58720 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 

1While 18 CFR 141.1 nominally refers to ‘‘electric 

utilities,’’ this regulation in fact applies to ‘‘public 

utilities.’’ See 16 U.S.C. 824; accord 18 CFR Part 

101, Definitions 29 and 40. The reference in 18 CFR 

141.1 to ‘‘electric utilities’’ predates the 1978 

addition of separate statutorily defined ‘‘electric 

utilities,’’ see 16 U.S.C. 796(22), when the only 

utilities that were Commission regulated under the 

Federal Power Act were the statutorily-defined 

public utilities, see 16 U.S.C. 824. See, e.g., 18 CFR 

141.1 (1977). 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Parts 41 and 141 

[Docket No. RM08–5–000; Order No. 715] 

Revisions to Forms, Statements and 

Reporting Requirements for Electric 

Utilities and Licensees 

Issued September 19, 2008. 

AGENCY: Federal Energy Regulatory 

Commission. 

ACTION: Final Rule. 

SUMMARY: This Final Rule amends the 

Federal Energy Regulatory 

Commission’s reporting requirements 

for public utilities and licensees to file 

financial forms, reports, and statements, 

including FERC Form No. 1, FERC Form 

No. 1–F, and FERC Form No. 3–Q. 

These changes will improve the forms, 

reports and statements to provide, in 

fuller detail, the information the 

Commission needs to carry out its 

responsibilities under the Federal Power 

Act to ensure that rates remain just and 

reasonable. In addition, the changes will 

help provide public utility customers, 

state commissions, and the public 

information to assess the justness and 

reasonableness of electric rates. 

DATES: Effective Date: This rule will 

become effective January 1, 2009. 

FOR FURTHER INFORMATION CONTACT: 

David Lengenfelder (Technical 

Information), Forms Administration and 

Data Branch, Division of Financial 

Regulation, Office of Enforcement, 

Federal Energy Regulatory Commission, 

888 First Street, NE., Washington, DC 

20426, Telephone: (202) 502–8351, email: david.lengenfelder@ferc.gov, 

Richard M. Wartchow (Legal 

Information), Office of the General 

Counsel, Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, Telephone: 

(202) 502–8744, e-mail: 

richard.wartchow@ferc.gov. 

SUPPLEMENTARY INFORMATION: 

FINAL RULE

Paragraph 

Numbers 

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

II. Background .......................................................................................................................................................................................... 6 

III. Notice of Inquiry ................................................................................................................................................................................. 10 

IV. Notice of Proposed Rulemaking ........................................................................................................................................................ 11 

V. Discussion ........................................................................................................................................................................................... 12 

A. Notice of Inquiry ........................................................................................................................................................................... 12 

B. Notice of Proposed Rulemaking .................................................................................................................................................. 13 

C. Effective Date .............................................................................................................................................................................. 19 

D. Proposed Revisions ..................................................................................................................................................................... 21 

1. Formula Rates ....................................................................................................................................................................... 21 

2. Filing Thresholds for Form 1 ................................................................................................................................................. 51 

3. Affiliate Transactions ............................................................................................................................................................. 56 

4. CPA Certification for a Non-Calendar Fiscal Year ............................................................................................................... 74 

5. ‘‘Other Revenues’’ (Pages 300–301) .................................................................................................................................... 78 

6. Increases to Threshold Reporting Levels ............................................................................................................................. 91 

7. Proposed Technical Corrections ........................................................................................................................................... 94 

8. Additional Technical Revisions ............................................................................................................................................. 98 

E. Miscellaneous .............................................................................................................................................................................. 103 

1. Retaining Form 3–Q .............................................................................................................................................................. 103 

2. Confidentiality Concerns ....................................................................................................................................................... 107 

3. Requests To Reconsider Rejected Revisions ...................................................................................................................... 111 

4. Requests for Additional Cost Data ....................................................................................................................................... 116 

F. Reporting Burden ......................................................................................................................................................................... 121 

VI. Information Collection Statement ....................................................................................................................................................... 129 

VII. Environmental Analysis ..................................................................................................................................................................... 130 

VIII. Regulatory Flexibility Act .................................................................................................................................................................. 131 

IX. Document Availability ......................................................................................................................................................................... 132 

X. Effective Date and Congressional Notification ................................................................................................................................... 135 

Revised Regulatory Text—18 CFR Parts 41 and 141. 

Appendix A: Revised Form 1 Pages. 

Appendix B: List of Proposed Technical Changes and Responses. 

Appendix C: List of Commenters. 

I. Introduction 

1. This Final Rule amends the Federal 

Energy Regulatory Commission’s 

(Commission) reporting requirements 

for public utilities 1 and licensees to file 

financial forms, reports, and statements, 

including FERC Form No. 1 (Form 1), 

FERC Form No. 1–F (Form 1–F), and 

FERC Form No. 3–Q (Form 3–Q). These 

changes will improve the forms, reports 

and statements to provide, in fuller 

detail, the information the Commission 

needs to carry out its responsibilities 

under the Federal Power Act (FPA) to 

ensure that rates remain just and 

reasonable. In addition, the changes will 

help provide public utility customers, 

state commissions, and the public the 

information they need to assess the 

justness and reasonableness of electric 

rates. 

2. This Final Rule complements the 

Commission’s recent revisions to the 

reporting requirements for natural gas 


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2 18 CFR Parts 158 and 260; Revisions to Forms, 

Statements, and Reporting Requirements for 

Natural Gas Pipelines, Order No. 710, Docket No. 

RM07–9–000, 73 FR 19389 (Apr. 10, 2008), FERC 

Stats. & Regs. ¶ 31,267, order on reh’g, Order No. 

710–A, 123 FERC ¶ 61,278 (2008). 

3 16 U.S.C. 824d. 

4 16 U.S.C. 824. 

5A major electric utility is one that had, in the 

last three consecutive years, sales or transmission 

services that exceeded (1) one million megawatthours of total sales; (2) 100 megawatt-hours of sales 

for resale; (3) 500 megawatt-hours of power 

exchanges delivered; or (4) 500 megawatt-hours of 

wheeling for others (deliveries plus losses). Utilities 

and licensees that are not classified as major and 

had total sales in each of the last three consecutive 

years of 10,000 megawatt-hours or more are 

classified as nonnmajor. See 18 CFR Part 101. 

6 16 U.S.C. 825a, 825f, 825h; see also 16 U.S.C. 

825j. 

7Amendments to FERC Form Nos. 1 and 1–F, and 

Annual Charges, and Fuel Cost and Purchased 

Economic Power Adjustment Clauses, Order No. 

529, FERC Stats. & Regs. ¶ 30,904 (1990). 

8Revisions to Uniform System of Accounts to 

Account for Allowances under the Clean Air Act 

Amendments of 1990 and Regulatory-Created 

Assets and Liabilities and to Form Nos. 1, 1–F, 2 

and 2–A, Order No. 552, FERC Stats. & Regs. 

¶ 30,967 (1993). 

9Electronic Filing of FERC Form No. 1 and 

Delegation to Chief Accountant, Order No. 574, 

FERC Stats. & Regs. ¶ 31,013 (1994) (establishing 

the Form 1 Submission Software (FOSS)). 

10Electronic Filing of FERC Form No. 1, and 

Elimination of Certain Designated Schedules in 

Form Nos. 1 and 1–F, Order No. 626, FERC Stats. 

& Regs. ¶ 31,130 (2002). 

11Accounting and Reporting of Financial 

Instruments, Comprehensive Income, Derivatives 

and Hedging Activities, Order No. 627, FERC Stats. 

& Regs. ¶ 31,134 (2002). 

12Quarterly Financial Reporting and Revisions to 

the Annual Reports, Order No. 646, FERC Stats. & 

Regs. ¶ 31,158, order on reh’g, Order No. 646–A, 

FERC Stats. & Regs. ¶ 31,163 (2004). 

13Accounting and Financial Reporting for Public 

Utilities Including RTOs, Order No. 668, FERC 

Stats. & Regs. ¶ 31,199 (2005), reh’g denied, Order 

No. 668–A, FERC Stats. & Regs. ¶ 31,215 (2006). 

14 Id. 

15Assessment of Information Requirements for 

FERC Financial Forms, Notice of Inquiry, FERC 

Stats. & Regs. ¶ 35,554 (2007). 

companies; 2 it revises the financial 

forms filed by public utilities and 

licensees—specifically, Form 1, Annual 

report for major electric utilities, 

licensees, and others; Form 1–F, Annual 

report for nonmajor public utilities, 

licensees and others; and Form 3–Q, 

Quarterly report of electric utilities, 

licensees, and natural gas companies. 

3. Specifically, the Final Rule adopts 

revised reporting requirements which 

will enhance the Commission’s and 

customers’ review of formula rates; 

permit better understanding of nonpower goods and services transactions 

with affiliates, and provide additional 

detail of revenues not previously 

specified in Form 1. In addition, the 

Final Rule will expedite reporting by 

clarifying Form 1 instructions and crossreferences and making certain technical 

improvements in the form. Finally, the 

Final Rule responds to the burdens 

faced by filers by adopting minimum 

reporting thresholds for certain 

accounting data, eliminating the 

reporting requirement for certain 

utilities that are not otherwise subject to 

this Commission’s reporting obligations 

or jurisdiction, and accommodating 

filers whose fiscal year does not fall in 

the calendar year that is used for 

reporting purposes. 

4. This Final Rule does not convert 

the submission of Form 1 and other data 

into a FPA section 205 3 rate case filing 

or a cost-and-revenue study, but is 

instead intended to better ensure a 

ready source of data to assist the 

Commission and interested parties in 

evaluating the justness and 

reasonableness of a utility’s rates. The 

revised forms do not limit or change an 

entity’s rights or obligations under the 

FPA and our regulations, and this Final 

Rule is not intended to change our 

obligation to rule on complaints, 

petitions, or other requests for relief 

based on a full record and substantial 

evidence. 

5. The proposed effective date for 

implementation of these changes is 

calendar year 2009. Accordingly, 

companies subject to the new 

requirements would file their new Form 

3–Qs following the first calendar quarter 

of 2009 and their new Forms 1 and 

1–F in April 2010 for calendar year 

2009. In addition, this Final Rule 

eliminates the filing requirement for 

utilities not subject to the Commission’s 

jurisdiction under section 201 of the 

FPA 4 but required to file Form 1 solely 

because they met the reporting 

threshold in the regulations. 

II. Background 

6. Under the Commission’s 

regulations, entities classified as major 

electric utilities are required to file 

Form 1. Entities classified as nonmajor 

electric utilities are required to file 

Form 1–F.5 Sections 304, 307 and 309 

of the FPA authorize the Commission to 

collect such data.6 Form 1, in particular, 

requires information to be filed on an 

annual basis by public utilities (and 

certain hydroelectric production 

sources) under the Commission’s 

jurisdiction. Form 1 collects corporate 

information, summary financial 

information and balance sheet and 

income information, as well as electric 

plant, sales, operating and statistical 

data. Since its inception, Form 1 has 

been amended by the Commission on 

numerous occasions to address and 

keep pace with the transformation of the 

utility industry. 

7. In 1990, the Commission issued 

Order No. 529, which modified Form 1 

to improve reporting of bulk power 

transactions.7 In 1993, the Commission 

issued Order No. 552, which revised the 

Uniform System of Accounts (USofA) to 

account for allowances under the 1990 

Clean Air Act Amendments, and 

adopted corresponding reporting 

schedules for Forms 1 and 1–F.8

8. In 1994, the Commission issued 

Order No. 574, which required the filing 

of an electronic version of Form 1, along 

with the paper version. The electronic 

version was prepared pursuant to a 

computer program supplied by the 

Commission.9 In 2002, the Commission 

issued Order No. 626, which eliminated 

the paper filing requirement, relying 

solely on electronic filing of Form 1.10

Also in 2002, the Commission expanded 

USofA accounting requirements to 

include monitoring for the fair value of 

certain security investments, derivative 

instruments, and hedging activities, and 

added new schedules and accounts to 

Forms 1 and 1–F.11

9. Order No. 646 implemented 

quarterly reporting for entities that filed 

Forms 1 and 1–F and added annual 

reporting requirements for ancillary 

services and electric transmission peak 

loads.12 In 2005, Order No. 668 updated 

the Commission’s accounting 

requirements for utilities and licensees, 

including independent system operators 

(ISOs) and regional transmission 

organizations (RTOs).13 The 

Commission also revised its USofA and 

Forms 1 and 1–F to accommodate 

industry restructuring under the 

Commission’s open-access transmission 

policies and increased competition in 

wholesale bulk power markets.14

III. Notice of Inquiry 

10. As part of Commission staff’s 

ongoing comprehensive review of the 

Commission’s financial data 

requirements, a series of public 

meetings were held in Fall 2006 with 

both filers and users of FERC’s financial 

reports (Forms 1, 1–F, 2, 2–A and 3–Q). 

On February 15, 2007, the Commission 

issued a Notice of Inquiry (NOI) in 

response to those discussions.15 The 

NOI sought comments on the need for 

changes or additions to the financial 

information reported on these forms. In 

response to the comments received, the 

Commission determined that each of the 

forms, representing different industries 

subject to the Commission’s 

jurisdiction, merited its own separate 

review. Accordingly, the Commission 

established a separate proceeding in 

Docket No. RM07–9–000, addressing 

only changes, additions, and 


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58722 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 

16Revisions to Forms. Statements, and Reporting 

Requirements for Natural Gas Pipelines, Order No. 

710, FERC Stats. & Regs. ¶ 31,267, order on reh’g, 

Order No. 710–A, 123 FERC ¶ 61,278 (2008). 

17Revisions to Forms, Statements, and Reporting 

Requirements for Electric Utilities and Licensees, 

Notice of Proposed Rulemaking, 73 FR 5136 (Jan. 

29, 2008), FERC Stats. & Regs. ¶ 32,627 (Jan. 18, 

2008) (NOPR). 

18These proposals were listed in an appendix to 

the NOPR, which is updated here with Commission 

responses and provided in Appendix B to this Final 

Rule. 

