tariff sheets with the 

Commission, a change in status filing, or 

triennial review.83

C. Implementation Process 

Clarifications on Implementation 

Process 

Background 

47. In Order No. 697, to ensure greater 

consistency in the data used to evaluate 

Category 2 sellers, the Commission 

modified the timing for the submission 

of updated market power analyses. 

Order No. 697 requires analyses to be 

filed for each seller’s region on a predetermined schedule, rotating by 

geographic region where two regions are 

reviewed each year, with the cycle 

repeating every three years.84 In Order 

No. 697–A, the Commission provided 

additional guidance regarding the 

implementation process. In particular, it 

explained that in the December 14 

Clarification Order, it clarified that 

‘‘transmission-owning utilities with 

market-based rate authority and their 

affiliates with market-based rate 

authority are the entities required to file 

their updated market power analyses 

first in each region.’’ 85 Accordingly, in 

Order No. 697–A, the Commission 

revised Appendix D to make clear that 

transmission owners and their affiliates 

have earlier filing periods than other 

entities required to file in each region.86

48. Upon further review of the 

Schedule for All Other Entities provided 

at Appendix D–2 to Order No. 697–A, 

it has come to our attention that the list 

of entities required to file updated 

market power analyses omits the 2010 

filing dates for Southwest and 

Northwest non-transmission owning 

entities.87 Accordingly, we will revise 

Appendix D to add the following: 

Appendix D—2 

SCHEDULE FOR ALL OTHER ENTITIES

Entities required to file Filing period 

(anytime during the month) Study period 

Others in Southwest that did not file in December and have not been 

found to be Category 1 sellers.

June 2010 ........................................ Dec. 1, 2009–Nov. 30, 2010. 

Others in Northwest that did not file in June and have not been found to 

be Category 1 sellers.

December 2010 ................................ Dec. 1, 2009–Nov. 30, 2010. 

IV. Information Collection Statement 

49. The Office of Management and 

Budget (OMB) regulations require that 

OMB approve certain information 

collection requirements imposed by an 

agency.88 The Final Rule’s revisions to 

the information collection requirements 

for market-based rate sellers were 

approved under OMB Control No. 1902– 

0234. While this order clarifies aspects 

of the existing information collection 

requirements for the market-based rate 

program, it does not add to these 

requirements. Accordingly, a copy of 

this order will be sent to OMB for 

informational purposes only. 

V. Document Availability 

50. In addition to publishing the full 

text of this document in the Federal 

Register, the Commission provides all 

interested persons an opportunity to 

view and/or print the contents of this 

document via the Internet through 

FERC’s Home Page (http://www.ferc.gov) 

and in FERC’s Public Reference Room 

during normal business hours (8:30 a.m. 

to 5 p.m. Eastern time) at 888 First 

Street, NE., Room 2A, Washington, DC 

20426. 

51. From FERC’s Home Page on the 

Internet, this information is available on 

eLibrary. The full text of this document 

is available on eLibrary in PDF and 

Microsoft Word format for viewing, 

printing, and/or downloading. To access 

this document in eLibrary, type the 

docket number excluding the last three 

digits of this document in the docket 

number field. 

52. User assistance is available for 

eLibrary and the FERC’s Web site during 


cprice-sewell on PRODPC61 with RULES
30934 Federal Register / Vol. 74, No. 123 / Monday, June 29, 2009 / Rules and Regulations 

normal business hours from FERC 

Online Support at 202–502–6652 (toll 

free at 1–866–208–3676) or e-mail at 

ferconlinesupport@ferc.gov, or the 

Public Reference Room at (202) 502– 

8371, TTY (202) 502–8659. E-mail the 

Public Reference Room at 

public.referenceroom@ferc.gov. 

VI. Effective Date 

53. Changes adopted in this order on 

rehearing will become effective July 29, 

2009. 

List of Subjects in 18 CFR Part 35 

Electric power rates, Electric utilities, 

Reporting and recordkeeping 

requirements by the Commission. 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

■ In consideration of the foregoing, the 

Commission amends part 35 Chapter I, 

Title 18, Code of Federal Regulations, as 

follows: 

PART 35—FILING OF RATE 

SCHEDULES AND TARIFFS 

■ 1. The authority citation for part 35 

continues to read as follows: 

Authority: 16 U.S.C. 791a–825r, 2601– 

2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352. 

■ 2. Section 35.42 is revised to read as 

follows: 

§ 35.42 Change in status reporting 

requirement. 

(a) As a condition of obtaining and 

retaining market-based rate authority, a 

Seller must timely report to the 

Commission any change in status that 

would reflect a departure from the 

characteristics the Commission relied 

upon in granting market-based rate 

authority. A change in status includes, 

but is not limited to, the following: 

(1) Ownership or control of generation 

capacity that results in net increases of 

100 MW or more, or of inputs to electric 

power production, or ownership, 

operation or control of transmission 

facilities, or 

(2) Affiliation with any entity not 

disclosed in the application for marketbased rate authority that owns or 

controls generation facilities or inputs to 

electric power production, affiliation 

with any entity not disclosed in the 

application for market-based rate 

authority that owns, operates or controls 

transmission facilities, or affiliation 

with any entity that has a franchised 

service area. 

