Skip to Content

Rule

Accounting and Financial Reporting for Public Utilities Including RTOs

Document Details

Information about this document as published in the Federal Register.

Published Document

This document has been published in the Federal Register. Use the PDF linked in the document sidebar for the official electronic format.

Start Preamble Start Printed Page 77626 Issued December 16, 2005.

AGENCY:

Federal Energy Regulatory Commission, DOE.

ACTION:

Final rule.

SUMMARY:

The Federal Energy Regulatory Commission (Commission) is amending its regulations to update the accounting requirements for public utilities and licensees, including independent system operators and regional transmission organizations (collectively referred to as RTOs). The Commission is also amending its financial reporting requirements for the quarterly and annual financial reporting forms for these entities. These updates to the Commission's Uniform System of Accounts and the financial reporting requirements will allow for better comparability between public utilities and will result in improved transparency of financial information and will facilitate better understanding of RTO costs.

DATES:

Effective Date: The amended regulations will become effective January 1, 2006.

Start Further Info

FOR FURTHER INFORMATION CONTACT:

John Okrak (Technical Information), Office of Markets, Tariffs and Rates, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-8280.

Julie Kuhns (Technical Information), Office of Markets, Tariffs and Rates, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6287.

Lodie White (Legal Information), Office of the General Council, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6193.

End Further Info End Preamble Start Supplemental Information

SUPPLEMENTARY INFORMATION:

I. Introduction

II. Background

III. Discussion

A. General

B. Regional Transmission and Market Operation Asset Function

C. RTO Revenue Accounts

D. Regional Market Expense Function

E. Accounting by Public Utilities for Computer Hardware, Software and Communication Equipment

F. Accounting and Financial Reporting by Public Utilities, Including RTOs

1. Accounts for Load Dispatching, Scheduling and System Control Expenses

2. Accounts for System Planning and Standards Development

3. Accounts for Study Costs

4. Accounts for RTO Billings

5. Account for Revenue From Transmission of Electricity

6. Accounting for Settlement Amounts

7. Ministerial Filings

8. Cost Oversight

9. Other Matters

IV. Effective Date

V. Changes to the FERC Quarterly and Annual Report Forms

VI. Information Collection Statement

VII. Environmental Analysis

VIII. Regulatory Flexibility Act

IX. Document Availabilty

Before Commissioners: Joseph T. Kelliher, Chairman; Nora Mead Brownell, and Suedeen G. Kelly.

I. Introduction

1. In this Final Rule, the Commission is revising its Uniform System of Accounts (USofA) [1] to accommodate the restructuring changes that are occurring in the electric industry due to the availability of open-access transmission service and increasing competition in wholesale bulk power markets. Corresponding changes are being made to the FERC Form No. 1, Annual Report for Major Electric Utilities, Licensees and Others (Form 1); FERC Form No. 1-F, Annual Report for Nonmajor Public Utilities and Licensees (Form 1-F); and FERC Form No. 3-Q, Quarterly Financial Report of Electric Utilities, Licensees, and Natural Gas Companies (Form 3-Q).

II. Background

2. In April 1996, in Order No. 888,[2] the Commission established the foundation necessary to develop competitive bulk power markets in the United States: non-discriminatory open access transmission services by public utilities and standard cost recovery rules to provide a fair transition to competitive markets. Public utilities were also required to functionally unbundle, and to provide transmission service separately from generation services.

3. Despite the changes brought about by Order No. 888, reports of discriminatory practices by vertically integrated public utilities persisted. In Order No. 2000,[3] the Commission encouraged the formation of independent and regional organizations, to remedy undue discrimination and to foster regional efficiencies and efficient pricing. As a result, a number of independent system operators and regional transmission organizations (collectively referred to as RTOs) have formed and are in operation.[4] These RTOs perform many of the same activities previously performed by the transmission owners whose transmission systems they now operationally control. In addition, RTOs perform some unique functions, not traditionally performed by other public utilities, they oversee markets and they conduct long-term system planning on a regional basis.

4. On September 26, 2004, the Commission issued a Notice of Inquiry (NOI) in this proceeding.[5] The NOI invited comments on various matters including the Commission's accounting and financial reporting requirements for RTOs. The Commission received comments from RTOs, public utilities that are RTO members, state regulatory commissions, and others. Generally, commenters agreed that the existing accounting regulations and related financial reporting requirements do not provide sufficient detailed information about RTO-related costs, including the costs incurred by RTOs and other relevant information concerning the types of services RTOs provide to their members. On June 3, 2005, the Commission issued a Notice of Proposed Rulemaking (NOPR) in response.[6] The Commission received Start Printed Page 77627comments from RTOs, public utilities that are RTO members, and others.[7]

5. Today, the Commission is issuing this Final Rule to address the accounting and financial reporting issues raised in the NOPR and the comments to the NOPR. The changes to the Commission's accounting and financial reporting requirements adopted here will provide uniformity and transparency in accounting for and reporting of transactions and events affecting public utilities, including RTOs. The Commission expects that these changes in accounting and financial reporting will also lead to improvements in cost recovery practices by providing details concerning the cost of RTO functions, and increased assurance that the costs are both legitimate and reasonable costs of providing service and assigned to the correct period for recovery in rates.