19A list of commenters is attached as Appendix 

C. 

amendments to the forms applicable to 

interstate natural gas companies.16

IV. Notice of Proposed Rulemaking 

11. On January 18, 2008, the 

Commission issued a Notice of 

Proposed Rulemaking (NOPR) that 

proposed to revise the Form 1 (and 

Forms 1–F and 3–Q) and requested 

comments on several issues, including: 

(1) Differences between Form 1 data and 

costs that are reflected in formula rate 

inputs, (2) the non-jurisdictional utility 

requirements and revising the Form 

1–F reporting threshold for nonmajor 

utilities, (3) reporting for affiliate 

transactions, (4) filers whose reporting 

and accounting systems are based on a 

non-calendar fiscal year, (5) reporting 

for ‘‘Other Revenues,’’ and (6) the 

minimum threshold reporting levels for 

certain line-item information.17 In 

addition, the NOPR proposed two nonform related rule changes, concerning 

notification of non-filing status and 

grants of extension of time for good 

cause. The NOPR also invited comments 

on software updates, revisions to the 

filing instructions, requests for 

additional information for particular 

accounts or schedules, and suggestions 

to improve the quality, completeness 

and consistency of data submissions.18

V. Discussion 

A. Notice of Inquiry 

12. In responding to the NOI, Form 1 

public utility filers generally 

emphasized the difficulty and expense 

of Form 1 preparation, stated that the 

current scope of information sought is 

sufficient to evaluate jurisdictional 

rates, and objected to particular filing 

requirements as burdensome. In 

contrast, Form 1 users, including 

nonprofit publicly-owned utilities and 

state commissions, disagree—requesting 

that Form 1 provide additional 

information to permit more effective 

review to determine whether current 

and proposed rates are just and 

reasonable. 

B. Notice of Proposed Rulemaking 

13. In the NOPR, the Commission 

affirmed that the information reported 

in Forms 1, 1–F and 3–Q is critical to 

the work of the Commission and stated 

its expectation that all filers would 

continue to follow the instructions and 

submit properly completed forms. The 

NOPR emphasized the importance of 

Form 1 data to the Commission, state 

commissions, utility customers and 

other interested persons as an important 

and primary source of information to 

assess whether rates charged remain just 

and reasonable or may be unjust and 

unreasonable. The NOPR stated that the 

purpose of Form 1, in particular, is to 

provide basic financial and operational 

information to allow the Commission, 

customers, and competitors to monitor a 

utility’s rates for jurisdictional services. 

Form 1 is an essential tool in the 

Commission’s regulatory program. Form 

1 makes publicly available the financial 

information upon which cost-based 

rates are developed and provides 

information on the financial operations 

of utilities. Form 1 and the underlying 

data are used in ratemaking and for 

customer rate and cost monitoring. In 

addition, because it reflects the 

Commission’s USofA, Form 1 ensures 

that such data is uniform and 

comparable between companies and 

reporting periods. Form 1 is not a 

substitute for a rate case filing or a 

projection of future financial 

performance, however. Instead the data 

enables the form’s users to monitor and 

assess a utility’s rates. 

14. Pursuant to the Commission’s 

comprehensive review of its financial 

reporting forms and based on the 

responses to the NOI, the Commission 

determined that wholesale changes were 

not justified, and instead proposed 

targeted adjustments to the existing 

reporting requirements. 

15. In response to the NOPR, the 

Commission received 13 timely 

comments, one motion to submit 

comments out-of-time, and one set of 

reply comments.19 These comments are 

summarized in the remainder of the 

discussion section. 

16. After careful consideration of the 

comments received, the Commission is 

adopting changes and revisions 

proposed in the NOPR with certain 

modifications and clarifications, as 

discussed below. 

17. No comments were filed objecting 

to the NOPR’s proposals concerning (i) 

accommodating filers whose books close 

on a non-calendar fiscal year, (ii) filing 

notifications of changes to non-filing 

status, (iii) adopting a good cause 

requirement for reviewing requests for 

extension of time, and (iv) providing for 

separate reporting of emissions 

allowances, such as nitrogen oxide 

(NOX) and sulfur dioxide (SO2). In fact, 

comments were received supporting 

several of these proposals, including the 

non-calendar year accommodation and 

emission allowances. Therefore, we 

adopt the proposals as set forth in the 

NOPR. 

18. In addition, several commenters 

proposed additional reporting 

requirements or modifications to the 

proposals made in the NOPR. To the 

extent such comments proposed 

revisions that were feasible and in 

keeping with the goals expressed in the 

NOPR, the Commission has attempted 

to incorporate commenters’ suggestions 

as discussed below. The discussion in 

the ‘‘Commission Determination’’ 

sections addressing each NOPR 

proposal provides additional detail to 

clarify those proposals and respond to 

the comments. 

C. Effective Date 

19. The NOPR proposed calendar year 

2009 as the effective date to implement 

these changes to the reporting 

requirements, stating: 

Accordingly, companies subject to the new 

requirements would file their new Form 3– 

Qs beginning with the Form 3–Q for the first 

calendar quarter of 2009 and their new Forms 

1 and 1–F in April 2010 for calendar year 

2009. 

20. The Commission believes that this 

effective date provides sufficient time 

for filing companies to collect the 

information needed to fulfill the 

reporting obligations proposed in the 

NOPR and adopted in this Final Rule. 

Because the changes adopted here are 

limited in scope, filers have sufficient 

opportunity to make the necessary 

changes to their reporting systems to 

capture the necessary data in the detail 

needed to complete the new 

requirements contained in this Final 

Rule. This proposed effective date thus 

provides an adequate time for utilities to 

revise their information collection 

procedures, and filers will have several 

additional months before the first 

reporting deadline to implement the 

changes needed because the first report 

due is the Form 3–Q, a quarterly report, 

due in May 2009. Therefore, the 

Commission adopts the changes 

provided for in this Final Rule effective 

calendar year 2009, consistent with the 

date proposed in the NOPR. 

D. Proposed Revisions 

1. Formula Rates 

21. In response to comments 

requesting additional information to 

accommodate formula rate review, the 

NOPR proposed the addition of 


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20NOPR at P 46. 

21BPA states its understanding that the burden of 

proof otherwise remains on the party challenging a 

Commission-approved formula. 

22See AEP, EEI, FirstEnergy, and Duke 

comments. 

explanatory information when formula 

rate inputs deviate from data reported in 

Form 1. Specifically, the NOPR 

proposed to revise the Form 1 to require 

that, if the inputs to a formula rate 

deviate from what is currently shown in 

the Form 1, the filer must provide an 

explanation for the deviation in a 

footnote to the corresponding page, line 

and column where the specific data is 

reported. The Commission sought 

comment on this proposal.20

Comments 

22. Several commenters support the 

Commission’s proposal for filing 

utilities to explain departures from 

Form 1 data in formula rates. SDG&E, 

for example, notes that many utilities 

with formula rates already make 

periodic informational filings to explain 

the use of modified Form 1 data. SDG&E 

supports the NOPR proposal and 

characterizes the proposal as a 

pragmatic and narrowly-tailored effort 

to provide additional information that 

does not duplicate publicly available 

material, while avoiding a ‘‘one size fits 

all’’ modification to Form 1 that does 

not address the varieties of formula rates 

currently in effect or utilities’ uses of 

variations from Form 1 data. 

23. APPA also supports the 

Commission’s intent that utilities 

provide all information necessary for 

calculating formula rates, but questions 

whether the Commission’s proposal will 

achieve the desired effect. APPA states 

that the requirement that filers describe 

in footnotes details on how formula 

rates deviate from Form 1 information 

may be difficult to monitor because staff 

may lack the means to identify utilities 

subject to the formula rate information 

requirement. APPA suggests that the 

Commission require a new schedule for 

filers to identify their status in regard to 

formula rates, which would require a 

filer to indicate (1) whether it has 

formula rates; and (2) where to find all 

explanations for deviations between 

formula rates and Form 1 information 

(either informational filings or footnotes 

in connection with specific page, line 

and column numbers of Form 1). Such 

a schedule would ensure that a utility 

does not omit a necessary footnote and 

would also locate deviations from Form 

1 data. APPA predicts that such a 

schedule would not change any Form 1 

references currently contained in 

formula rates and should not add any 

substantial burden to respondents, 

because it would not repeat the 

information, but would simply reference 

the location of the information already 

compiled. 

24. BPA agrees that since formula 

rates routinely cite specific accounts 

and page numbers, the Commission 

should not revise Form 1 accounts or 

page numbers, so as to necessitate 

amendments to existing formula rates. 

BPA supports the use of explanatory 

footnotes, stating that the footnotes are 

an essential aspect of Form 1 and may 

provide the only means for a utility to 

explain, and Form 1 user to understand, 

the data. BPA suggests the need for 

additional enforcement of Form 1 

requirements, including penalties for 

failure to meet footnote requirements. 

25. In addition, BPA requests 

clarification that a statement made in 

paragraph 41 of the NOPR, ‘‘[t]he annual 

rate adjustment may not initiate a rate 

proceeding and the customer’s recourse, 

if it believes the resulting rates are 

unjust and unreasonable, is to file a 

complaint under section 206 of the 

FPA,’’ is not intended to change the 

burden of proof in a section 206 

proceeding involving a formula rate. 

Specifically, BPA requests the 

Commission clarify that the statement 

does not shift the burden of proof from 

the utility to establish that the formula 

is correctly applied or that the correct 

data is being used to populate the 

formula.21

26. Nevada Companies suggests that a 

transmission provider should post the 

reasons for changes in formula rates on 

its Web site within a prescribed period 

of time, which would provide 

immediate information to customers on 

changes in rates rather than having to 

wait for a quarterly or annual filing. 

27. TAPS strongly supports the 

NOPR’s effort to further the goal of 

timely transparency through inclusion 

of the relevant information in Form 1. 

TAPS questions the level of detail in an 

informational filing that would relieve a 

utility of the requirement to describe 

formula rate differences in Form 1. 

TAPS states that the rule should require 

that the transparency information be 

included in Form 1 submissions of each 

utility whose Form 1 data is input into 

a formula rate. TAPS proposes that 

waivers be considered where the utility 

can show that it is legally committed to 

make annual informational filings that 

will provide all of the data, of the same 

quality and reliability, that would 

otherwise have to be included in its 

Form 1, and will do so in time to 

facilitate rate monitoring by customers, 

regulators, and the public. TAPS also 

requests that the Final Rule require 

annual reporting of all historical cost, 

load, and revenue information that is an 

input into a Form 1 filing utility’s 

formula rate. 

28. The Michigan Commission 

requests that the Commission initiate a 

process to address problems associated 

with its review of utility transmission 

investment in conjunction with formula 

rates. The Michigan Commission states 

that a lack of necessary data reporting in 

combination with formula rates can 

shield utility investment decisions from 

review. The Michigan Commission 

suggests that the Commission initiate an 

inquiry, possibly a technical conference, 

to explore ways that formula rates can 

be reviewed. 

29. Several utility commenters object 

to the requirement to add footnotes to 

discuss differences between Form 1 

financial information and formula rate 

inputs for wholesale rates.22 AEP 

believes that the Form 1 is a financial 

report and should continue to be a 

financial report and not a rate 

verification report. AEP claims that 

footnoting differences between Form 1 

data and formula rate inputs would, for 

some filers like AEP, be extensive, 

voluminous and burdensome to comply 

with. AEP suggests that multiple rates 

will require reconciliation, including 

separate wholesale customer service 

rates and some regional transmission 

organization rates. AEP states that the 

Commission should obtain such 

information from the seller when 

needed on a case-by-case basis. AEP 

suggests that the additional detail need 

not be made public, and states that the 

information is better provided as a 

separate rate filing to be made whenever 

the formula rate is being changed or 

supported. 

30. EEI encourages the Commission 

not to add a requirement to Form 1 to 

explain departures from Form 1 

information used as inputs to formula 

rates. EEI argues that companies should 

not be required to footnote Form 1 data 

to explain differences in formula rates, 

so long as they document changes to 

formula rate inputs, adhere to the 

approved formula rate tariffs, and 

provide information to the Commission 

and affected customers on request or via 

informational filings. 

31. EEI suggests that the Commission 

adopt an alternate policy, under which 

companies adopting formula rates 

would provide information to customers 

about rate inputs, including underlying 

costs and cost increases, in sufficient 

detail to enable the customers to 

understand the basis for their rates. EEI 

states that if the Commission does 


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58724 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 

23Other than comprehensive formula rates, the 

Commission’s regulations provide for automatic 

adjustment of only those costs specified in section 

35.14 of our regulations (fuel adjustment clause). 

See Public Service Company of Oklahoma, 40 FERC 

¶ 61,215, at 61,733 (1987). 

24Thus, utilities that are required to make regular 

informational filings by their formula rates, a 

Commission-approved settlement, or other 

Commission order need not provide footnotes. 

These filers must nevertheless complete the new 

schedule provided in page 106. 

25We clarify that we do not seek the explanatory 

information for fuel adjustment clauses, which are 

governed by separate policies established in the 

Commission’s regulations and which typically 

would not reference Form 1. See 18 CFR 35.14. 

26This recordkeeping requirement is in addition 

to any other Commission recordkeeping 

requirement, see, e.g., 18 CFR Parts 101, 125, 

including the footnoting requirement adopted in 

this Final Rule. 

impose a formula rate footnote 

requirement in Form 1, the Commission 

should: (1) Clarify that the footnote is 

necessary only to explain departures 

from Form 1 data when a formula rate 

tariff calls for specific Form 1 data as 

inputs and different input data are used; 

(2) clarify that the footnote requirement 

applies only to cost-based rates, not to 

market-based rates (MBR); (3) specify 

that, if a seller files informational filings 

containing information about inputs to 

its formula rates, a footnote is not 

required; (4) specify that if customers 

have audit rights under a formula rate 

tariff, a footnote is not required; (5) 

specify that if a company has explained 

departures from Form 1 data as inputs 

to a formula rate elsewhere in 

information available to the 

Commission and customers on request, 

it is not required to do so again in Form 

1; (6) specify that, if the footnote cannot 

be added before Form 1 is filed, it can 

be added at the next reporting cycle; 

and (7) address how the footnote should 

be prepared when multiple operating 

companies or gas and electric 

companies are involved and not all of 

those companies are reflected in a given 

Form 1. 

