Federal Energy Regulatory Commission.
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.
Effective Date: This rule will become effective January 1, 2009.Start Further Info
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, e-mail: firstname.lastname@example.org, 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: email@example.com.End Further Info End Preamble Start Supplemental Information
|III. Notice of Inquiry||10|
|IV. Notice of Proposed Rulemaking||11|
|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|
|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.|
1. This Final Rule amends the Federal Energy Regulatory Commission's (Commission) reporting requirements for public utilities  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 Start Printed Page 58721companies;  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 non-power 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 cross-references 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  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  but required to file Form 1 solely because they met the reporting threshold in the regulations.
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. Sections 304, 307 and 309 of the FPA authorize the Commission to collect such data. 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. 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. 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. In 2002, the Commission issued Order No. 626, which eliminated the paper filing requirement, relying solely on electronic filing of Form 1. 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.
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. 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). 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.
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. 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 Start Printed Page 58722amendments to the forms applicable to interstate natural gas companies.
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. In addition, the NOPR proposed two non-form 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.
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. 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 Start Printed Page 58723explanatory 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.
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.
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. 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 Start Printed Page 58724impose 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.
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. 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 Commission-approved 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.
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. 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  (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 Start Printed Page 58725and 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. 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. 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, the differences between the Form 1 amounts and any amounts included in a formula rate as described above.
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.
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. 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 Start Printed Page 58726information 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. 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.
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. 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. The NOPR mentioned that the Commission was aware of five non-jurisdictional 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.
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.
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 cross-subsidization, 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.
57. Several commenters support the proposal, and some include proposals to expand the reporting requirement. Others object to the affiliate transaction reporting requirement  or argue that such a requirement would be duplicative of other reporting obligations, unnecessary and burdensome.
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 Start Printed Page 58727requirement and suggests that the issue is a state regulatory matter.
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  and (2) exempt transactions based on regulator-approved tariffs. 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. 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.”  International Transmission states 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. 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.
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 non-power goods and services transactions including those with other regulated public utilities, centralized and other service companies, and other affiliated or associated companies providing non-power 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). In Order No. 707, the Commission codified in its rate regulations  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 Start Printed Page 58728companies. 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 cross-subsidization.
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. 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. 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. 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.
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.
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 Start Printed Page 58729revenues are derived. 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. 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.
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.
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. 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, Start Printed Page 58730etc.; 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. 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.
92. Several commenters support the proposals to increase the threshold reporting levels. 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.|
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 Start Printed Page 58731requirement helps ensure that comparable data is available for all major utilities. Therefore, we adopt the revised reporting thresholds proposed in the NOPR  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).
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.
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.
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 year-to-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:  (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 native-format 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.
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 firstname.lastname@example.org (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;  and (9) consistent with EEI's request the software already permits filers to calculate totals on pages 426-427, column (f) by substation.
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 Start Printed Page 58732Commission 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 e-mail 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 email@example.com. 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 firstname.lastname@example.org. 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 email@example.com. 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.
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.
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.
105. We decline to adopt this change for the reasons stated in the NOPR: 
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.
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.
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. 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 market-based), 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 non-public status for Form 1 data. Consistent with our long-standing precedent, and in light of the commenters' failure to convince us Start Printed Page 58733otherwise, we decline to adopt non-public 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. 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. 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-by-year 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.
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.
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.
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. 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.Start Printed Page 58734
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.
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. 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. 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. 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.
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; (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;  (3) EEI requests reporting by service type category rather than by transaction;  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;  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 Start Printed Page 58735ratemaking 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 transmission-owning 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. 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|
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. No environmental consideration is needed for the promulgation of a rule that addresses information gathering, analysis, and dissemination, or that addresses accounting. This Final Rule involves information gathering, analysis, and Start Printed Page 58736dissemination, 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)  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. Most utilities regulated by the Commission do not fall within the RFA's definition of a small entity. 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 firstname.lastname@example.org, or the Public Reference Room at (202) 502-8371, TTY (202) 502-8659. E-mail at email@example.com.
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.Start List of Subjects
List of Subjects
- Administrative practice and procedures
- Electric utilities
- Reporting and recordkeeping requirements
- Uniform System of Accounts
End List of Subjects Start Signature
By the Commission.
Nathaniel J. Davis, Sr.,
In consideration of the foregoing, the Commission amends parts 41 and 141 of Title 18 of theEnd Amendment Part Start Part
PART 41—ACCOUNTS, RECORDS, MEMORANDA AND DISPOSITION OF CONTESTED AUDIT FINDINGS AND PROPOSED REMEDIESEnd Part Start Amendment Part
1. The authority citation for part 41 continues to read as follows:End Amendment Part Start Amendment Part
2. Section 41.11 is revised to read as follows:End Amendment Part
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)End Part Start Amendment Part
3. The authority citation for part 141 is revised to read as follows:End Amendment Part Start Amendment Part
4. In § 141.1, paragraph (b)(1)(i) is revised to read as follows:End Amendment Part
(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:End Amendment Part
(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, Start Printed Page 58737transmission, 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.