(b) Any change in status subject to 

paragraph (a) of this section, other than 

a change in status submitted to report 

the acquisition of control of a site or 

sites for new generation capacity 

development, must be filed no later than 

30 days after the change in status 

occurs. Power sales contracts with 

future delivery are reportable 30 days 

after the physical delivery has begun. 

Failure to timely file a change in status 

report constitutes a tariff violation. 

(c) When submitting a change in 

status notification regarding a change 

that impacts the pertinent assets held by 

a Seller or its affiliates with marketbased rate authorization, a Seller must 

include an appendix of assets in the 

form provided in Appendix B of this 

subpart. 

(d) A Seller must report on a quarterly 

basis the acquisition of control of a site 

or sites for new generation capacity 

development for which site control has 

been demonstrated in the 

interconnection process and for which 

the potential number of megawatts that 

are reasonably commercially feasible on 

the site or sites for new generation 

capacity development is equal to 100 

megawatts or more. If a Seller elects to 

make a monetary deposit so that it may 

demonstrate site control at a later time 

in the interconnection process, the 

monetary deposit will trigger the 

quarterly reporting requirement instead 

of the demonstration of site control. A 

notification of change in status that is 

submitted to report the acquisition of 

control of a site or sites for new 

generation capacity development must 

include: 

(1) The number of sites acquired; 

(2) The relevant geographic market in 

which the sites are located; and 

(3) The maximum potential number of 

megawatts (MW) that are reasonably 

commercially feasible on the sites 

reported. 

(e) A Seller must report to the 

Commission any land it has acquired, 

taken a leasehold interest in, obtained 

an option to purchase or lease, or 

entered into an exclusivity or other 

arrangement to acquire for new 

generation capacity development and 

for which site control has not yet been 

demonstrated during the prior three 

years (triggering event), and for which 

the potential number of megawatts that 

are reasonably commercially feasible on 

the land for new generation capacity 

development is equal to 100 megawatts 

or more. A Seller must report each such 

triggering event in a single report by 

January 1 of the year following the 

calendar year in which the triggering 

event occurred. The information that 

must be provided and the aggregation of 

the maximum potential number of 

megawatts by relevant geographic 

market is the same as required in the 

quarterly reports, as described in 

paragraph (d) of this section. 

(f) For the purposes of paragraph (d) 

of this section, ‘‘control’’ shall mean 

‘‘site control’’ as it is defined in the 

Standard Large Generator 

Interconnection Procedures (LGIP). 

Note: The following appendix will not be 

published in the Code of Federal Regulations. 

Appendix C to Order No. 697–C 

* * * * * 

Mitigated Sales 

Sales of energy and capacity are 

permissible under this tariff in all balancing 

authority areas where the Seller has been 

granted market-based rate authority. Sales of 

energy and capacity under this tariff are also 

permissible at the metered boundary between 

the Seller’s mitigated balancing authority 

area and a balancing authority area where the 

Seller has been granted market-based rate 

authority provided: (i) Legal title of the 

power sold transfers at the metered boundary 

of the balancing authority area where the 

seller has market-based rate authority; and 

(ii) if the Seller sells at the metered boundary 

of a mitigated balancing authority area at 

market-based rates, then neither it nor its 

affiliates can sell into that mitigated 

balancing authority area from the outside. 

Seller must retain, for a period of five years 

from the date of the sale, all data and 

information related to the sale that 

demonstrates compliance with items (i) and 

(ii) above. 

* * * * * 

Appendix D–2 

SCHEDULE FOR ALL OTHER ENTITIES

Entities required to file 

Filing period 

(anytime during 

the month) 

Study period 

All others in Northeast that did not file in December including all power 

marketers that sold in the Northeast.

June 2008 ........................................ Dec. 1, 2005–Nov. 30, 2006. 


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Federal Register / Vol. 74, No. 123 / Monday, June 29, 2009 / Rules and Regulations 30935 

SCHEDULE FOR ALL OTHER ENTITIES—Continued 

Entities required to file 

Filing period 

(anytime during 

the month) 

Study period 

All others in Southeast that did not file in June including all power marketers that sold in the Southeast and have not already been found to 

be Category 1 sellers.

December 2008 ................................ Dec. 1, 2005–Nov. 30, 2006. 

All others in Central that did not file in December including all power marketers that sold in the Central and have not already been found to be 

Category 1 sellers.

June 2009 ........................................ Dec. 1, 2006–Nov. 30, 2007. 

All others in SPP that did not file in June including all power marketers 

that sold in SPP and have not already been found to be Category 1 

sellers.

December 2009 ................................ Dec. 1, 2006–Nov. 30, 2007. 