32. FirstEnergy requests that the 

Commission clarify that its proposal is 

not a blanket requirement on companies 

filing the Form 1 to include any changes 

on inputs to formula rates in a footnote 

to the relevant page in Form 1. 

Similarly, the Commission should also 

clarify that its proposed requirement 

would not preclude companies from 

submitting the formula input 

information in filings other than Form 1. 

33. FirstEnergy states that companies 

should not be required to submit 

informational filings or otherwise report 

situations in which formula rate inputs 

differ slightly from what is shown in 

Form 1, and requests the Commission to 

clarify whether such disclosures will 

now be required. To the extent that such 

information will be required, 

FirstEnergy does not believe that Form 

1 is an appropriate vehicle for reporting 

information concerning a utility’s 

formula rates. FirstEnergy states that 

Forms 1 and 3–Q are financial 

statements providing information in 

accordance with the USofA and argues 

that the forms are not, and should not 

be, considered ratemaking documents to 

be used for ratemaking purposes. 

Commission Determination 

34. In this Final Rule, as we explain 

below, we adopt the NOPR proposal 

that Form 1 filers should provide 

explanatory information when formula 

rate inputs differ from Form 1 reported 

amounts.23 That is, with regard to 

formula rates for which no 

informational filings are required to be 

regularly submitted to this Commission, 

we revise the Form 1 to require that, if 

the formula rate relies on Form 1 data 

and if the input amounts to that formula 

rate differ from what is shown in the 

Form 1, the filer must provide a 

narrative explaining the reason for the 

difference. The explanation must be 

provided in a footnote on the same page, 

line and column where the specific data 

is reported. 

35. As described above, EEI states that 

companies which provide service under 

formula rates should make additional 

information available if requested by 

customers, on an as-needed basis, if 

such information is not already being 

provided in the informational filings. 

EEI recommends that the Commission 

adopt an alternative policy, under 

which companies using formula rates 

would provide information to customers 

about rate inputs, including underlying 

costs and cost increases, in sufficient 

detail to enable the customers to 

understand any deviations to the inputs 

used in calculating the formula rates. 

36. With respect to EEI’s requests for 

various clarifications, we adopt portions 

of EEI’s recommendations as follows. 

Consistent with the NOPR proposal we 

limit the footnoting requirement so that 

it will only apply to utilities with 

formula rates that do not make regular 

(i.e., at least annual) informational 

filings of cost data with the Commission 

pursuant to the requirements of their 

formula rates (or for example, pursuant 

to the requirements of a Commissionapproved settlement or a Commission 

directive). We believe it is unnecessary 

to require companies that are required 

to make regular informational filings to 

include a footnote in Form 1 because 

any difference from any Form 1 inputs 

used in formula rates should already be 

described in sufficient detail in their 

informational filings.24

37. In addition, EEI requests 

clarification of the treatment of formula 

rates accepted under our MBR policies. 

We clarify that a rate is subject to the 

footnoting requirement if it relies on 

Form 1 data and is on file with the 

Commission. Such rates may be featured 

in tariffs of general applicability or 

individual rate schedules.25 We further 

adopt EEI’s suggestion that, if 

companies have formula rates but do 

not make such informational filings 

with the Commission, they must 

maintain sufficient records that explain 

the changes made to those inputs 26

(and, of course, must adhere to the 

approved formula rate tariffs on file) 

and provide that information to the 

Commission, state commissions and 

affected customers on request. 

Furthermore, we clarify that if 

customers have audit rights under a 

formula rate, a footnote is still required, 

so that utilities can describe how the 

rate was derived (as described herein). 

38. With respect to EEI’s request that 

the Commission specify that footnote 

information that cannot be added before 

Form 1 is filed may be added at the next 

reporting cycle, we clarify that if the 

necessary information is not available at 

the time for filing (given that Form 1 is 

an annual report), the utility must 

provide the information in its next Form 

1 filing. 

39. As stated in the NOPR, we do not 

propose to convert the Form 1 filing 

process into a rate proceeding. As noted 

by several commenters, Form 1 is an 

historical financial reporting document. 

However, Form 1 provides cost and 

revenue data that aids in evaluating the 

justness and reasonableness of rates in 

a ratemaking proceeding, and Form 1 

serves as a ready source of public 

information to assess on an ongoing 

basis the justness and reasonableness of 

utility rates. In particular, for a formula 

rate, Form 1 identifies costs that result 

in annual fluctuations in rates as costs 

rise and fall. Thus, Form 1 plays an 

important role in the Commission’s rate 

review process. 

40. A key component of this rate 

review process is the transparency 

provided by requiring utilities to make 

information on costs underlying rates 

publicly available. This cost information 

is, in turn, used by the Commission, 

state commissions, and customers to 

review and monitor a utility’s rates, 

which, as appropriate, may ultimately 

result in an investigation or a complaint 

proceeding. Thus, Form 1 is a valuable 

tool. Commenters’ attempts to establish 

a bright line between financial reporting 


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27As noted above, we do not seek the explanatory 

information for fuel adjustment clauses, which are 

governed by separate polices under the 

Commission’s regulations and typically do not 

reference Form 1. See 18 CFR 35.14. 

28The information contained in a formula rate 

footnote (as for any Form 1 footnote) should be 

specific to the data provided in the form, and not 

simply transferred from consolidated financial 

statements that may reflect different assumptions 

and reporting requirements. 

29Whether or not a public utility or licensee must 

provide this information is addressed above. 

30Revised Form 1 pages affected by this Final 

Rule are provided in Appendix A. 

31The Commission reiterates that utilities that are 

required to make regular informational filings by 

their formula rates, a Commission-approved 

settlement, or other Commission requirement (e.g., 

a Commission requirement imposed as a condition 

of acceptance of the formula rates) need not provide 

footnotes. These filers must nevertheless complete 

the new schedule provided in page 106. 

32See Order No. 710 at P 12 (noting that despite 

changes made to gas reporting forms, a party filing 

a complaint has the burden to show why the 

information in the Commission’s financial forms 

supports an allegation that the existing rates are not 

just and reasonable, and that the changes adopted 

in Order No. 710 do not limit an entity’s rights 

under governing law and the Commission’s 

regulations, nor change the Commission’s 

obligation to rule on complaints, petitions, or other 

requests for relief based on a full record and 

substantial evidence). 

and rate making are insufficient for the 

Commission to withdraw its proposals 

to seek information that will assist the 

Commission in carrying out its statutory 

obligations to ensure that rates are just 

and reasonable, and to assist others— 

including customers—with monitoring 

rates charged. 

41. The NOPR did not propose to 

revise the Commission’s USofA 

accounting requirements to track 

specific costs or cost estimates for future 

projects as suggested by TAPS and the 

Michigan Commission. Therefore, we 

will not adopt proposals to track 

additional costs that would require 

changes to the Commission’s accounting 

requirements. 

42. In response to APPA’s comments 

concerning how Commission staff will 

determine whether a utility is subject to 

a regular informational filing 

requirement for its formula rate, we note 

that the existence of such a filing 

requirement is a matter of public record 

for each formula rate. That is, the 

requirement that a utility make a regular 

informational filing describing the 

information that will be used to 

populate the formula rate is typically 

established in the rate proceeding 

accepting the formula rate. If an 

interested entity believes that a utility 

has failed to include the required 

footnotes, or that a utility has not 

responded in a timely manner to a 

request for an explanation of the 

applicable formula rate and the inputs 

to that rate, it should discuss the matter 

with the utility and, if not satisfied, 

may, among other things, notify the 

Commission through our enforcement 

Hotline and the Commission’s Office of 

Enforcement will take appropriate 

action. 

43. Based on the record in this 

proceeding, the Commission does not 

anticipate that this reporting 

requirement will be unduly burdensome 

because the information is already 

available and can be transposed to a 

footnote. 

44. Several filing utilities request the 

Commission to clarify the scope of the 

formula rate footnoting requirement. 

Initially, as noted above, the 

Commission clarifies that a filing 

company should footnote differences 

from Form 1 data in formula rates that 

are on file with this Commission and 

that rely on Form 1 data, and that such 

rates may be featured in tariffs of 

general applicability or individual rate 

schedules.27 The Commission also 

clarifies that it is not necessary to 

provide a detailed reconciliation. The 

Commission anticipates that the 

footnotes would contain a simple 

narrative explaining how the ‘‘rate’’ (or 

billing) was derived if different from the 

reported amount in the Form 1. For 

instance, differences could be due to: (i) 

Application of a percent allocation 

factor for gross transmission plant that 

is OATT related; (ii) excluding 

particular items such as step-up 

transformer investment; (iii) deducting 

amounts for transmission for others 

from total transmission expenses or 

applying an OATT transmission factor; 

or (iv) excluding particular cost items 

from administrative and general 

expenses or application of an OATT 

labor factor. This list is not exhaustive, 

we caution, but is strictly for illustration 

purposes; the Commission anticipates 

that similar issues would be footnoted 

in Form 1. The description should 

describe the difference, including any 

reference to a Commission proceeding 

approving the difference. Such an 

explanation should be sufficient to alert 

interested parties of the deviation and to 

permit them to estimate and evaluate 

the impact of the departure on rates.28

In this fashion, interested entities 

should be able to, with reasonable 

accuracy, monitor rates in light of 

current costs and available financial 

data. 

45. In response to suggestions that 

formula rate information be centralized, 

a new schedule (page 106) will be 

incorporated in Form 1 on which filers 

will (1) indicate whether they have 

formula rates; (2) provide details about 

the formula rates; (3) indicate whether 

the filer makes regular informational 

filings and the location of the filings 

(e.g., accession numbers) on the 

Commission’s eLibrary Web site; and (4) 

summarize, if required,29 the differences 

between the Form 1 amounts and any 

amounts included in a formula rate as 

described above.30

46. AEP is concerned that reporting 

may be difficult because of the number 

and variety of rate schedules and tariffs 

that may be covered by this 

requirement. As stated above, we do not 

anticipate that this requirement need 

rise to the level of an accounting 

reconciliation; a narrative description 

(with reference to a rate proceeding 

adopting the difference) may suffice. 

47. In addition, a utility is not 

precluded from filing modifications to 

its formula rates to make cost references 

consistent with Form 1 reporting 

requirements as they are updated.31

48. In response to BPA and the 

Michigan Commission, we clarify that 

this Final Rule does not change our 

policies with respect to the burden of 

proof associated with challenges to 

previously approved formula rates 

under section 206.32 Form 1 is not filed 

pursuant to sections 205 or 206 of the 

FPA and, therefore, its submittal will 

not initiate a rate proceeding or 

investigation. A rate proceeding is 

initiated by a rate filing under section 

205, or an investigation initiated either 

in response to a complaint or pursuant 

to a notice of Commission investigation 

under section 206. Additional 

information to assess jurisdictional rates 

may be requested from the utility or 

sought through discovery in an 

appropriate proceeding; the 

Commission’s actions here do not, for 

example, affect the scope of discovery in 

litigated proceedings. 

49. In addition, we reject TAPS’ 

proposals to change the Commission’s 

accounting as beyond the scope of this 

proceeding, which relates to reporting 

requirements for the various accounts 

defined by the USofA, and we reject the 

Nevada Companies’ proposal to revise 

our OASIS Web site posting 

requirements; both should be addressed 

in more appropriate proceedings 

reviewing the Commission’s accounting 

and OASIS regulations. 

50. With respect to the Michigan 

Commission’s suggestion that the 

Commission initiate an inquiry into the 

Commission’s formula rate policies and 

whether formula rates can shield future 

utility investment decisions from 

review, the Commission declines to 

initiate such an investigation. The 

NOPR rejected calls for reporting 


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33NOPR at P 54. 

34Preventing Undue Discrimination and 

Preference in Transmission Service, Order No. 890, 

72 FR 12,266 (March 15, 2007), FERC Stats. & Regs. 

¶ 31,241 at P 435 (2007), order on reh’g, Order No. 

890–A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & 

Regs. ¶ 31,261 (2007), order on reh’g, Order No. 

890–B, 123 FERC ¶ 61,299 (2008). 

35NOPR at P 50. 

36 Id. P 48. 

37 Morenci Water and Electric Co., 121 FERC 

¶ 61,024 (2007). 

38NOPR at P 51–52. 

39APPA and Michigan Commission comments. 

40 International Transmission, and SDG&E 

comments. 

41See AEP, EEI, MidAmerican, and Nevada 

Companies comments. 

42FirstEnergy and Duke comments. 

information on future transmission 

investments, stating that Form 1 is 

intended to provide information on a 

utility’s financial activities for the 

reporting year, but does not include 

projections of future costs.33 Comments 

filed in response to the NOPR have not 

persuaded us to change our views. 

Should an entity desire to question the 

prudence of a utility’s transmission 

investment decisions, it may file a 

complaint with the Commission.34

2. Filing Thresholds for Form 1 

51. The NOPR proposed to eliminate 

the filing requirement for utilities that 

are not subject to the Commission’s 

jurisdiction because they are not public 

utilities under Part II of the FPA, but 

make sales that meet or exceed the 

threshold for meeting the Commission’s 

Forms 1 and 3–Q reporting 

requirements.35 The NOPR also sought 

comment on whether to revise the 

definitions for major and nonmajor 

utilities, inviting specific suggestions for 

how this might be done with 

justifications for proposed thresholds.36

The NOPR mentioned that the 

Commission was aware of five nonjurisdictional utilities that otherwise 

met or exceeded the threshold for 

reporting: Alaska Electric and Power 

Co.; CenterPoint Energy Houston 

Electric, LLC; Hawaii Electric Light Co., 

Inc.; Hawaiian Electric Co., Inc.; and 

Maui Electric Co., Ltd. 