1. While 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).Back to Citation
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).Back to Citation
5. A major electric utility is one that had, in the last three consecutive years, sales or transmission services that exceeded (1) one million megawatt-hours 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.Back to Citation
7. Amendments 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).Back to Citation
8. Revisions 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).Back to Citation
9. Electronic 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)).Back to Citation
10. Electronic 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).Back to Citation
11. Accounting and Reporting of Financial Instruments, Comprehensive Income, Derivatives and Hedging Activities, Order No. 627, FERC Stats. & Regs. ¶ 31,134 (2002).Back to Citation
12. Quarterly 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).Back to Citation
13. Accounting 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).Back to Citation
14. Id.Back to Citation
15. Assessment of Information Requirements for FERC Financial Forms, Notice of Inquiry, FERC Stats. & Regs. ¶ 35,554 (2007).Back to Citation
16. Revisions 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).Back to Citation
17. Revisions 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).Back to Citation
18. These 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.Back to Citation
19. A list of commenters is attached as Appendix C.Back to Citation
20. NOPR at P 46.Back to Citation
21. BPA states its understanding that the burden of proof otherwise remains on the party challenging a Commission-approved formula.Back to Citation
22. See AEP, EEI, FirstEnergy, and Duke comments.Back to Citation
23. Other 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).Back to Citation
24. Thus, 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.Back to Citation
25. We 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.Back to Citation
26. This 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.Back to Citation
27. As 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.Back to Citation
28. The 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.Back to Citation
29. Whether or not a public utility or licensee must provide this information is addressed above.Back to Citation
30. Revised Form 1 pages affected by this Final Rule are provided in Appendix A.Back to Citation
31. The 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.Back to Citation
32. See 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).Back to Citation
33. NOPR at P 54.Back to Citation
34. Preventing 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).Back to Citation
35. NOPR at P 50.Back to Citation
36. Id. P 48.Back to Citation
37. Morenci Water and Electric Co., 121 FERC ¶ 61,024 (2007).Back to Citation
38. NOPR at P 51-52.Back to Citation
39. APPA and Michigan Commission comments.Back to Citation
40. International Transmission, and SDG&E comments.Back to Citation
41. See AEP, EEI, MidAmerican, and Nevada Companies comments.Back to Citation
42. FirstEnergy and Duke comments.Back to Citation
43. See also Nevada Companies comments.Back to Citation
44. SDG&E also supports a $250,000 reporting threshold for affiliate transactions.Back to Citation
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).Back to Citation
46. Cross-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).Back to Citation
47. Citing NOPR at P 52.Back to Citation
50. See 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)).Back to Citation
51. NOPR at P 56.Back to Citation
53. See, e.g., PacifiCorp, Docket Nos. AC00-20-000 and AC00-20-001 (Apr. 14, 2000) (unpublished letter order).Back to Citation
54. NOPR 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.Back to Citation
55. Id.Back to Citation
56. The New York Commission proposal is provided as line item 36 of Appendix B (corresponding to Appendix C of the NOPR).Back to Citation
57. Page 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).Back to Citation
58. See Order No. 710-A at P 7.Back to Citation
59. NOPR at P 60.Back to Citation
60. See AEP, EEI, and FirstEnergy comments.Back to Citation
61. Filers 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).Back to Citation
62. An 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.Back to Citation
63. BPA and FirstEnergy also generally support the corrections.Back to Citation
64. AEP supports the software improvements proposed by EEI to enable them to load data efficiently into the FERC software.Back to Citation
65. To 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).Back to Citation
66. This 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.Back to Citation
67. Absent reference to particular pages, the Commission is unable to address EEI's remaining request that the Commission correct unspecified improper page references and footnotes.Back to Citation
68. NOPR at P 61.Back to Citation
69. See generally Connecticut Light and Power Co., 2 FPC 853 (1944).Back to Citation
70. See 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).Back to Citation
71. See NOPR at P 14 (summarizing Duke's comments responding to the NOI).Back to Citation
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.Back to Citation
73. NOPR at P 35.Back to Citation
74. Order No. 710 at P 38.Back to Citation
75. NOPR at P 66.Back to Citation
77. EEI 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.Back to Citation
78. EEI 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.Back to Citation
79. See EEI comments at 6.Back to Citation
80. EEI comments at 10.Back to Citation
81. The Commission does not object so long as the service is ongoing, and is not undertaken in response to a particular, non-recurring event.Back to Citation
83. These numbers are based on the most recent filings.Back to Citation
84. See Regulations Implementing the National Environmental Policy Act of 1969, Order No. 486, FERC Stats. & Regs. ¶ 30,783 (1987).Back to Citation
88. Id.Back to Citation
BILLING CODE 6717-01-P
[FR Doc. E8-23458 Filed 10-6-08; 8:45 am]
BILLING CODE 6717-01-C