III. Discussion

A. General

6. The Commission received 22 comments on the proposed accounting and reporting requirements which ranged from favorable to falling short of the proposal's intended goal of providing greater transparency for transactions and business functions. Most commenters, however, generally commend and support the Commission's proposed initiative to amend its regulations to update the accounting requirements for public utilities, including RTOs.[8] After careful consideration of the comments received, the Commission is adopting the changes and revisions as proposed with certain modifications and clarifications as discussed below.

B. Regional Transmission And Market Operation Asset Function

1. Accounting NOPR

7. In the NOPR, the Commission proposed to create a new asset function entitled Regional Transmission and Market Operation Plant to record RTO investments in computer hardware, software and communication equipment.[9] The proposed new accounts in this function are Account 380, Land and Land Rights; Account 381, Structures and Improvements; Account 382, Computer Hardware; Account 383, Computer Software; Account 384, Communication Equipment; Account 385, Miscellaneous Regional Transmission and Market Operation Plant; Account 386, Asset Retirement Costs for Regional Transmission and Market Operation Plant; and reserves Account 387 for future accounts.

2. Commenters

8. Commenters were generally supportive and did not oppose the creation of the Regional Transmission and Market Operation Asset Function. One commenter recommended breaking down each new asset account into sub-accounts for general purpose activities, market design development, and market operation.[10]

3. Commission Conclusion

9. The Commission will adopt the Regional Transmission and Market Operation Asset Function as proposed in the NOPR: Account 380, Land and Land Rights; Account 381, Structures and Improvements; Account 382, Computer Hardware; Account 383, Computer Software; Account 384, Communication Equipment; Account 385, Miscellaneous Regional Transmission and Market Operation Plant; Account 386, Asset Retirement Costs for Regional Transmission and Market Operation Plant; and reserves Account 387 for future accounts. The Commission notes that in order to perform many of their primary functions, RTOs must make significant investments in computer hardware, software and communication equipment. The cost of these assets is not explicitly addressed in the existing primary plant accounts, resulting in inconsistent accounting and reporting for these assets. In order to provide more financial transparency and consistent accounting and reporting for the costs of hardware, software and communication equipment, the Commission believes a new utility plant function is needed to record the cost of assets owned and used by RTOs.

10. The Commission does not believe sufficient justification has been advanced to expand the proposed new accounts further as suggested by commenters. The new accounts adopted herein will provide the Commission and others with additional, more detailed information than is currently available about the major types of assets needed to perform region-wide transmission and market operations. These assets perform joint functions and at this point the Commission believes it may be unduly burdensome to allocate the costs of these assets in greater detail.

C. RTO Revenue Accounts

1. Accounting NOPR

11. Revenues RTOs receive for the reimbursement of their operational costs are not addressed in the current USofA because the existing revenue accounts were designed principally to record revenues from electricity sales on a bundled basis. Therefore, the Commission proposed the creation of two new revenue accounts to record amounts billed by RTOs to their members.[11] The first, Account 457.1, Regional Transmission Service Revenues, would include revenues received by RTOs for services provided and amounts billed under each Commission-approved tariff. The second, Account 457.2, Miscellaneous Revenues, would include revenues received from incidental transactions and events, such as profits or losses on sales of miscellaneous materials.

12. The Commission also proposes to include a new Form 1 Schedule to report the revenue collected by RTOs for services performed pursuant to Commission-approved tariffs.

2. Commenters

13. Commenters are generally supportive of the proposed accounting for RTO revenue accounts.[12] However, one commenter suggests that the Commission should create a mechanism and account for all revenues and costs arising from managed market services and operations.[13]

14. Another commenter asserts that RTO constituents have the right to know how much of their RTO's revenues derive from penalties assessed by the RTO.[14] The commenter thus asserts that a new series of accounts should be created to record RTO's revenue from penalties assessed against market participants. According to the commenter, these accounts should be further augmented by another, separate new sub-account for neutrality charges assessed by the RTO.

3. Commission Conclusion

15. We will adopt Account 457.1, Regional Transmission Service Revenues, Account 457.2, Miscellaneous Revenues, and the RTO Revenue Schedule as proposed in the NOPR. The Commission declines to adopt the recommendation to amend the USofA to require RTOs to record revenues on their books and records for energy products, services and Start Printed Page 77628commodities associated with services that RTOs manage for market participants. In these instances, an RTO acts as an agent in providing these services; it does not realize or earn revenue on these transactions. The RTO merely collects monies from one member or participant and remits it to another member or participant. For example, when a member or participant purchases energy through an RTO managed centralized energy market, the RTO merely collects monies from the purchaser of the energy and remits it or passes it through to the appropriate energy supplier, who then records it as revenue.

16. We also decline to adopt the recommendation to amend the USofA to create separate sub-accounts of Account 457 to record penalty and neutrality revenues. According to the instructions of the new RTO revenue accounts, RTOs are to maintain records showing revenues received from customers by type of charge. RTOs then must report any penalty and neutrality revenues received on the newly-created RTO Revenue Schedule adopted herein, providing adequate disclosure of these revenues.