52. The NOPR cited an order where 

the Commission recently granted waiver 

of the financial form filing requirements 

under such circumstances. In Morenci 

Water and Electric Co., the Commission 

granted a waiver from the requirement 

of §§ 141.1 and 141.400 of the 

Commission’s regulations that utilities 

who are not public utilities under Part 

II of the FPA but who otherwise meet 

the threshold filing requirements for 

Forms 1, 1–F and 3–Q must comply 

with the reporting requirements 

established in the regulations.37

Comments 

53. No commenter objected to these 

proposals. International Transmission 

proposes, however, that non-major 

electric utilities and non-jurisdictional 

utilities that belong to a joint rate zone 

be required to file Form 1 and that, for 

purposes of the filing thresholds, all of 

the electric utilities in a joint rate zone 

should be deemed major electric 

utilities. International Transmission 

thus proposes that, in addition to the 

numerical filing thresholds, the General 

Instructions to Part 101 be revised to 

require that: (1) Nonmajor electric 

utilities in joint rate zones with major 

electric utilities be required to file Form 

1; and (2) non-jurisdictional utilities in 

joint rate zones with jurisdictional 

public utilities also be required to file 

Form 1. 

Commission Determination 

54. In this Final Rule we are removing 

the words ‘‘whether or not the 

jurisdiction of the Commission is 

otherwise involved’’ from §§ 141.1(b) 

and 141.400(b), which establish the 

filing requirements for Form 1 and Form 

3–Q, respectively. With this change, 

companies that are not subject to the 

Commission’s jurisdiction because they 

are not public utilities (or licensees) 

need no longer file Form 1 or 3–Q. If a 

company is concerned that it may still 

fall within the revised requirements of 

§§ 141.1(b) or 141.400(b), but 

nevertheless should be exempted from 

filing Forms 1 and 3–Q, it may continue 

to seek an individual waiver from the 

Commission. No commenter, we add, 

objected to the proposal to cease 

requiring filing by companies that do 

not otherwise fall under the 

Commission’s jurisdiction, but meet the 

minimum filing requirements found in 

§§ 141.1 and 141.400 of the 

Commission’s regulations. 

55. The Commission rejects 

International Transmission’s proposal to 

revise the definitions that distinguish 

major and nonmajor utilities, to require 

utilities that participate in joint rate 

zones with major utilities to also file 

Form 1. International Transmission’s 

proposal expands the reporting 

requirement so that it would apply to 

non-jurisdictional entities and also 

would require small utilities to file 

Form 1, regardless of the reporting 

threshold. International Transmission’s 

proposal would unreasonably increase 

the reporting burdens on small utilities. 

Therefore, we reject the proposal. 

3. Affiliate Transactions 

56. To provide further transparency 

and improve the detection of crosssubsidization, the NOPR proposed to 

add a new schedule and page 429, 

‘‘Transactions with Associated 

(Affiliated) Companies,’’ providing 

information concerning affiliate 

transactions. The NOPR proposed that 

filers would report the following: (1) A 

description of the good or service 

charged or credited; (2) the name of the 

associated (affiliated) company; (3) the 

USofA account charged or credited; and 

(4) the amount charged or credited.38

Comments 

57. Several commenters support the 

proposal,39 and some include proposals 

to expand the reporting requirement.40

Others object to the affiliate transaction 

reporting requirement 41 or argue that 

such a requirement would be 

duplicative of other reporting 

obligations, unnecessary and 

burdensome.42

58. APPA supports the Commission’s 

proposal to add the new schedule to 

collect information on affiliate 

transactions. The Michigan Commission 

states that detailed descriptions of costs 

allocated to jurisdictional operations 

from affiliates are essential to detect 

cross-subsidization. It also requests 

clarification whether the Commission 

intends that an allocation for common 

facilities that are billed to one or more 

affiliates be reported as an affiliate 

transaction. The Michigan Commission 

requests that the Commission require 

additional detail, consisting of a 

description of all allocation factors used 

by the utility and its affiliates and an 

explanation of how ‘‘direct’’ and 

‘‘common’’ costs are defined and 

implemented. 

59. Nevada Companies states that 

affiliate transactions should be reported 

by type of service provided and goods 

transferred. The Nevada Companies 

note that reporting amounts by types of 

services provided would link this report 

to master service agreements entered 

into by many affiliated companies. They 

also request a definition of good or 

service. 

60. SDG&E recommends that the 

Commission clarify that the affiliate 

transaction information required to be 

provided is limited to transactions 

between a jurisdictional utility and its 

affiliates and does not include 

transactions solely between or among 

the affiliates. 

61. Nevada Companies requests that 

affiliate transaction information only be 

reported annually for companies that 

prepare similar information to fulfill 

state requirements, suggesting the 

proposed reporting requirement could 

be met by state oversight. AEP objects to 

an affiliate transaction reporting 


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43See also Nevada Companies comments. 

44SDG&E also supports a $250,000 reporting 

threshold for affiliate transactions. 

45 In particular, MidAmerican notes that it is 

bound to serve affiliates due to its provision of 

service to 2.5 million retail customers. 

MidAmerican argues that provision of service in 

accordance with a state-regulator-approved tariff 

precludes the opportunity for cross-subsidization or 

preferential service. MidAmerican states that the 

same holds true where MidAmerican purchases 

tariff services from an affiliate of its parent 

(Berkshire Hathaway). 

46Cross-Subsidization Restrictions on Affiliate 

Transactions, Order No. 707, 73 FR 11013 (Feb. 29, 

2008), FERC Stats. & Regs. ¶ 31,264, order on reh’g, 

Order No. 707–A, 73 FR 43072 (Jul. 24, 2008), FERC 

Stats. & Regs. ¶ 31,272 (2008); Blanket 

Authorization Under FPA Section 203, Order No. 

708, 73 FR 11003 (Feb. 29, 2008), FERC Stats. & 

Regs. ¶ 31,265, order on reh’g, Order No. 708–A, 73 

FR 43066 (Jul. 24, 2008), FERC Stats. & Regs. 

¶ 31,273 (2008). 47Citing NOPR at P 52. 

48 15 U.S.C. 79a, et seq. 

49 18 CFR Part 35. 

requirement and suggests that the issue 

is a state regulatory matter.43

62. Duke requests that the 

Commission clarify that the new page 

429 is not intended to require the 

reporting of affiliate transactions 

between the electric utility and 

centralized service companies, as this 

information is already reported in FERC 

Form No. 60 (Form 60). FirstEnergy 

states that the new page would result in 

a duplication of effort since the same 

information is already reported to the 

Commission in other FERC forms, 

including the Form 60, and other places 

in Form 1, such as page 332, 

Transmission of Electricity by Others 

and pages 326–327, Purchased Power. 

At a minimum, FirstEnergy requests that 

a set of parameters be established for 

reporting the information requested, and 

suggests filers be permitted to report the 

information by general category rather 

than by individual transactions. 

63. MidAmerican objects to detailed 

reporting of each affiliate transaction as 

unnecessarily burdensome and states 

that the information is already being 

provided in other publicly available 

documents. MidAmerican requests that 

the Commission limit any affiliate 

transaction reporting requirement and 

(1) establish an aggregate annual 

transaction reporting threshold of the 

greater of (a) $250,000 per affiliate or (b) 

one one-hundredth of one percent 

(.01%) of the electric utility’s operating 

revenues 44 and (2) exempt transactions 

based on regulator-approved tariffs.45

The Nevada Companies request that 

$100,000 be set as a reasonable 

minimum amount to report the transfer 

of a good, or an aggregate amount of 

service. 

64. EEI states that the affiliate 

transaction reporting proposal is 

inconsistent with the Commission’s 

decisions in Orders No. 707 and 708 not 

to require additional reporting.46

International Transmission and Nevada 

Companies object to an affiliate 

reporting requirement that would apply 

to transactions between regulated public 

utilities. International Transmission 

cites the Commission’s proposal that 

page 429 is to ‘‘provide further 

transparency and improve the detection 

of cross-subsidization.’’ 47 International 

Transmission states that a broad, onesize-fits-all requirement that includes 

reporting of transactions between 

affiliated regulated public utilities 

would not produce useful information 

for detecting improper crosssubsidization for the benefit of nonutility affiliates. International 

Transmission argues that the regulated 

affiliates’ Form 1 filings already provide 

ample transparency and that the affiliate 

transaction reporting requirement is 

therefore not necessary for affiliate 

transactions between regulated public 

utilities. 

Commission Determination 

65. Consistent with our natural gas 

reporting requirements established in 

Order No. 710, we will adopt the NOPR 

proposal and incorporate new page 429, 

Transactions with Associated 

(Affiliated) Companies. Consistent with 

the reporting threshold established in 

Order No. 710, the schedule instructions 

incorporate a $250,000 threshold for 

reporting individual transactions. While 

some commenters suggested alternative 

thresholds, we find that the threshold 

we adopt here reasonably balances the 

burden while still reporting needed 

information. Therefore, we will not 

adopt the suggested alternative 

proposals. 

66. In response to requests that the 

Commission specify the affiliated or 

associated company transactions to 

which new page 429 applies, we clarify 

that the schedule applies to all 

affiliated/associated company nonpower goods and services transactions 

including those with other regulated 

public utilities, centralized and other 

service companies, and other affiliated 

or associated companies providing nonpower goods and services to the 

respondent or receiving non-power 

goods or services from the respondent. 

However, we also clarify that page 429 

does not apply to transactions between 

affiliate or associate companies that do 

not include the respondent utility. 

67. We disagree with EEI that the 

‘‘affiliate transaction reporting proposal 

is inconsistent with the Commission’s 

decisions in Orders No. 707 and 708 not 

to require additional reporting.’’ We 

note that, although Order No. 707 did 

not adopt a reporting requirement, at the 

same time the NOPR in this proceeding 

alerted interested persons that the 

Commission was separately proposing 

the additional affiliate transaction 

reporting requirements that are adopted 

in this Final Rule. Order No. 707 was 

intended to update our rate filing 

regulations to reflect our expanded 

authority following the repeal of the 

Public Utility Holding Company Act of 

1935 (PUHCA 1935).48 In Order No. 

707, the Commission codified in its rate 

regulations 49 restrictions on affiliate 

transactions between franchised public 

utilities that have captive customers or 

that own or provide transmission 

service over jurisdictional transmission 

facilities, on the one hand, and their 

market-regulated power sales affiliates 

or non-utility affiliates, on the other. 

Order No. 707 addressed both power 

and non-power goods and services 

transactions between the utility and its 

affiliates and specifically power sales 

affiliates. This proceeding provides 

expanded affiliate/associate transaction 

reporting to facilitate monitoring 

affiliate/associate non-power goods and 

services transactions as part of a 

comprehensive proceeding to update 

our reporting requirements. Thus, while 

Order No. 707 did not expand reporting 

to implement the revised rate filing 

regulations adopted in the wake of the 

repeal of PUHCA 1935, this proceeding 

is based on the need for data to monitor 

on an ongoing basis utility rates to 

ensure that they remain just and 

reasonable. On the basis of the record in 

this proceeding, we find that the 

additional reporting requirement 

adopted here is appropriate because it 

will assist the Commission and the 

public in monitoring a utility’s rates. 

68. Order No. 708 adopted a blanket 

authorization permitting certain 

dispositions under section 203, such as 

the disposition of less than 10 percent 

of public utility voting securities to a 

holding company that does not thereby 

exceed certain voting interest 

thresholds. The requirements in Order 

No. 708 to report security dispositions 

made pursuant to blanket authorizations 

were designed to implement the new 

authorizations. Order No. 708 does not 

establish general reporting requirements 

or policies and the requirements 

established there are not relevant to the 

proposal adopted in this Final Rule. 

69. The Form 60 requirements are 

limited to total direct costs, total 

indirect costs and total costs of goods 

and services provided to each associate 

company by centralized service 


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50See 18 CFR 366.1; 18 CFR 367.1(a)(20) and (44); 

Repeal of the Public Utility Holding Company Act 

of 1935 and Enactment of the Public Utility Holding 

Company Act of 2005, Order No. 667, FERC Stats. 

& Regs. ¶ 31,197 (2005), order on reh’g, Order No. 

667–A, FERC Stats. & Regs. ¶ 31,213, order on reh’g, 

Order No. 667–B, FERC Stats. & Regs. ¶ 31,224 

(2006), order on reh’g, Order No. 667–C, 118 FERC 

¶ 61,133 (2007) (incorporating definitions from 

Securities and Exchange Commission, Public Utility 

Holding Company Act of 1935 Release No. 125 

(1936) (codified at 17 CFR 250.80)). 

51NOPR at P 56. 

52 18 CFR 41.11. 

53See, e.g., PacifiCorp, Docket Nos. AC00–20–000 

and AC00–20–001 (Apr. 14, 2000) (unpublished 

letter order). 

companies. The new reporting 

requirement provides more detailed 

information (in the form of individual 

transactions) about non-power goods 

and services provided by utilities to 

other affiliated/associated companies 

and non-power goods and services 

provided by affiliated/associated 

companies to utilities which is lacking 

in the Form 60 requirements. While the 

proposed Form 1 information 

requirement might be part of the total 

reported in Form 60, at least for 

transactions where centralized service 

companies provide non-power goods 

and services to the respondent utility, it 

is not duplicative. As compared to the 

other information in Form 1, we clarify 

that the new requirements apply only to 

non-power goods and services and thus 

do not apply to power sales. Therefore, 

we find that the new reporting 

requirements have not been shown to be 

duplicative of other requirements. 

70. The Michigan Commission 

requests clarification whether the 

Commission intends that an allocation 

of common facilities that are billed to 

one or more affiliates be reported as an 

associate/affiliate transaction. We clarify 

that apportionment of costs of a 

common facility should be reflected on 

page 429. Some examples of items that 

could be reported as an associate/ 

affiliate transaction include the amount 

of rent or property apportioned to a 

utility for a common building; the 

apportioned cost of a computer network 

along with costs to maintain such 

network, the apportioned cost of a 

garage used to house common trucks; 

the apportioned cost of phone networks 

and other phone costs. The allocation 

should also be disclosed as required in 

Instruction 3 of page 429 which requires 

the basis of the allocation. 