Others in Southwest that did not file in December and have not been 

found to be Category 1 sellers.

June 2010 ........................................ Dec. 1, 2009–Nov. 30, 2010. 

Others in Northwest that did not file in June and have not been found to 

be Category 1 sellers.

December 2010 ................................ Dec. 1, 2009–Nov. 30, 2010. 

Others in Northeast that did not file in December and have not been 

found to be Category 1 sellers.

June 2011 ........................................ Dec. 1, 2008–Nov. 30, 2009. 

Others in Southeast that did not file in June and have not been found to 

be Category 1 sellers.

December 2011 ................................ Dec. 1, 2008–Nov. 30, 2009. 

Others in Central that did not file in December and have not been found 

to be Category 1 sellers.

June 2012 ........................................ Dec. 1, 2009–Nov. 30, 2010. 

Others in SPP that did not file in June and have not been found to be 

Category 1 sellers.

December 2012 ................................ Dec. 1, 2009–Nov. 30, 2010. 

Others in Southwest that did not file in December and have not been 

found to be Category 1 sellers.

June 2013 ........................................ Dec. 1, 2010–Nov. 30, 2011. 

Others in Northwest that did not file in June and have not been found to 

be Category 1 sellers.

December 2013 ................................ Dec. 1, 2010–Nov. 30, 2011. 

[FR Doc. E9–14784 Filed 6–26–09; 8:45 am] 

BILLING CODE 6717–01–P 

DEPARTMENT OF HOMELAND 

SECURITY 

Coast Guard 

33 CFR Part 1 

46 CFR Part 1 

[USCG–2009–0314] 

RIN 1625–ZA22 

Establishment of Suspension and 

Revocation National Center of 

Expertise 

AGENCY: Coast Guard, DHS. 

ACTION: Final rule. 

SUMMARY: This rule makes nonsubstantive, technical changes to Titles 

33 and 46 of the CFR to reflect the 

authorization and establishment of the 

Coast Guard Suspension and Revocation 

National Center of Expertise (S&R 

NCOE). The S&R NCOE is responsible 

for performing suspension and 

revocation functions regarding 

Merchant Mariner Credentials. 

Investigating Officers (IOs), both 

military and civilian employees, are 

assigned to the S&R NCOE for this 

purpose. These changes affect internal 

Coast Guard organization and 

functioning only and will have no 

substantive effect on mariners or other 

members of the public. 

DATES: Effective on June 29, 2009. 

ADDRESSES: Documents mentioned in 

this preamble as being available in the 

docket, are part of USCG–2009–0314 

and are available online by going to 

http://www.regulations.gov, selecting 

the Advanced Docket Search option on 

the right side of the screen, inserting 

USCG–2009–0314 in the Docket ID box, 

pressing Enter, and then clicking on the 

item in the Docket ID column. They are 

also available for inspection or copying 

at two locations: The Docket 

Management Facility (M–30), U.S. 

Department of Transportation, West 

Building Ground Floor, Room W12–140, 

1200 New Jersey Avenue, SE., 

Washington, DC 20590, between 9 a.m. 

and 5 p.m., Monday through Friday, 

except Federal Holidays, and at S&R 

COE co-located with the National 

Maritime Center, 100 Forbes Drive, 

Martinsburg, WV between 9 a.m. and 5 

p.m., Monday through Friday, except 

Federal holidays. 

FOR FURTHER INFORMATION CONTACT: If 

you have questions on this rule, call 

Commander Scott Budka, Supervisor, 

S&R NCOE, U.S. Coast Guard, telephone 

304–433–3744. If you have questions on 

viewing the docket, call Ms. Renee V. 

Wright, Program Manager, Docket 

Operations, telephone or 202–366–9826. 

SUPPLEMENTARY INFORMATION: 

Regulatory Information 

The Coast Guard is issuing this final 

rule without prior notice and 

opportunity to comment pursuant to 

authority under section 4(a) of the 

Administrative Procedure Act (APA) (5 

U.S.C. 553(b)). This provision 

authorizes an agency to issue a rule, 

without prior notice and opportunity to 

comment, when the agency for good 

cause finds that those procedures are 

‘‘impracticable, unnecessary, or contrary 

to the public interest.’’ Under 5 U.S.C. 

553(b)(B), the Coast Guard finds that 

good cause exists for not publishing a 

notice of proposed rulemaking (NPRM) 

with respect to this rule because is 

unnecessary. This rulemaking makes 

amendments to rules regarding agency 

organization and functioning. As such, 

comments are unnecessary because they 

would not change the Coast Guard’s 

internal delegation of authority and 

duty regarding the Suspension and 

Revocation process or provide 

additional expertise regarding Coast 

Guard functioning. 

Under 5 U.S.C. 553(d)(3), the Coast 

Guard finds that good cause exists for 

making this rule effective less than 30 

days after publication in the Federal 

Register because these changes affect 

internal Coast Guard organization and 

functioning only and will have no 

substantive effect on the public. 


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