D. Regional Market Expense Function

1. Accounting NOPR

17. In the NOPR, the Commission explained that the current USofA does not provide sufficient financial transparency concerning the types of costs incurred by RTOs in facilitating and monitoring energy markets. In order to address this deficiency the Commission proposed creating a separate new expense function within the USofA to capture these types of costs in greater detail.[15] As part of this new function, the Commission proposed the creation of certain operating expense accounts to capture the costs of managing the various RTO markets and reviewing market data to determine compliance with market rules. These accounts are Account 575.1, Operation Supervision; Account 575.2, Day-Ahead and Real-Time Market Facilitation; Account 573.3, Transmission Rights Market Facilitation; Account 575.4, Capacity Market Facilitation; Account 575.5, Ancillary Services Market Facilitation and Account 575.6, Market Monitoring and Compliance.

18. Additionally, new accounts were proposed to capture and provide greater detail as to the amount of maintenance expense incurred on computer hardware, software, communication equipment and other assets owned and used by RTOs. These accounts are Account 576.1, Maintenance of Structures and Improvements; Account 576.2, Maintenance of Computer Hardware; Account 576.3, Maintenance of Computer Software; Account 576.4, Maintenance of Communication Equipment and Account 576.5, Maintenance of Miscellaneous and Market Operation Plant.

19. Finally, the Commission proposed that RTOs report in Form 1 the data required by the Transmission of Electricity for Others schedule [16] to provide more complete information concerning the use of the transmission system under the control of the RTO.

2. Commenters

20. Most commenters did not object to the Commission's proposal to create a new regional market expense function.[17] However, some commenters suggest that the Commission clarify that the regional market expense function accounts apply solely to RTOs, as the proposed new regulatory text contained in the NOPR does not make this clear.[18] Additionally, one commenter suggests that the Commission change the descriptive caption of this function from “regional market operations expense” to “market operations expense.” [19] This commenter submits that these accounts should not be limited to RTOs, as other public utilities in the future may use market oriented approaches to provide these services.

21. One commenter also suggests that the word “facilitation” in the title of Accounts 575.2, 575.3, 575.4 and 575.5, be changed to “administer” as RTOs administer or operate organized markets while “facilitation” describes a more passive role than is the case.[20]

22. Additionally, one commenter suggests that the Commission require RTOs to record and report revenues and expenses related to the cost of energy, energy products, services and commodities that RTOs manage or provide to market participants.[21] Another commenter suggests that RTO customer service costs be recorded separately in a newly-created account; [22] customer service costs are a significant component of RTO expense identified by public utilities and it is important for RTO/non-RTO customer services expenses to be segregated.

23. Finally, most commenters did not object to the proposal to require RTOs to report the data required by the Form 1 Transmission of Electricity for Others schedule. However, one commenter asserts that RTOs do not currently organize transaction data in a way that would allow them to report the information called for by the schedule.[23] This commenter notes that RTOs treat most service in their footprint as network service and as such can only report aggregate flows without transaction specific source and sink information. The commenter contends that absent extremely expensive software and design changes RTOs will not be able to fully report the information called for on the schedule. The commenter recommends that the Commission not include this requirement in the Final Rule or in the alternative clarify that aggregate flow data will be acceptable.

3. Commission Conclusion

24. The Commission will adopt the regional market expense function and accounts proposed, as modified and clarified below. Upon additional consideration, the Commission clarifies that any jurisdictional entity, whether an RTO or a non-RTO public utility, must use the regional market expense accounts if a regional market expense is incurred. The key for recording costs in these accounts is not whether an entity is an RTO or not, but whether an entity is performing market services on a region-wide basis. The accounts are intended to capture costs incurred in performing region-wide services related to market administration, market monitoring and market compliance activities whether performed by an RTO or another non-RTO public utility. These accounts are not limited to RTOs, as other non-RTO jurisdictional entities may provide these market services, and the costs incurred by these other non-RTO jurisdictional entities in performing these services must be captured in these accounts. The Commission will add a definition of regional market to the USofA to make clear which type of entities are to use the regional market expense function accounts. The Commission clarifies that regional market expense accounts are to be used not only by RTO/ISO public utilities but by any public utility that operates an organized energy market, whether directly or through a contractual relationship with another entity.

25. The Commission will modify the account titles and instructions to replace the word “facilitation” with “administer”, as we agree with the Start Printed Page 77629commenter that it is more descriptive of the role RTOs play (and others may play) in market operations.

26. The Commission declines to adopt commenter recommendations to amend the USofA to require the RTOs to record expenses on their books and records for energy products, services and commodities associated with services that RTOs manage for market participants. As previously discussed, an RTO acts as an agent and does not take title to energy products, services and commodities associated with services in the performance of these managed services. The RTO merely collects monies from one member or participant and remits it to another member or participant.

27. The Commission also declines to adopt one commenter's suggestion to create new accounts to separately record RTO customer service costs. Our existing accounting rules contain customer service expense accounts for recording costs of this nature, Accounts 901-910 (Customer Accounts and Customer Service Accounts). RTOs are required to record their customer service expenses in the appropriate existing customer service accounts. Therefore, it is not necessary to create new accounts for this purpose.