71. Nevada Companies requests that 

affiliate transaction information need 

only be reported annually for companies 

that prepare similar information to 

fulfill state requirements, suggesting the 

proposed reporting requirement could 

be met by state oversight. AEP objects to 

an affiliate transaction reporting 

requirement and suggests that the issue 

is a state regulatory matter. We disagree 

that this information is a state regulatory 

matter; the information is needed for 

monitoring Commission-jurisdictional 

rates. Also, more generally, not all states 

provide oversight. Furthermore, as 

noted above, this action is consistent 

with the Commission’s adoption of a 

similar requirement for natural gas 

companies in Order No. 710. 

72. International Transmission asserts 

that a broad, one-size-fits-all 

requirement that includes reporting of 

transactions between affiliated, 

regulated public utilities would not 

produce useful information for detecting 

improper cross-subsidization for the 

benefit of non-utility affiliates. While 

the Commission appreciates that 

additional requirements may be useful 

to address concerns in particular cases, 

the Commission believes that the 

reporting requirement adopted here will 

provide useful information and will aid 

in detecting improper crosssubsidization. 

73. We clarify, for purposes of page 

429, that by ‘‘goods’’ we mean any 

goods, equipment (including 

machinery), materials, supplies, 

appliances, or similar property 

(including coal, oil, or steam, but not 

including electric energy, natural or 

manufactured gas, or utility assets) 

which is sold, leased, or furnished, for 

a charge. Similarly, for purposes of page 

429, by ‘‘service,’’ we mean any 

managerial, financial, legal, engineering, 

purchasing, marketing, auditing, 

statistical, advertising, publicity, tax, 

research, or any other service (including 

supervision or negotiation of 

construction or of sales), information or 

data, which is sold or furnished for a 

charge.50 These definitions should 

address the concerns of commenters 

who are uncertain whether a particular 

charge or arrangement need be reported 

as an affiliate transaction. 

4. CPA Certification for a Non-Calendar 

Fiscal Year 

74. The NOPR noted that, although 

Form 1 is filed on a calendar year basis, 

some reporting companies operate on a 

non-calendar fiscal year. In response to 

comments describing the burden to 

prepare two sets of audited statements 

faced by companies that do not use a 

calendar fiscal year, the NOPR proposed 

to eliminate the burden by requiring 

public utilities using non-calendar fiscal 

years to continue to file annual reports 

each April, and file a certified set of 

financial statements following the end 

of the fiscal year.51 The second, certified 

set of financial statements is to be 

independently audited and 

accompanied by a certified public 

accountant (CPA) certification as 

required by the Commission’s 

regulations.52 This revision will permit 

non-calendar year public utilities to 

avoid duplicative audits. 

75. This approach is consistent with 

the Commission’s existing practice; i.e., 

the Commission’s historical practice of 

granting individual requests for waiver 

of the CPA certification requirement for 

Forms 1 and 1–F filers so long as the 

certification accompanies the fiscal 

year-end financial information filed 

after the annual Form 1 or 1–F is 

submitted.53

Comments 

76. No commenter objects to the 

proposal. EEI encourages the 

Commission to clarify that, with 

adoption of the NOPR’s proposed 

amendment to 18 CFR 41.11, companies 

will no longer need to seek a waiver, or 

if a company must continue to seek a 

waiver they need do so only once and 

the waiver would then apply in 

perpetuity barring a subsequent filing by 

the company or notice by the 

Commission. 

Commission Determination 

77. We adopt the NOPR proposal to 

revise § 41.11 to accommodate filing 

parties who follow accounting and 

reporting practices under which their 

fiscal year does not match the calendar 

year. Companies seeking waiver of the 

calendar-year independent accountant 

certification requirement must request 

authority to file the independent 

accountant certification based on their 

fiscal year information. Once the request 

is granted, however, we will not require 

the company to annually renew the 

request. Instead, the company must 

annually notify the Commission in 

writing at the time that it files its initial 

annual report that it will continue to file 

the certification based on fiscal year 

information (or is returning to a 

calendar year reporting). The 

certification for fiscal year companies 

must be filed no later than 150 days 

after the end of their fiscal year which 

is a period comparable to calendar year 

filers. 

5. ‘‘Other Revenues’’ (Pages 300–301) 

78. The NOPR proposed to expand the 

reporting of ‘‘Other Revenue’’ data 

referenced in pages 300 and 301 to 

enable the Commission and the forms’ 

users to achieve a meaningful 

understanding of the nature of the 

business activities from which the 


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54NOPR at P 57. NOI commenters coined the 

phrase ‘‘Other Revenue’’ to refer to the unspecified 

revenues referenced on pages 300 and 301. In 

response to comments on the NOPR proposal, the 

scope of the Other Revenue reporting requirement 

is more precisely defined in the discussion below. 

55 Id. 

56The New York Commission proposal is 

provided as line item 36 of Appendix B 

(corresponding to Appendix C of the NOPR). 

57Page 300 already tracks various specific sources 

of other revenue, including Forfeited Discounts 

(account 450), Sales of Water and Water Power 

(account 453), Rent from Electric Property (account 

454), Interdepartmental Rents (account 455), 

Revenues from Transmission of Electricity of Others 

(account 456.1) and Regional Control Service 

Revenues (account 457.1). These accounts are not 

subject to the additional reporting requirement (or 

the $250,000 reporting threshold). Page 300 also 

incorporates three general accounts, Miscellaneous 

Service Revenues (account 451), Other Electric 

Revenues (account 456), and Miscellaneous 

Revenues (account 457.2). 

revenues are derived.54 Greater detail 

concerning these revenue accounts 

could provide data that would enable 

the Commission and utility customers to 

identify revenues received by the filing 

companies and to understand how these 

transactions may affect the companies’ 

cost of service. To that end, the NOPR 

proposed to revise the instructions on 

page 300 to require that details of items 

included in Other Revenues be reported 

in a footnote to pages 300–301. 

79. Page 300 itemizes total electric 

operating revenues, composed of 

various types of sales of electricity 

(consisting of accounts 440–449), less 

provision for rate refunds, in addition to 

Other Operating Revenue. The data 

provided on page 300 on Other 

Operating Revenue includes accounts 

450 (forfeited discounts), 451 

(miscellaneous service revenues) and 

453–457.2 (including water and water 

power sales, rents, other electric 

revenues, regional control service 

revenues and miscellaneous revenues). 

Because Form 1 contains only a 

cumulative total for the reporting year of 

the various Other Revenues, the NOPR 

proposed that filers include a detailed 

breakdown of the various sources of 

other revenues in a footnote to page 300 

for any revenues not otherwise specified 

on pages 328–330, Transmission of 

Electricity for Others (including 

transactions referred to as ‘‘wheeling’’). 

80. Form 1 reports Total Other 

Operating Revenues (page 300, line 26), 

which include Revenues from 

Transmission of Electricity for Others 

(page 300, line 22, account 456.1). The 

details of account 456.1 are reported on 

pages 328–330, (Transmission of 

Electricity for Others (including 

transactions referred to as ‘‘wheeling’’)). 

The NOPR proposed two changes and 

requested comment. First, the NOPR 

proposed to revise the instructions on 

page 300 to require that for any 

revenues reported on line 26, excluding 

amounts reported on line 22, the filer 

must in a footnote report details on the 

other line items to page 300.55 Second, 

the NOPR asked for specific comment 

on a New York Commission proposal to 

clarify the instructions on pages 300– 

301 to indicate that delivery-only 

revenues shall be recorded as Other 

Electric Revenues (Account 456), while 

sales of electricity shall be recorded on 

a full-service basis (Accounts 440 

through 448), to reflect that the USofA 

does not unbundle electric operating 

revenues.56

Comments 

81. The New York Commission 

supports the proposal, stating that the 

Commission should require electric 

utilities to report other income and 

other income deductions in order to 

assess whether rates are just and 

reasonable. The Michigan Commission 

also supports the proposal, describing 

Form 1 as currently reporting a 

cumulative total for only two broad 

categories of revenue: ‘‘Revenue from 

Transmission of Electricity for Others’’ 

and ‘‘Other Electric Revenues.’’ The 

Michigan Commission requests that the 

Commission require filers to provide 

additional details, i.e., revenue for 

wholesale distribution, retail 

distribution, opportunity sales, and 

retail sales (with a breakout of bundled 

and customer choice sales); breakouts 

by state jurisdiction and rate schedule; 

and reporting of the value of ‘‘unbilled 

sales.’’ The Michigan Commission also 

requests that the Commission require a 

breakout of ‘‘Revenue from 

Transmission for Others’’ by rate 

schedule. 

82. Nevada Companies suggest 

$500,000 as a reasonable minimum 

threshold for reporting Other Revenues 

and also suggests, as with affiliate 

transactions, that the items be reported 

by category and not by transaction. 

83. EEI requests that the Commission 

clarify that the requirement for 

additional details on page 300 applies 

only to FERC account 456, Other 

Electric Operating Revenues, and 

specify whether the requirement applies 

to account 457.2, Miscellaneous 

Revenues used by RTOs and ISOs. EEI 

requests that the Commission establish 

a threshold of $500,000 or 10 percent of 

the balance in the FERC account, 

whichever is greater. 

84. Duke is opposed to the 

Commission’s proposal to add a 

footnote to page 300 in order to provide 

users with additional detail related to 

all Other Revenues not otherwise 

specified on pages 328–330, arguing that 

the benefit from the proposed 

requirement is outweighed by the 

additional burden placed on filers. Duke 

proposes that any breakout requirement 

should only apply to the two accounts 

that are truly ‘‘miscellaneous’’ in nature, 

account 451, Miscellaneous Service 

Revenues, and account 456, Other 

Electric Operating Revenues, and 

should only require categorization of the 

types of charges included in these two 

accounts. 

85. FirstEnergy objects to the New 

York Commission’s proposed revision. 

FirstEnergy generally notes that 

reporting practices should follow 

accounting practices. If, however, the 

Commission is proposing a change in 

accounting practice, FirstEnergy 

submits that this proceeding is not the 

appropriate forum to propose such a 

change, which should be addressed in a 

separate rulemaking preceding that does 

not relate solely to proposals on 

reporting requirements. 

86. APPA supports the proposal to 

clarify the pages 300–301 instructions to 

distinguish unbundled, delivery-only 

transactions from the remainder of the 

transactions and provide consistency in 

filer data. Cogentrix supports the New 

York Commission proposal that 

delivery-only revenues be recorded in 

Other Electric Revenues (account 456), 

while sales of electricity (including 

bundled sales) be recorded in accounts 

440 through 448. 

Commission Determination 

87. In this Final Rule, we adopt the 

NOPR proposals to revise the 

instructions on pages 300 and 301. 

Several commenters requested 

clarifications to the scope of the 

additional reporting requirement for 

Other Revenues. In response, we clarify 

that a filing company shall provide in a 

footnote information on ‘‘any revenues’’ 

not otherwise specified in the 

breakdowns of Other Revenues 

provided on page 300 or on pages 328– 

330.57 The Commission clarifies that the 

information provided on these pages 

should be comprehensive, meaning that 

any and all revenues should be 

described for each source of income in 

the same degree of detail as for the 

specific items for which a breakout is 

already required. For example account 

456, Other Electric Revenues would 

include, among other items, commission 

on sale or distribution of electricity of 

others when sold under rates filed by 

such others; compensation for minor or 

incidental services provided for others 

such as customer billing, engineering, 


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58See Order No. 710–A at P 7. 59NOPR at P 60. 60See AEP, EEI, and FirstEnergy comments. 

etc.; profit or loss on sale of material; 

and supplies not ordinarily purchased 

for resale and not handled through 

merchandising and jobbing accounts. 

The Commission anticipates that the 

additional information should provide 

details on the amounts included in the 

general accounts (account 451, 

Miscellaneous Service Revenues, line 17 

of page 300; account 456, Other Electric 

Revenues, line 21; and account 457.2, 

Miscellaneous Revenues, line 24) and 

that such reporting, along with the 

detail on page 300, should account for 

all sources of the filing company’s other 

revenue. 

88. In the NOPR, the Commission did 

not propose a threshold for disclosing 

‘‘Other Revenues.’’ Nevada Companies 

suggest $500,000 as a reasonable 

minimum threshold guideline for 

reporting Other Revenues. EEI requests 

that the Commission establish a 

threshold of $500,000 or 10% of the 

balance in the USofA account, 

whichever is greater. Consistent with 

the statements the Commission made in 

Order No. 710–A when adopting the 

threshold amounts for grouping natural 

gas items, we find that the absence of a 

minimum threshold could add a 

substantial burden to the forms’ filers.58

We find that an alternative threshold of 

$250,000 is reasonable and not unduly 

burdensome, and will, nevertheless, 

provide meaningful data to this 

Commission, state commissions, and 

customers. We also note that the 

threshold here is consistent with that 

used in FERC Form No. 2 (Form 2). In 

keeping with this analysis, the 

Commission adopts a minimum 

threshold of $250,000 per source of 

income, consistent with the amounts 

reported on page 308 of Form 2, which 

reports other operating revenues. 

89. The Michigan Commission 

requests that the Commission require 

filers to provide additional breakouts of 

revenue for wholesale distribution, 

retail distribution, opportunity sales, 

and retail sales (with a breakout of 

bundled and customer choice sales); 

breakouts by state jurisdiction and rate 

schedule; and reporting of the value of 

‘‘unbilled sales.’’ Michigan Commission 

also requests that the Commission 

require a breakout of ‘‘Revenue from 

Transmission for Others’’ by rate 

schedule. The requests by Michigan 

Commission would require changes to 

the Commission’s accounting 

requirements. We are not prepared to, 

and did not propose in the NOPR to, 

revise our accounting requirements at 

this time; the Michigan Commission 

proposals are beyond the scope of our 

original proposal and so we decline to 

adopt them at this time. 

90. With regard to commenters’ 

suggestions that a delivery-only 

transaction be separately disclosed, 

rather than included in electric sales 

(accounts 440–447), such an accounting 

requirement would require revision to 

the USofA, which is beyond the scope 

of this proceeding and which we 

decline to do at this time. Therefore, we 

will not require companies to separate 

out delivery-only transactions in their 

Form 1. 

6. Increases to Threshold Reporting 

Levels 

91. The NOPR found that it is 

reasonable to increase certain threshold 

levels for reporting specific cost items 

and invited comment. Specifically, the 

NOPR proposed to increase the 

threshold reporting levels for (i) page 

216 (Construction Work in Progress) to 

$1 million, (ii) pages 232, 233 and 278 

(Other Regulatory Assets, Miscellaneous 

Deferred Debits and Other Regulatory 

Liabilities) to group items featuring an 

aggregate outstanding balance of 

$100,000 or less, (iii) page 269 (Other 

Deferred Credits) to $100,000, and (iv) 

pages 352 and 353 (Research and 

Development) to $50,000.59

Comments 

92. Several commenters support the 

proposals to increase the threshold 

reporting levels.60 BPA, however, states 

that Form 1 should contain more 

information and detail rather than less 

and that no accounts or level of detail 

should be removed from the current 

Form 1 requirements. Duke and Nevada 

Companies each proposes alternative 

thresholds as detailed in the following 

table. 

Page No. Title of schedule NOPR proposal Duke Nevada companies 

1 ............... 216 ......................... Construction Work in 

Progress—Electric 

(Account 107).

$1,000,000 or less may 

be grouped.

Graduated scale based 

on total assets base.

Report projects 

$10,000,000 or more. 

2 ............... 232 ......................... Other Regulatory Assets 

(Account 182.3).

Amounts less than 

$100,000 may be 

grouped by classes.

$1,000,000, or a graduated scale based on 

total asset base.

$1,000,000. 

3 ............... 233 ......................... Miscellaneous Deferred 

Debits (Account 186).

Amounts less than 

$100,000 may be 

grouped by classes.

$1,000,000, or a graduated scale based on 

total asset base.

$1,000,000. 

4 ............... 269 ......................... Other Deferred Credits 

(Account 253).

Amounts less than 

$100,000 may be 

grouped by classes.

$1,000,000, or a graduated scale based on 

total asset base.

$100,000. 

5 ............... 278 ......................... Other Regulatory Liabilities (Account 254).Amounts less than 

$100,000 may be 

grouped by classes.

$1,000,000, or a graduated scale based on 

total asset base.

$1,000,000. 

6 ............... 353 ......................... Research, Development, 

and Demonstration Activities.

Group items under 

$50,000.

Graduated scale based 

on total asset base.

n.a. 

Commission Determination 

93. We are not persuaded to adopt the 

alternate thresholds or graduated 

reporting requirements proposed by 

some commenters. The Commission 

believes that the proposed thresholds 

are reasonable and not unduly 

burdensome. The thresholds balance the 

burden on utilities, and, in fact, in 

raising the thresholds, lessen the burden 

while continuing to provide meaningful 

data to this Commission, state 

commissions, and customers that wish 

to review a utility’s rates. Furthermore, 

the uniformity of the reporting 


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61Filers that use Form 1 to meet more specific 

reporting requirements for incentive rate treatment 

for construction work in progress (CWIP) or other 

costs must continue to meet the obligations arising 

with the approval of such incentive rates, despite 

these thresholds. Cf., e.g., Potomac-Appalachian 

Transmission Highline, LLC, 122 FERC ¶ 61,188, at 

P 155–56 (2008); Trans-Allegheny Interstate Line 

Co., 119 FERC ¶ 61,219, at P 45 (2007) (requiring 

reporting of financial details in Form 1 footnotes as 

condition of approval for CWIP rate incentive). 

62An additional proposal concerning consistency 

in distinguishing delivery revenues and electricity 

sales (pages 300–301) has already been addressed 

in the discussion of Other Revenues, above. 

63BPA and FirstEnergy also generally support the 

corrections. 

64AEP supports the software improvements 

proposed by EEI to enable them to load data 

efficiently into the FERC software. 

65To facilitate reporting, we will revise the 

software so that a total can be entered on line 8, 

columns (b) and (e), number of units, if filers wish 

to use a standard unit of measure (otherwise there 

will be no total). 

66This feature can be accomplished by entering 

either ‘‘Subtotal’’ or ‘‘Total’’ as the first characters 

in column (a), which will result in the system 

calculating values for other columns, accordingly. 

requirement helps ensure that 

comparable data is available for all 

major utilities. Therefore, we adopt the 

revised reporting thresholds proposed 

in the NOPR61 and reject the alternative 

threshold reporting levels and proposals 

for graduated reporting requirements. 

7. Proposed Technical Corrections 

94. In response to the NOI, the 

Commission received a number of 

suggested technical changes and 

instruction revisions. The Commission 

listed the suggestions that showed merit 

in the NOPR, Appendix C and invited 

comment on specific proposals. The 

proposals are reproduced in Appendix 

B to this Final Rule along with the 

Commission’s responses. The NOPR 

specifically sought comment on the 

proposals in Appendix C, line 25 (RTO 

accounting on pages 310–311, 326–327, 

332, 397–398), line 32 (measuring sales 

for resale as financial transactions, 

pages 310 and 326), line 34 (designating 

reporting hours and accounting for 

financial transactions, page 401A), and 

line 35 (utility of column (b), pages 301 

and 326).62

Comments 

95. SDG&E believes many of the 

proposed revisions and technical 

corrections are appropriate and provide 

needed information for rate review 

without imposing undue burdens on the 

filer.63

96. In regard to the proposal to 

measure sales for resale as financial 

transactions (pages 310 and 326) on line 

32 of Appendix C, APPA supports 

providing guidelines on how to report 

volume information on the sales for 

resale and purchased power schedule 

on pages 310 and 326. The proposal 

asks the Commission to address the 

reporting of financial transactions; 

APPA believes that the Commission 

should also address the reporting of 

negative volumes on these schedules. 

Commission Determination 

97. The comments received did not 

offer specifics in response to the NOPR 

requests for comments on the proposals 

in Appendix C, line 25 (RTO accounting 

on pages 310–311, 326–327, 332, 397– 

398), line 34 (designating reporting 

hours and accounting for financial 

transactions, page 401A), or line 35 

(utility of column (b), pages 301 and 

326). In addition, with respect to 

APPA’s proposal to address reporting of 

negative volumes, we decline to adopt 

such a proposal at this time; APPA has 

not adequately explained how negative 

volumes arise in purchase or sales 

transactions. Due to the lack of specific 

proposals, the Commission will not 

implement the remainder of these 

changes at this time. In addition, for 

Appendix C, line 32, no commenter 

provided a specific proposal for 

reporting volume information; 

consequently, we will not revise our 

reporting requirements at this time. 

8. Additional Technical Revisions 

98. EEI’s comments include a number 

of additional suggested improvements, 

clarifications and corrections to the 

forms and software: (1) General—on 

various pages, EEI requests the 

Commission to ensure that all data, 

descriptions, and amounts roll over 

from one period to the next, to avoid 

companies having to re-enter the data; 

(2) General—standardize the number 

formats used to represent credits 

throughout the form—for example, on 

page 119, column (c), the format is 

‘‘¥50,500,’’ while in column (d) the 

format is ‘‘(50,500);’’ (3) pages 120– 

121—EEI requests a correction to ensure 

that all footnotes print to identify which 

column is involved when footnotes are 

added to columns (b) or (c); (4) pages 

122a–122b and 231–EEI requests the 

instructions be revised to reflect 

Commission staff guidance that these 

schedules are to be presented on a yearto-date basis; (5) pages 122a–122b—EEI 

requests the row heights on the two 

pages be adjusted to be the same, 

making information easier to follow; (6) 

pages 329–330—EEI states that the page 

title should reference account 456.1, not 

456; (7) pages 352–353—correct the 

printing parameters so that the dollars 

for line 47 print on the same page as the 

description for that line; (8) page 398— 

clarify whether a standard unit of 

measure should be applied to Number 

of Units Sold in column (e), and, if not, 

how dissimilar units of measure are to 

be totaled on line 8; and (9) pages 426– 

427—the Form 1 submission software 

(FOSS) should calculate totals for 

column (f) by Substation Classification. 

99. In addition, EEI supplements the 

technical revisions proposed in the 

NOPR and requests that the Commission 

address the following issues: 64 (a) The 

ability to load data more cleanly into the 

software, including Excel data; (b) the 

ability to copy and paste information 

from Microsoft Word and other nativeformat documents without losing 

formatting such as underlines, 

paragraphs, and headers; (c) the ability 

to print preview for Notes to Financials 

and Important Changes pages; (d) 

corrections to the ‘‘total amount’’ 

functions in the software, in particular 

on pages 224, 320–323, 336, 354–355; 

(e) corrections to improper page 

references, in particular on pages with 

footnotes; (f) corrections to the 

software’s cross-checking function; and 

(g) corrections to text on various pages 

of the forms, as noted in NOI comments. 

Commission Determination 

100. With respect to EEI’s new 

suggestions, the Commission confirms: 

(1) The copy forward feature is available 

for many page schedules, and if 

additional pages need such a feature, 

filers may make requests to 

ferconlinesupport@ferc.gov (copying on 

these pages is an option and not 

mandated); (2) the printing of negative 

numbers on page 119, column (d) will 

be corrected; (3) the footnote printing 

issues on pages 120–121 will be 

addressed; (4) the instructions on pages 

122a, 122b and 231 will be updated; (5) 

the row heights on pages 122a and 122b 

will be changed, as requested; (6) the 

page title on pages 329 and 330 will be 

corrected (consistent with page 328); 

and (7) printing parameters on pages 

352–353 will be corrected to address 

text continuity. As for the two 

remaining suggestions from the list, we 

clarify: (8) that a standard unit of 

measure on page 398 is not appropriate, 

because the unit of measure should 

instead be that used in the filer’s billing 

determinants; 65 and (9) consistent with 

EEI’s request the software already 

permits filers to calculate totals on 

pages 426–427, column (f) by 

substation.66

101. With respect to EEI’s request that 

the Commission ensure compatibility 

between the Form 1 reporting software 

and commonly used commercial 

products such as spreadsheet, word 

processing and accounting software, the 


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67Absent reference to particular pages, the 

Commission is unable to address EEI’s remaining 

request that the Commission correct unspecified 

improper page references and footnotes. 68NOPR at P 61. 

69See generally Connecticut Light and Power Co., 

2 FPC 853 (1944). 

70See PECO Energy Co., et al., 88 FERC ¶ 61,330 

(1999); Consolidated Edison Co., 72 FERC ¶ 61,184 

(1995). See also Alabama Power Company v. FPC, 

511 F.2d 383, 390–91 (DC Cir. 1974) (upholding 

fuel purchases reporting requirement, and rejecting 

claims that disclosure would lead to bargaining 

disadvantages in future fuel contract negotiations as 

outweighed by benefits of disclosure). 

Commission is mindful of the continual 

upgrading of commercial software and 

strives to ensure that the Commission’s 

forms can accommodate the changes. 

However, we note that several 

comments concerning the eForm 

software (FOSS) appear to be based on 

a misunderstanding of the software’s 

capability. The Commission encourages 

filing companies to contact the 

Commission’s Online Support (via email or phone) to resolve technical 

issues concerning the FOSS software. 

Through calls to Online Support, issues 

may be addressed in a direct and timely 

manner that is specific to an individual 

filing company’s concerns. In this 

manner, the Commission, the regulated 

entities, and the public in general will 

be best and most efficiently served. 

102. As to the specific issues 

described in the comments, the 

Commission notes that the software 

incorporates the ability to import data 

from any spreadsheet program 

(including Excel or Open Office) that is 

able to export the data using the ‘‘dbf’’ 

format. Many schedules support this 

capability and also support (but do not 

require) data roll-over from past reports. 

If importing or data roll-over capability 

is desired for other pages, filing 

companies should contact 

ferconlinesupport@ferc.gov. In addition, 

the software includes the capability to 

import word processing files in the 

Word format into Form 1, Notes to the 

Financial Statements. It is possible 

compatibility issues with specific 

versions of word processing software 

(such as Microsoft Word) may result in 

some formatting being lost. Users 

experiencing technical difficulties may 

contact the Commission at 

ferconlinesupport@ferc.gov. The 

software also features print preview 

capability and data roll-over functions. 

As for corrections to the ‘‘total amount’’ 

functions on various pages, we have 

been unable to duplicate the errors 

referred to in the comments. If a filing 

company is having difficulty with a 

particular calculation, assistance is 

available by contacting 

ferconlinesupport@ferc.gov. Finally, 

steps have been taken to include data 

cross-checking in the 2008 Form 1 

submission software, and we will make 

corrections to the text on various pages 

of the forms to address EEI’s suggested 

editorial changes.67

E. Miscellaneous 

1. Retaining Form 3–Q 

103. In the NOPR, we rejected 

requests that the Commission eliminate 

Form 3–Q as being unnecessary. The 

Commission believes that the quarterly 

reports are important because they 

allow more timely evaluations of 

existing rates and improve the 

transparency and currency of financial 

information. 

Comments 

104. AEP, EEI, and Nevada 

Companies suggest that the Commission 

reconsider whether the burden of 

completing the Form 3–Q is warranted 

when compared to the limited value of 

data it provides. 

Commission Determination 

105. We decline to adopt this change 

for the reasons stated in the NOPR: 68

The Commission believes that the 

increased frequency of financial information 

provided in Form 3–Q is important. The 

quarterly reports allow for more timely 

evaluations of existing rates and improve the 

transparency and currency of financial 

information submitted to the Commission. 

106. The comments provide no 

compelling reason to eliminate Form 

3–Q. 

2. Confidentiality Concerns 

107. In response to NOI comments, 

the NOPR rejected calls that certain 

financial data should be considered 

confidential because of concerns raised 

regarding competitive risks and harm to 

critical infrastructure. The NOPR 

affirmed the Commission’s commitment 

to maintaining the public availability of 

financial data filed in Form 1 and other 

reports and found that additional 

precautions or protection of financial 

data are not necessary. 