28. One commenter asserts that RTOs cannot provide all of the information required on the Form 1 Transmission of Electricity for Others schedule absent costly software changes to their systems; most of the transmission service in their footprint is network service and as such RTOs do not currently maintain transaction specific source and sink information in a format needed to complete the schedule. However, RTOs can provide aggregate power flow information for the transmission facilities under their control.

29. We will, therefore, require RTOs to report aggregate transmission usage information for imports into the RTO from other systems, exports from the RTO, through and out service, network service and point-to-point service. We will also require RTOs to report related financial information by type of service, such as network and point-to-point service. These changes we adopt herein will give the Commission more complete information concerning the use of the transmission system under the control of RTOs, without requiring RTOs to make costly software changes. We will require the transmission usage information to be reported on a new Form 1 and Form 3-Q schedule entitled Monthly ISO/RTO Transmission System Peak Load and the related financial information on a newly created schedule entitled Transmission of Electricity by RTOs, rather than have RTOs report the information on the Form 1 Transmission of Electricity for Others schedule which is not a good fit for reporting this aggregate information.

30. In examining the new regional market expense function, we recognize a rent account is needed to capture the expenses associated with renting assets to perform regional market functions to be consistent with our other function classifications. Therefore, we will also add a new account entitled Account 575.8, Rents, to capture rent costs in the regional market expense function.

E. Accounting by Public Utilities for Computer Hardware, Software and Communication Equipment

1. Accounting NOPR

31. In the NOPR, the Commission proposed to add three new sub-accounts to the existing transmission asset function for public utilities and licensees, other than RTOs, to record the cost of computer hardware, software and communication equipment owned and used for transmission related activities.[24] The Commission proposed to create Account 351.1, Computer Hardware, Account 351.2, Computer Software, and Account 351.3, Communication Equipment, so as to provide uniform and consistent accounting and reporting for these types of assets by non-RTO public utilities and licensees.

2. Commenters

32. Commenters generally argue that the proposed changes would impose a significant burden on companies; [25] companies will face a complex undertaking in identifying what portions of their computer hardware, software and communications equipment and operation and maintenance costs belong in the new transmission accounts because most companies rely on such hardware, software, and equipment for multiple purposes.[26] One commenter suggests that the Commission appears to have overlooked the fact that public utilities perform many more functions than simply transmission functions.[27]

33. Commenters assert that the new accounts for computer equipment and computer use will require judgments as to disaggregation and assignment of these costs among different accounts [28] —costs that are not necessarily severable and directly assignable. Commenters also assert that these allocations will be unnecessarily arbitrary and the Commission's desire for comparability will never be achieved.[29]

34. Commenters recommend that, due to the extreme burden the proposed changes would place on public utilities, these changes should be applied only to RTOs, whose sole business is related to performing transmission functions.[30] Commenters note that the RTOs' primary function is the administration of transmission systems and the use of their hardware, software and communication equipment is more easily identifiable as transmission related.[31]

35. Commenters also suggest that, if the Commission retains the proposed new computer and communication equipment accounts for use by licensees and public utilities other than RTOs, that it provide companies the flexibility to make reasonable allocations to the new accounts and other accounts in the USofA, including the general plant accounts.[32] Commenters also suggest that companies should be able to adopt the new accounts in a way that makes sense given their circumstances, with as little extra effort as possible, without having to perform complex allocations, and without having to modify prior accounting records and reports.

36. Another commenter suggests that new sub-accounts should be set up to record the additional computer hardware, software and communications equipment required to interface with the RTO.[33] This commenter suggests that these sub-accounts should record and disclose the amount of information and technology and communications spending that relates specifically to the public utility's RTO interface.

37. Finally, one commenter also notes that the Commission proposes to add new sub-accounts to Account 569, Maintenance of Structures, namely Account 569.1, Maintenance of Computer Hardware, Account 569.2, Maintenance of Computer Software, and Account 569.3, Maintenance of Communication Equipment. The commenter suggests that the more appropriate account for these sub-accounts would be Account 573, Maintenance of Miscellaneous Transmission Plant (Major only), Start Printed Page 77630making them sub-accounts Account 573.1 though Account 573.3.[34]

3. Commission Conclusion

38. The great majority of commenters disagree with the NOPR's proposed accounting for computer hardware, software and communication equipment by public utilities and licensees other than RTOs. These commenters argue that these assets are not necessarily severable and directly assignable. They point out that the equipment and software in question perform many different functions and that it would be extremely difficult to determine what portion of the equipment and software perform a transmission function. These commenters also argue that individual utilities may use different allocation methods to determine the portion of these items used in transmission, which will reduce comparability among utilities and therefore the usefulness of the reported accounting information. Finally, these commenters contend that it will be burdensome and costly to implement the proposed changes and that minimal reporting benefits will be derived from the change.

39. The Commission acknowledges that some or perhaps most computer hardware, software and communication assets are joint use assets that may not be severable or directly assignable to the transmission function. We agree with commenters that requiring entities to record that portion of their investments in these assets used for transmission purposes within the transmission function on an allocated basis is problematic in that functional reclassification of the investment, as well as the related depreciation reserve, would be required each accounting period as the allocation factor changes. Therefore, we have decided not to adopt proposed Accounts 351.1, 351.2 and 351.3 for public utilities and licensees other than RTOs and will continue to allow non-RTO public utilities to account for these items as joint use assets as they have historically done. However, we will require both RTOs and non-RTO public utilities to record the costs of maintaining these assets that are related to providing transmission services in Accounts 569.1, 569.2 and 569.3 as proposed. Non-RTO public utilities already allocate these joint use costs for ratemaking purposes in determining open access transmission rates. We will now also require that public utilities allocate these costs for accounting purposes.