Comments 

108. APPA commends the 

Commission for continuing to improve 

its collection of financial data and for its 

commitment to maintaining the public 

availability of the data. AEP 

recommends the Commission 

reconsider its position and cease to 

require the release of what it 

characterizes as competitively sensitive 

commercial information to potential 

competitors that could disadvantage 

sellers in competitive markets. 

109. EEI encourages the Commission 

to protect commercially sensitive 

information, in the interest of promoting 

fair competition and the development of 

robust competitive markets. EEI further 

encourages the Commission to 

reconsider its handling of commercially 

sensitive information in the financial 

forms, to ensure that information is not 

released at a plant or company level if 

such information may harm companies, 

either in their competition with others 

or in their negotiations with suppliers. 

In particular, EEI requests, as it has 

done in previous efforts to revise the 

reporting requirements that the 

Commission cease releasing in discrete 

form individual generating plant costs 

and operating performance information, 

and instead release such information 

only in aggregated form that, according 

to EEI, avoids commercial harm. 

Commission Determination 

110. As stated in the NOPR and 

elsewhere, the Commission remains 

committed to the public availability of 

cost-of-service data for public utilities. 

Since 1937, Form 1 data have provided 

a critical component of the 

Commission’s regulatory program and 

that of its predecessor, the Federal 

Power Commission.69 While the 

electricity market is changing, regulated 

public utilities still provide 

jurisdictional power and transmission 

services for which information is 

needed in connection with the 

Commission fulfilling its statutory 

responsibilities. Because transmission 

service is a critical component in 

electricity service and most 

transmission rates are cost-based, Form 

1 data are critical to evaluating the 

underlying costs of providing 

transmission service and the resulting 

rates. In addition, Form 1 data provide 

the basis for many rates for generation 

service (both cost-based and marketbased), which may be determined on a 

unit by unit basis. Making this cost data 

publicly available provides customers 

with a means to monitor the 

reasonableness of their rates, and thus 

assists the Commission’s efforts to 

ensure that rates remain just and 

reasonable. The Commission also has 

previously reviewed and rejected 

suggestions that it should adopt nonpublic status for Form 1 data.70

Consistent with our long-standing 

precedent, and in light of the 

commenters’ failure to convince us 


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71See NOPR at P 14 (summarizing Duke’s 

comments responding to the NOI). 

72 Duke comments at 5. Pages 422–425, col. (a) 

and (b) provide information on transmission lines 

(132 kV and above), which are designated as 

running ‘‘from’’ location A ‘‘to’’ their destination at 

location B. Transmission lines below 132 kV are 

grouped together by voltage. 73NOPR at P 35. 74Order No. 710 at P 38. 

otherwise, we decline to adopt nonpublic status for such data here. 

3. Requests To Reconsider Rejected 

Revisions 

111. Duke suggests that the 

Commission misconstrued its proposal 

in Docket No. RM07–9–000, proposing 

to eliminate the requirement to report 

executive officers’ salaries on page 104 

and argues that the information is not 

relevant and may be obtained 

elsewhere.71 Duke also renews its 

objection that the requirement to 

footnote amounts reported in pages 

328–330, column (m), is unduly 

burdensome, because the detail largely 

concerns ancillary services data and 

filers must insert repetitive footnotes 

that do little to further the user’s 

understanding of the charges. 

112. Further, Duke believes the 

Commission misinterpreted Duke’s 

suggested revisions related to pages 

422–425. Duke does not request 

eliminating the pages, but states rather 

that it is proposing a means by which 

the burden on the filer could be 

reduced, without diminishing the 

usefulness of the data reported. Duke 

believes that reporting miles of 

transmission lines by state and legal 

entity, as well as the totals of the 

different type of supporting structures 

by voltage, would be sufficient and far 

less burdensome for filers than current 

practice. Duke questions the claim, cited 

in the NOPR, stating that pages 422–425 

(as well as pages 426 and 427) provide 

valuable information on transmission 

lines and substations that allows 

commenters to track rate base amounts 

on a facility-by-facility basis. Duke 

disagrees and questions the necessity of 

the ‘‘to’’ and ‘‘from’’ level of detail.72

According to Duke, the necessary data 

to calculate transmission rates for RTO 

members that file Form 1 is already 

largely available in various RTO filings 

or available upon request. Second, Duke 

states that the ‘‘to’’ and ‘‘from’’ level of 

detail for filers that are not members of 

RTOs is insignificant because 

transmission rates for these filers are 

based on average system cost. 

113. Duke proposes that the 

information contained on pages 426 and 

427 be updated in its entirety every 

three years, and that in all other years 

a filer only be required to report 

additions, retirements and changes to 

the substations. Duke believes that 

typically there are few changes year-byyear to the amount of information 

presented on pages 426 and 427. 

According to Duke, this change would 

be beneficial not only to filers, but also 

to users because the changes would be 

more apparent to users. 

114. APPA supports the 

Commission’s determination that pages 

422–423 and 426–427 should remain in 

Form 1. BPA states that Form 1 should 

contain more information rather than 

less, and that no accounts or level of 

detail should be removed from the 

current Form 1 requirements. 

Commission Determination 

115. The Commission affirms its 

decision to retain the existing 

requirements. The information is useful 

to the Commission’s oversight, and is 

relied upon for the monitoring, review 

and modification of rates. The 

Commission disagrees that alternate 

approaches of seeking the information, 

i.e., on request or seeking comparable 

information in various rate, tariff and 

informational filings, are a substitute for 

consistent and uniform reporting of the 

data in Form 1. The Form 1 format 

ensures that the data is available, is 

consistent from year to year and is 

comparable among filing utilities. In 

addition, this information is valuable 

because of the increasing demand, and 

accompanying scrutiny, being placed on 

the transmission grid; there is a 

continuing need for information to 

assess changes and improvements (both 

existing and new) to transmission 

infrastructure. 

4. Requests for Additional Cost Data 

116. In the NOPR, we rejected 

requests for the collection of additional 

Form 1 data, finding that additional 

detail may be unnecessary. In light of 

the comments received and given the 

Commission’s experience with reporting 

requirements, the Commission 

determined that wholesale changes to 

Form 1 were unnecessary especially in 

light of the targeted changes proposed. 

Therefore, the NOPR did not propose 

that filers provide a cost and revenue 

study or the type of detailed information 

needed in a rate case, or detailed 

information on pensions and other 

employment benefits.73

Comments 

a. Pension Information 

117. The New York Commission 

renews its request that the Commission 

require electric utilities to file 

information regarding pensions and 

other employee benefits in order to 

assess whether rates are just and 

reasonable, and states that this need 

outweighs the burden of imposing an 

incremental reporting requirement upon 

utilities. The New York Commission 

indicates that the Commission’s 

proposal appears inconsistent with its 

position in Order No. 710. 

b. Transmission Investment 

118. The Michigan Commission 

requests that the Commission clarify 

whether additional detail on new 

transmission plant in service is 

required. TAPS proposes that the 

Commission require subdivision of 

account 353 in order to distinguish 

account 353 costs associated with the 

transmission and generator step-up 

functions. This requirement would 

apply irrespective of whether a Form 1 

filing utility uses a formula rate. TAPS 

states that for the Form 1 to work as a 

basis for a preliminary rate assessment 

and serve its other rate-regulatory 

purposes, it should break out the costs 

of facilities associated with generator 

step-up transformation and report any 

methodology used to divide account 353 

between the transformation and 

transmission functions. According to 

TAPS, the Commission’s accounting 

practices should reflect rate 

functionalization for both stated and 

formulaic rates so that customers and 

regulators may monitor rates and 

understand how the utility 

functionalizes costs. 

Commission Determination 

119. Contrary to the New York 

Commission’s view, our decision to rely 

on existing reporting requirements with 

respect to pension information in this 

proceeding is not inconsistent with our 

determination in Order No. 710. In that 

proceeding, which adopted changes to 

our reporting requirements in Form 2 

for gas pipelines, we found that 

insufficient information was available 

because details about the types and 

costs of employee benefits were not 

readily available due to the pipelines’ 

participation in multi-employer benefit 

plans in which they are assigned a 

portion of the total cost and there was 

flexibility in the way in which 

information was described in a footnote 

disclosure.74 However, in contrast, there 

was no evidence of a widespread 

impediment to understanding public 

utilities’ pension obligations. Therefore, 

we will not impose similar reporting 

requirements here, but instead will rely 

on our existing reporting requirements. 


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75NOPR at P 66. 

76EEI cites 44 U.S.C. 3501, et seq. 

77EEI states that the Paperwork Reduction Act 

requires each agency to undertake a triennial review 

in consultation with the Office of Management and 

Budget (OMB) to demonstrate that information 

collections are as reasonable and streamlined as 

possible. EEI comments at 2–3. 

78EEI estimates that the proposed affiliate 

transaction schedule alone would require on the 

order of 100 to 300 hours per company to compile 

in the proposed format. AEP similarly argues that 

the affiliate transaction reporting would be 

voluminous and burdensome. 

79See EEI comments at 6. 

80EEI comments at 10. 

81The Commission does not object so long as the 

service is ongoing, and is not undertaken in 

response to a particular, non-recurring event. 

82 44 U.S.C. 3507(d). 

120. As stated in the NOPR, we are 

not persuaded to expand the scope of 

this proceeding, as would be necessary 

to grant TAPS’ request to revise our 

accounting requirements and provide in 

this Final Rule the additional 

information requested. This 

determination is consistent with our 

holdings elsewhere in this Final Rule 

with respect to requests for additional 

information related to formula rates and, 

in particular, transmission investment. 

F. Reporting Burden 

121. In the NOPR, the Commission 

estimated that the proposed new 

affiliate transaction and other 

information will take respondents 14 

hours to collect and report on an 

average annual basis per respondent.75

Comments 

122. EEI comments that, recognizing 

that reporting does involve substantial 

costs, the Paperwork Reduction Act 

(PRA) requires federal agencies to strive 

to minimize the reporting burden and 

avoid duplicative reporting 

requirements.76 In prior triennial 

reviews, EEI has asked the Commission 

to review the Forms 1, 1–F, and 3–Q as 

well as other FERC forms to determine 

if all the information contained in the 

forms is truly needed and whether it is 

needed in as much detail.77 EEI 

reiterates that general request here and 

encourages the Commission to minimize 

the reporting burden to the maximum 

extent possible. 

123. Duke estimates a burden greater 

than 14 hours to meet the requirements 

associated with the proposed Form 1, 

page 429 alone; similarly, EEI suggests 

that compiling the proposed affiliate 

transaction information will take longer 

than 14 hours.78 MidAmerican suggests 

that the proposed Form 1 affiliate 

transaction reporting requirement is 

duplicative of existing federal and state 

affiliate reporting requirements. 

124. SDG&E on the other hand 

believes that the proposed revisions to 

the financial reporting obligations in the 

NOPR generally are appropriately 

balanced to fulfill the Commission’s 

stated goal of obtaining necessary 

information without imposing undue 

burdens on the filer. 

Commission Determination 

125. The Commission’s estimate of 

the reporting burden refers to the 

Commission’s estimate of the additional 

amount of time needed to comply with 

the Form 1 revisions on an annual basis, 

over and above the time needed to 

prepare the Form 1 under existing 

requirements. Thus, while the 

Commission is sensitive to filing parties’ 

individual expectations that becoming 

familiar with the new reporting 

requirements, compiling and reporting 

certain information may initially take 

more time than the annual estimate, 

these parties will not need to invest a 

similar effort in subsequent years. 

Furthermore, the revisions adopted in 

this Final Rule are not extensive, and 

largely consist of material that is already 

required to be maintained for other 

purposes. Therefore, although the initial 

preparation to meet new reporting 

requirements established in this Final 

Rule may be greater, the Commission 

believes that the total increase in the 

time to meet all of the Form 1 

requirements, existing as well as those 

adopted in this rule, is not unduly 

burdensome. Furthermore, the Final 

Rule also relieves some parties of their 

reporting obligations, and lessens the 

reporting burden for all parties through 

the increase in the threshold reporting 

requirements for certain items. 

126. FirstEnergy, AEP, MidAmerican, 

and SDG&E comment on the estimated 

burden of the affiliate transaction 

reporting requirement; however, they do 

not offer an alternative estimate. 

Likewise, International Transmission 

and MidAmerican challenge the total 14 

hour estimate but fail to offer alternative 

estimated burden hours. 

127. While Duke cites how they 

would have to review 187,700 lines of 

accounting related to transactions for its 

four respondent companies, Duke does 

not specify what such a ‘‘review’’ would 

entail, nor what the estimated burden 

would be. Nevada Companies argue that 

40 hours per quarter would be needed 

or 160 hours annually for the affiliate 

transaction reporting requirement. EEI 

states it would take anywhere from 100 

to 300 hours, according to its members, 

to fulfill the affiliated transaction 

requirement. 

128. In response to Nevada 

Companies’ burden estimate, the 

Commission notes that the Final Rule 

only requires a reporting of transactions 

on an annual basis, not quarterly. 

Therefore, we believe that Nevada 

Companies’ have overestimated the 

amount of time needed to comply with 

the requirements. In addition, EEI’s 

estimate likewise appears to be 

excessive and does not take into account 

clarifications made in this Final Rule. 

EEI makes several assumptions that 

have been resolved in a manner that 

would significantly decrease its 

estimate, including: (1) Similar to 

Nevada Companies, EEI assumes that 

the revised reporting requirements are 

to be met on a quarterly basis, while the 

Final Rule largely imposes annual 

reporting requirements;79 (2) EEI 

assumes that power transactions are 

included, while the Final Rule clarifies, 

that power transactions are excluded 

from the new page 429 affiliated 

transaction reporting requirement; 80 (3) 

EEI requests reporting by service type 

category rather than by transaction; 81

and (4) EEI’s estimate does not account 

for the $250,000 affiliate transaction 

reporting threshold of transaction/ 

service type adopted in response to 

comments. In response to concerns 

raised by the commenters, however, the 

Commission has adjusted its estimate as 

reflected below. 

VI. Information Collection Statement 

129. The collections of information 

contained in this Final Rule have been 

submitted to the Office of Management 

and Budget for review under section 

3507(d) of the Paperwork Reduction Act 

of 1995; 82 the Commission is revising 

the reporting requirements for public 

utilities and licensees (and for Form 3– 

Q, also natural gas companies) 

contained in the above financial and 

operational information collections. 

Title: FERC Form No. 1, ‘‘Annual 

Report of Major Electric Utilities, 

Licensees, and Others’’; FERC Form No. 

1–F, ‘‘Annual Report for Nonmajor 

Public Utilities and Licensees; FERC 

Form No. 3–Q, ‘‘Quarterly Financial 

Report of Electric Utilities, Licensees, 

and Natural Gas Companies.’’ 

Action: Final Rule. 

OMB Control Nos. 1902–0021 (Form 

1); 1902–0029 (Form 1–F); 1902–0205 

(Form 3–Q). 

Respondents: Businesses or other for 

profit. 

Frequency of responses: Annually and 

quarterly. 

Necessity of the information: The 

information collected under the 

requirements of Part 141 is essential to 

the Commission’s fulfilling its statutory 

responsibilities under the FPA. The 

information collected is used in 


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83These numbers are based on the most recent 

filings. 

84See Regulations Implementing the National 

Environmental Policy Act of 1969, Order No. 486, 

FERC Stats. & Regs. ¶ 30,783 (1987). 

85See 18 CFR 380.4(a)(5). 

86See 18 CFR 380.4(a)(16). 

ratemaking and rate monitoring, for 

oversight of company finances and 

operations, and for adjudication and 

regulation. The data currently reported 

in the forms lack the information that 

would allow the Commission to assess 

and keep pace with changes in the 

industry and the changes adopted here 

better permit the Commission and the 

public to evaluate the filers’ 

jurisdictional rates and operations. The 

additional information to be collected 

by the Final Rule will increase the 

forms’ usefulness to both the 

Commission and the public. Without 

this information, it would be more 

difficult for the Commission and the 

public to assess costs and operations, 

and thereby ensure that rates are just 

and reasonable. 

Burden Statement: In light of 

comments from larger transmissionowning public utilities that it may take 

additional time to comply with the new 

affiliate transaction reporting 

requirement added to Form 1 in this 

Final Rule, the Commission is revising 

its information collection estimates. 

Taking into account the comments 

received, the Commission estimates that 

on average it will take large respondents 

28 hours annually to comply with the 

requirements adopted in the Final Rule 

and smaller respondents 11 hours. 

There are an estimated 211 major and 4 

nonmajor electric utilities that will be 

affected by the changes adopted for 

Form 1 in the Final Rule, for a total of 

215 respondents.83 Larger utilities with 

more affiliate transactions may face a 

greater burden in reporting affiliate 

transaction, other revenues and formula 

rate information. However, the 

Commission believes that most of the 

additional information required to be 

reported is already maintained by the 

utilities. 

The Commission’s estimate has taken 

into account the commenters’ proposed 

burden estimates. However, the 

Commission has adjusted these numbers 

to reflect the clarifications made in the 

Final Rule. Thus, commenters’ proposed 

affiliated transaction burden estimates 

of 100 to 300 hours are better 

considered to be 25 to 75 hours, to 

account for the fact that quarterly 

reporting is not required. Furthermore, 

because the Final Rule does not require 

reporting of affiliate power transactions 

on new page 429, the affiliate 

transaction reporting estimate was 

halved to reflect the Commission’s 

estimate of the transactions to be 

reported. In addition, the Final Rule 

adopts the $250,000 threshold for 

affiliate transaction reporting, which 

will result in a further reduction of the 

initial estimates. The Commission finds 

that a range of 8 to 20 hours is 

appropriate to estimate the annual 

burden of affiliate transaction reporting, 

and, based on its understanding that 

smaller entities will face a lower 

burden, estimates the typical burden to 

prepare the affiliate transaction 

schedule to be 12 hours. Assuming a 

similar burden for the formula rate 

footnote disclosure, the Commission 

estimates the total burden, including 

other reporting, for the revised Form 1 

reporting requirements adopted in this 

Final Rule to be 25 hours. The 

Commission adopts the Form 3–Q 

burden of one hour as proposed in the 

NOPR, since neither the formula rate or 

affiliate transaction reporting 

requirements are adopted for Form 3–Q. 

The resulting total hours for the 

following collections of information will 

be: 

Data collection form Number of 

respondents 

Change in the 

number of 

hours per 

respondent 

Filing 

periods 

Change in the 

total annual 

hours 

(a) (b) (c) (d) (e) = (b) × (c) × (d) 

FERC Form 1 ...................................................................... 211 25 1 5,275 

FERC Form 3–Q .................................................................. 199 1 3 597 

FERC Form 1–F .................................................................. 4 11 1 44 

Relevant Totals ............................................................. ............................ ............................ ............................ 5,916 

Total Annual Hours for Collection: 

(Est. Reporting + Recordkeeping (if 

appropriate)) = 5,916. 

Information Collection Costs: The 

Commission estimates the costs to 

comply with these requirements as 

follows: 

The Commission estimates that the 

additional hours to complete the 

additional reporting requirements will 

be divided among a utility’s accounting 

and internal and outside legal services 

and support staff. The total annualized 

costs for the information collection is 

$538,356. This number is reached by 

multiplying the total hours to prepare 

responses (total: 5,916) by an hourly 

wage estimate of $91 (an average that 

incorporates senior accountant ($50), 

financial analyst ($40), support staff 

rates ($25) and legal ($250)) (salary 

information source: Bureau of Labor 

Statistics and market research). These 

costs will be spread over 215 utilities, 

however. On balance, the Commission 

finds that the collection costs will not 

be unduly burdensome. 

Interested persons may obtain 

information on the reporting 

requirements by contacting: Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 20426 

[Attention: Michael Miller, Office of the 

Chief Information Officer, phone: (202) 

502–8415, fax: (202) 273–0873, e-mail: 

Michael.Miller@ferc.gov]. Comments 

concerning the collection of information 

and the associated burden estimates, 

should be sent to the contact listed 

above and to the Office of Management 

and Budget, Office of Information and 

Regulatory Affairs, Washington, DC 

20503 [Attention: Desk Officer for the 

Federal Energy Regulatory Commission, 

phone (202) 395–7345; fax (202) 395– 

7285]. 

VII. Environmental Analysis 

130. The Commission is required to 

prepare an Environmental Assessment 

or an Environmental Impact Statement 

for any action that may have a 

significant adverse effect on the human 

environment.84 No environmental 

consideration is needed for the 

promulgation of a rule that addresses 

information gathering, analysis, and 

dissemination,85 or that addresses 

accounting.86 This Final Rule involves 

information gathering, analysis, and 


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58736 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 

87 5 U.S.C. 601–12. 

88 Id. 

89 5 U.S.C. 601(3). 

dissemination, and accounting. 

Consequently, neither an Environmental 

Impact Statement nor an Environmental 

Assessment is required. 

VIII. Regulatory Flexibility Act 

131. The Regulatory Flexibility Act of 

1980 (RFA) 87 requires rulemakings to 

contain either a description or analysis 

of the effect that the rule will have on 

small entities or a certification that the 

rule will not have a significant 

economic impact on a substantial 

number of small entities.88 Most utilities 

regulated by the Commission do not fall 

within the RFA’s definition of a small 

entity.89 Thus, most utilities to which 

the rules adopted herein apply would 

not fall within the RFA’s definition of 

small entities. As noted above, the 

Commission has also sought to alleviate 

the burden imposed on small entities by 

(a) eliminating a non-jurisdictional 

utility reporting requirement; (b) 

accommodating non-calendar fiscal year 

accounting; and (c) increasing the 

minimum threshold reporting levels for 

certain line-item information. In 

creating the Form 1 and the Form 1–F, 

moreover, the Commission established 

two different reporting thresholds so 

that smaller utilities would not be 

encumbered with having to provide the 

information necessary to comply with 

the Form 1. Consequently, the Final 

Rule adopted here will not have a 

significant economic effect on a 

substantial number of small entities. 

IX. Document Availability 

132. In addition to publishing the full 

text of this document in the Federal 

Register, the Commission provides all 

interested persons an opportunity to 

view and/or print the contents of this 

document via the Internet through the 

Commission’s home page (http:// 

www.ferc.gov) and in the Commission’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. 

133. From the Commission’s home 

page on the Internet, this information is 

available in the Commission’s document 

management system, 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. 

134. User assistance is available for 

eLibrary and the Commission’s Web site 

during normal business hours. For 

assistance, please contact FERC Online 

Support at 1–866–208–3676 (toll free) or 

202–502–6652 or e-mail at 

ferconlinesupport@ferc.gov, or the 

Public Reference Room at (202) 502– 

8371, TTY (202) 502–8659. E-mail at 

public.referenceroom@ferc.gov. 

X. Effective Date and Congressional 

Notification 

135. These regulations are effective 

for calendar year 2009, i.e., as of January 

1, 2009. The first report, the Form 3–Q 

for the first quarter of 2009, will be due 

in May 2009. The Commission has 

determined, with the concurrence of the 

Administrator of the Office of 

Information and Regulatory Affairs of 

OMB, that this rule is not a ‘‘major rule’’ 

as defined in section 351 of the Small 

Business Regulatory Enforcement 

Fairness Act of 1996. 

List of Subjects 

18 CFR Part 41 

Administrative practice and 

procedures, Electric utilities, Reporting 

and recordkeeping requirements, 

Uniform System of Accounts. 

18 CFR Part 141 

Electric utilities and licensees, 

Reporting requirements. 

By the Commission. 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

■ In consideration of the foregoing, the 

Commission amends parts 41 and 141 of 

Title 18 of the Code of Federal 

Regulations, as set forth below: 

PART 41—ACCOUNTS, RECORDS, 

MEMORANDA AND DISPOSITION OF 

CONTESTED AUDIT FINDINGS AND 

PROPOSED REMEDIES 

■ 1. The authority citation for part 41 

continues to read as follows: 

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

2645; 42 U.S.C. 7101–7352. 

■ 2. Section 41.11 is revised to read as 

follows: 

§ 41.11 Report of certification. 

Each Major and Nonmajor (including 

those companies classified as 

nonoperating under Part 101, General 

Instruction 1(A)(3) of this chapter) 

public utility or licensee operating on a 

calendar year and not classified as Class 

C or Class D prior to January 1, 1984 

must file with the Commission a letter 

or report of the independent accountant 

certifying approval, together with or 

within 30 days after the filing of the 

Annual Report, Form No. 1, covering 

the subjects and in the form prescribed 

in the General Instructions of the 

Annual Report. For such utility or 

licensee operating on a non-calendar 

fiscal year, the letter or report of the 

independent accountant certifying 

approval must be filed within 150 days 

of the close of the company’s fiscal year; 

the letter or report must also identify 

which, if any, of the examined 

schedules do not conform to the 

Commission’s requirements and shall 

describe the discrepancies that exist. 

The Commission will not be bound by 

a certification of compliance made by an 

independent accountant pursuant to 

this paragraph. 

PART 141—STATEMENTS AND 

REPORTS (SCHEDULES) 

■ 3. The authority citation for part 141 

is revised to read as follows: 

Authority: 15 U.S.C. 79; 15 U.S.C. 717– 

717z; 16 U.S.C. 791a–828c, 2601–2645; 31 

U.S.C. 9701; 42 U.S.C. 7101–7352. 

■ 4. In § 141.1, paragraph (b)(1)(i) is 

revised to read as follows: 

§ 141.1 FERC Form No. 1, Annual report of 

Major electric utilities, licensees and others. 

* * * * * 

(b) Filing requirements—(1) Who must 

file—(i) Generally. Each Major and each 

Nonoperating (formerly designated as 

Major) electric utility (as defined in part 

101 of Subchapter C of this chapter) and 

each licensee as defined in section 3 of 

the Federal Power Act (16 U.S.C. 796), 

including any agency, authority or other 

legal entity or instrumentality engaged 

in generation, transmission, 

distribution, or sale of electric energy, 

however produced, throughout the 

United States and its possessions, 

having sales or transmission service 

equal to Major as defined above, must 

prepare and file electronically with the 

Commission the FERC Form 1 pursuant 

to the General Instructions as provided 

in that form. 

* * * * * 

■ 5. In § 141.400, paragraph (b)(1)(i) is 

revised to read as follows: 

§ 141.400 FERC Form No. 3–Q, Quarterly 

financial report of electric utilities, 

licensees, and natural gas companies. 

* * * * * 

(b) Filing requirements—(1) Who must 

file—(i) Generally. Each electric utility 

and each Nonoperating (formerly 

designated as Major or Nonmajor) 

electric utility (as defined in part 101 of 

subchapter C of this chapter) and other 

entity, i.e., each corporation, person, or 

licensee as defined in section 3 of the 

Federal Power Act (16 U.S.C. 792 et 

seq.), including any agency or 

instrumentality engaged in generation, 


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Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 58737 

transmission, distribution, or sale of 

electric energy, however produced, 

throughout the United States and its 

possessions, having sales or 

transmission service must prepare and 

file with the Commission FERC Form 

No. 3–Q pursuant to the General 

Instructions set out in that form. 

* * * * * 

BILLING CODE 6717–01–P 


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58738 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 


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58740 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 


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58742 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 


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58744 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 


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58746 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 


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58748 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 


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58750 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 


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58752 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 


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58754 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 


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58756 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 


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Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 58757 


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58758 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 


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Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 58759 


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58760 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 


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Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 58761 


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58762 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 


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58764 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 


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58768 Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 


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Federal Register / Vol. 73, No. 195 / Tuesday, October 7, 2008 / Rules and Regulations 58769 

[FR Doc. E8–23458 Filed 10–6–08; 8:45 am] 

BILLING CODE 6717–01–C 


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