40. Allocation approaches used by public utilities must ensure that a reasonable portion of the cost of maintaining these joint use assets are used in the transmission of electricity are allocated to the transmission function. Additionally, public utilities are also expected to allocate these costs to the transmission function on a consistent basis from year to year. Public utilities will be required to footnote their allocation method used to calculate these maintenance expenses as reported in the Form 1 Electric Operation and Maintenance Expenses Schedule (pages 320-323).

41. Finally, we decline to adopt one commenter's suggestion that instead of adding sub-accounts to Account 569, Maintenance of Structures, that we add sub-accounts to Account 573, maintenance of Miscellaneous Transmission Plant, for the maintenance costs related to computer hardware, software and communication equipment. The commenter provides no explanation for the proposed change and we see no benefit in deviating from the account structure originally proposed.

F. Accounting and Financial Reporting by Public Utilities, Including RTOs

1. Accounts for Load Dispatching, Scheduling and System Control Expenses

i. Accounting NOPR

42. In the NOPR, the Commission proposed to replace Account 561, Load Dispatching, with a series of detailed expense accounts to record expenses for providing transmission services related to load dispatching, scheduling and system control.[35] The proposed accounts are Account 561.1, Load Dispatch-Reliability, to include the costs incurred to manage the region-wide reliability coordination function; Account 561.2, Load Dispatch-Monitor and Operate Transmission System, to include the costs incurred to monitor, assess and operate the transmission system and ensure the system's reliability and Account 561.3, Load Dispatch-Transmission Service and Scheduling, to include the costs incurred to process hourly, daily, weekly and monthly transmission service requests using an automated system such as an Open Access, Same-Time Information System (OASIS).

ii. Commenters

43. One commenter asserts that the Commission should not apply the proposed USofA changes to transmission owners that are members of an RTO or ISO, as doing so will increase the cost to consumers for the implementation of these systems, while providing little additional information to the Commission.[36] This commenter also asserts that it may be difficult to disaggregate expenses among the proposed new Load Dispatch sub-accounts (561.1, 561.2, and 561.3), because the same staff members may perform functions included under more than one of these sub-accounts, tasks undertaken to accomplish functions relevant to one sub-account may also contribute to completion of another, and the descriptions of the sub-accounts are insufficiently detailed.[37] This commenter further asserts that if the Commission does decide to apply the proposed USofA changes to utilities that are members of RTOs and ISOs, it should allow those utilities to apply for a waiver to allow consolidated reporting of load dispatch expenses if they fall below a de minimus threshold.[38]

44. Another commenter asserts that the lines of demarcation between costs in these sub-accounts are not clear and that the Commission should provide additional guidance on its intention as to information to be captured in these sub-accounts.[39] Yet another commenter notes that, while it supports the Commission's goal of greater cost transparency, it similarly recommends that the Commission provide further guidance so that the useful cost comparisons that the Commission is seeking to facilitate can be made across RTOs and public utilities.[40] This commenter asserts that the addition of accounts to reporting forms will be of little use if users are not populating those accounts with comparable costs and information. This commenter recommends that the Commission provide additional guidance regarding the specific information it would like captured in these sub-accounts.

45. One commenter supports the specific account structure the Commission proposes, as well as its applicability to both RTOs and non-RTO public utilities. However, that commenter suggests the Commission realign the grouping of the new accounts under two new functions (system control and transmission services) that it proposes should be created.[41]

46. Finally, a commenter notes that, in the text of the NOPR's discussion of Accounts 561.1, 561.2 and 561.3, the Start Printed Page 77631NOPR states that these proposed accounts are for use by both non-RTO public utilities and RTOs.[42] However, in the proposed text of the USofA for Accounts 561.1, 561.2 and 561.3, the proposed language specifically states that the accounts are to include expenses incurred by the regional transmission service provider, with no mention in the proposed text of non-RTO public utilities. The commenter suggests that the Commission revise the proposed text of the USofA for proposed Accounts 561.1, 561.2 and 561.3 to specifically state that the accounts may be used by RTOs, other public utilities and licensees, consistent with the NOPR's language.

iii. Commission Conclusion

47. The proposed accounts for recording load dispatch, scheduling and system control expenses provide greater transparency concerning the types of costs incurred by both RTOs and non-RTO public utilities in providing transmission services. Therefore, we will adopt the proposed accounting for load dispatch, scheduling and system control expenses. However, based upon the comments received, we will adopt the proposed accounting with certain clarifications and modifications as discussed below.

48. The instructions to Accounts 561.1, 561.2 and 561.3 are revised to make clear that the accounts are to be used by both RTOs and non-RTO public utilities. Additionally, the items list of Account 561.2 has been revised to include certain items included in replaced Account 561, Load Dispatching, which were inadvertently not included on the list. These modifications add clarity as to which entities are to use the accounts and what types of costs are to be recorded in the load dispatch, scheduling and system control expense accounts.

49. We will not adopt one commenter's suggestion to realign the newly created accounts under its suggested new functions: system control and transmission service. The expanded expense accounts contained in the transmission function provide the requisite transparency concerning the activities and related costs incurred by public utilities, including RTOs, in providing transmission service for ratemaking and other Commission purposes. Moreover, the account structure appropriately herein adequately separates market service and transmission service activities.

50. Finally, we clarify that, to the extent that RTOs and non-RTO public utilities perform the same activities for load dispatch, scheduling and system control, then the costs of those activities should be accounted for in the same manner and recorded in the same accounts. For example, if an RTO incurs costs to manage the region-wide reliability coordination function it would record those costs in Account 561.1. Likewise, if a non-RTO public utility happens to incur costs to manage the reliability coordination function for third parties, it would also record those costs in Account 561.1.

2. Accounts for System Planning and Standards Development

i. Accounting NOPR

51. In the NOPR, the Commission proposed to add a new Account 561.5, Long-Term Reliability Planning and Standards Development, to record the costs incurred by RTOs for performing long-term system planning and standards development.[43]

ii. Commenters

52. Some commenters request clarification of the Commission's proposed changes.[44] These commenters suggest that the definition provided in the NOPR does not provide a definitive basis to identify the costs to be recorded in this account because planning can be interpreted to have several meanings. National Grid requests that the Commission recognize that the scope of costs covered by Account 561.5 is likely to vary from region to region and clarity should be provided about the meaning of “long-term system planning.” They explain that transmission planning occurs over several different time-scales such as short-term planning to intermediate planning to long term planning.[45] Indicated NYTOs request a waiver for transmission owners that are RTO members to allow consolidated reporting of de minimus amounts or alternatively guidance on the specific expenses to be recorded in the account.[46]

53. Other commenters support the proposed changes but believe the Commission should require additional accounts to offer more transparency and comparability. Specifically one commenter believes that Account 561.5 should be augmented by additional accounts for the portion of system planning, development and maintenance expenses that relate to market design initiatives and activities of RTOs, as opposed to control area operation.[47]

54. Finally, one commenter believes that the structure of this new account allows for inclusion of generation-related costs such as resource planning.

iii. Commission Conclusion

55. As the Commission explained in the NOPR, the existing USofA does not provide a specific expense account to record expenses for system planning and development activities. The Commission will adopt Account 561.5 as proposed as modified and discussed below. Commenters raise questions about the scope of planning costs that are to be recorded in Account 561.5 and how to record costs incurred relative to the different transmission planning time-scales, such as short-term, intermediate-term, and long-term. We will modify the instructions to Account 561.5 to allow inclusion of all transmission system planning time-scale planning costs, not just long-term planning. We will therefore modify the title of the account to Account 561.5, Reliability, Planning and Standards Development, to reflect the fact that planning costs other than long-term are to be recorded in Account 561.5.

56. RTOs are directed to report costs of system planning, development, and maintenance expenses in Account 561.5. We clarify to the extent that public utilities and licensees that are not RTOs perform similar activities; they should also include the costs that they incur for system planning and standards development in Account 561.5. We also clarify that all system planning and standards development costs recorded in this account are to be transmission related.

57. The Commission declines at this time to augment Account 561.5 with additional accounts for the portion of system planning, development and maintenance expenses that relate to market design initiatives and activities of RTOs, as opposed to control area operation. We have created a new regional market expense function and all market planning and development costs shall be recorded in the appropriate market expense account based on the nature of the planning and development costs incurred.

3. Proposed Accounts for Study Costs

i. Accounting NOPR

58. The USofA does not specially provide accounts for recording costs incurred to perform generation interconnect and transmission service studies. Therefore, the Commission Start Printed Page 77632proposed to create Account 561.6, Transmission Service Studies, to record the costs incurred by public utilities and licensees, including RTOs, to conduct studies for transmission service requests. The Commission also proposed to add a new Account 561.7, Generation Interconnection Studies, to record the costs incurred by public utilities and licensees, including RTOs to conduct studies for generator service requests.[48]

59. Additionally, in order to provide more disclosure concerning the costs of interconnect study activities being performed by public utilities and licensees, including RTOs, the Commission proposed to add a new schedule to the quarterly and annual financial reports that will provide more specifics concerning the costs of these activities.[49]

ii. Commenters

60. Commenters were of divergent views regarding the Commission's proposal to record costs to perform generation interconnect and transmission service studies in Account 561.6 and Account 561.7. Commenters state that it is not clear whether the proposed shift in accounting treatment of study costs could affect the billable or capital treatment of the underlying study costs. Commenters state that the costs of transmission service studies and generator interconnection studies are largely reimbursed by customers or folded into the capital accounting for transmission projects or upgrades, and would only be expensed in rare circumstances.[50] One commenter requests that the Commission clarify that the new expense accounts for study costs are not intended to cover all study costs, but only those costs that are neither reimbursed by customers nor capitalized. Alternatively, this commenter requests clarification that utilities may still charge out or capitalize such study costs as they have in the past.[51] Another commenter requests that the Commission exempt RTO member utilities from the proposed USofA changes for study costs because it provides little additional information. Alternatively, this commenter requests a waiver to eliminate reporting study costs in Account 561.6 and Account 561.7 because the costs are largely reimbursed by the RTO and will appear in the RTO financial reports. Additionally, this commenter requests that the cost of transmission service and generator interconnect studies be treated as capital expenditures.[52]

iii. Commission Conclusion

61. The Commission will adopt the proposed accounts for recording generation interconnection and transmission service study costs as clarified below. We clarify that Accounts 561.6 and 561.7 are only to be used to record the costs incurred by public utilities, including RTOs, to conduct studies for transmission service requests and generator service requests, respectively, when the costs are not directly reimbursable by a specific customer and the costs are otherwise charged to expense under the USofA.

62. Additionally, we clarify that the Commission did not propose any change and does not do so now related to the recording of the costs of conducting transmission and generation interconnect studies in Account 186, Miscellaneous Debits, by public utilities, including RTOs, pending reimbursement by the entity requiring the service. We further clarify that the Commission did not intend to change any capitalization requirements related to study costs. Public utilities are to continue to follow the Commission's existing rules and regulations for cost capitalization.

4. Accounts for RTO Billings

i. Accounting NOPR

63. In the NOPR, the Commission proposed to create three new sub-accounts in order to provide greater transparency for the payments made by public utilities and licensees to RTOs. The three new proposed sub-accounts are Account 561.4, Scheduling, System Control and Dispatching Services; Account 561.8, Reliability Planning and Standards Development Services; Account 575.7, Market Facilitation, Monitoring and Compliance Services.[53] The proposed new sub-accounts will be used by public utilities and licensees to record their share of costs billed to them by an RTO. Additionally, the Commission proposed that each RTO include in its monthly settlement statements a breakdown of the allocation of that RTO's operational costs within each of the three sub-accounts discussed below.

ii. Commenters

64. Commenters generally agree that non-RTO public utilities should record in separate sub-accounts the charges paid to RTOs and suggest that the Commission add more sub-accounts to separately disclose additional costs incurred by non-RTO public utilities.[54]

65. One commenter seeks clarification of the Commission's intent with respect to proposed Account 575.7 Market Facilitation, Monitoring and Compliance Services.[55] This commenter questions if the Commission intends that only costs billed to utilities by the RTOs be included in this account, not including costs by utilities performing functions that meet the description of the account. The commenter explains that decisions made regarding rate recovery of Balancing Authority costs by transmission owners are likely to depend heavily on how relevant costs are recorded and requests that the Commission clarify that Account 575.7 is only applicable to costs billed to utilities by RTOs.

66. Finally, one commenter requests that the Commission not adopt an absolute rule that information on the three new cost sub-accounts be part of the settlement statements.[56] This commenter believes it will be expensive to include such cost breakdowns in monthly customer settlement statements. This commenter states that RTOs have sophisticated billing software that is not easy to modify and that a number of RTOs would have to make expensive and time-consuming changes to their billing systems in order to incorporate the required cost information directly into monthly settlement statements. This commenter suggests that a more flexible approach would recognize the reality that different RTOs have different software capabilities and allow each entity to comply with the Commission's requirement in their own efficient way.

iii. Commission Conclusion

67. The Commission will adopt the new accounts for RTO billings proposed in the NOPR with the modification discussed below. As the Commission explained in the NOPR, these new accounts will allow each RTO member to record its share of the RTO's total monthly operating costs in these new sub-accounts. The Commission will also require each RTO provide a breakdown of the allocation of that RTO's operational costs within each of the three sub-accounts. However, the Commission will not require RTOs to include this information in its monthly settlement statements because of software costs to implement changes to Start Printed Page 77633the RTO billing systems. Instead, the Commission will permit RTOs to use another format to provide the information to its members. However, RTOs are nevertheless directed to provide a breakdown of the cost allocation to the three new sub-accounts on the date the billings are issued.

68. The Commission also clarifies that Account 575.7 is to be used only for costs billed to utilities by RTOs for market administration, monitoring and compliance services.

5. Account for Revenue From Transmission of Electricity

i. Accounting NOPR

69. In the NOPR, the Commission proposed to add a new sub-account to Account 456, Other Electric Revenues, in order to provide greater transparency by transmission owners for the revenues received for use of their transmission facilities.[57]

ii. Commenters

70. Commenters were generally supportive, but request that the Commission provide additional clarification.[58] One commenter requests that the Commission provide even more transparency regarding the particular sources of those revenues and how they relate to common ratemaking categories. This commenter suggests the Commission implement accounting for transmission revenues that would enable customers and the Commission to monitor whether previously accepted rates generate more than an appropriate level of revenues. This commenter requests that the Commission remedy its accounting and reporting, in this proceeding, to keep pace with standard ratemaking practice so that Form 1 information provides accounting data for direct ratemaking use.[59] Another commenter requests the Commission clarify that non-RTO public utilities should use the new Account 456.1 for transmission service revenues and existing Account 456 for miscellaneous revenues.

iii. Commission Conclusion

71. The Commission will adopt the new sub-account as proposed in the NOPR. The new Account 456.1, Revenues From Transmission of Electricity of Others, will include revenues the transmission owner receives for the transmission of electricity over its transmission facilities. This new account will provide greater transparency with respect to the revenues received by transmission owners for use of their transmission facilities. We also clarify that revised Account 456 is to be used for recording non-transmission miscellaneous operating revenues.

6. Accounting for Settlement Amounts

i. Accounting NOPR

72. In the NOPR, the Commission proposed that public utilities or licensees that conduct energy transactions through an RTO that requires participants to bid their generation into the market and buy generation to supply their native load report these transactions on a net basis in Account 555, Purchased Power.[60] The Commission also invited comment as to what circumstances would be appropriate for a public utility or licensee to reflect these types of transactions on a net basis, and under what circumstances would it be appropriate for a public utility or licensee to reflect these types of transactions as distinct purchases and sales.

ii. Commenters

73. Two commenters do not support the netting of transactions that flow through RTO energy markets.[61] One of these commenters argues that for accounting and tax purposes, purchased power should, on financial statements, represent only purchased power. This commenter also asserts that its members that are subject to Rural Utilities Service (RUS) oversight need to be able to report gross amounts of energy sales to RUS. This commenter further asserts that it will be difficult for cooperatives to determine income for income tax purposes if only net transactions are reported.[62] The other commenter argues that showing only the net position of a market participant may understate the use of RTO energy markets and mask situations where a utility is a net seller during one period but a net buyer in another period. This commenter also notes that netting would not reveal the effects of time and location-specific variation in energy prices, yielding only incomplete results that are unlikely to be meaningful.[63]

74. Most other commenters, however, generally agree that these transactions should be reported on a net basis.[64] One commenter submits that reporting these types of transactions on a gross basis might give an inaccurate picture of an entity's size and its actual revenue-generating activities.[65] This commenter suggests that accounting for transactions settled through RTO markets on a net basis more accurately reflects what similarly situated utilities would be doing in the absence of RTO markets. This commenter also suggests that accounting on a gross basis would cause it to incur an artificially large gross receipts tax liability which would act as a deterrent to participation in RTO markets. This commenter further suggests that accounting for these transactions on a net basis is in accord with traditional accounting principles regarding whether to record transactions on a gross or net basis.

75. Some commenters support netting, but believe that it is inappropriate to report net sales in Account 555.[66] These commenters assert that net sellers of generation should report the transactions in Account 447, Sales for Resale, and that net purchasers should report the transactions in Account 555, Purchase Power. One commenter notes that consistent with the reporting methodology of its RTO it reports sales and purchases of power on an hourly net position basis. For each hour that the company is a net seller of power, the commenter states that it reports the net amount in Account 447; conversely, if it is net buyer of power, it reports the net amount in Account 555. In each monthly reporting period, the commenter notes that the hourly Account 447 and/or Account 555 net amounts are aggregated and separately reported in Account 447 and 555, respectively.

76. Some commenters also recommend that the Commission allow companies flexibility in determining net sales and/or purchases during the relevant reporting period and for using the appropriate account or accounts to display its net sales and/or purchases.[67] One of these commenters suggests that some companies may choose to net their purchases and sales for the entire reporting period, while others may reflect separately net purchases when the company was a net buyer and net sales when it was a net seller.

77. On the other hand, one commenter suggests that the Commission define a uniform method for the calculation of the gross amount of sales versus purchases, whether it be Start Printed Page 77634by the hour, day, week or month.[68] This commenter argues that, without such a standard, a wide range of interpretation and reporting is likely to result.

78. Another commenter asserts that netting should be allowed for transactions in all RTO markets.[69] This commenter suggests that the Commission clarify that netting of purchases from and sales into an RTO market is appropriate and allowed not only for transactions in an RTO that requires participants to offer all resources to and buy all power from the RTO, but for transactions in any RTO that offers an energy market in which participants may choose to offer all generation to and buy all power from the energy market. This commenter also suggests that the Commission clarify that purchases from and sales to one or more RTO markets may be netted against one another.

79. Finally, one commenter recommends that the Commission's Electronic Quarterly Reports (EQR) and annual reports be revised to match the accounting methodology using the Commission's USofA with the required reporting format.[70] While another commenter notes that there is a disconnect between the reporting of transactional data in the EQRs and reporting of the data in the FERC Form 1, stemming from how the data are defined in those two contexts. This commenter recommends that when the Commission next entertains revisions to one or the other of the forms, the Commission should discuss this issue with reporting entities to determine if some clarification aimed at conformity would be appropriate.[71]

iii. Commission Conclusion

80. Recording RTO energy market transactions on a net basis is appropriate as purchase and sale transactions taking place in the same reporting period to serve native load are done in contemplation of each other and should be combined. Netting accurately reflects what participants would be recording on their books and records in the absence of the use of an RTO market to serve their native load. Recording these transactions on a gross basis, in contrast, would give an inaccurate picture of a participant's size and revenue producing potential. The Commission will, therefore, adopt the proposed accounting for RTO energy market transactions with certain modifications and clarifications as discussed below. The Commission does expect public utilities, however, to maintain detailed records for auditing purposes of the gross sale and purchase transactions that support the net energy market amounts recorded on their books.

81. Additionally, we clarify that transactions are to be netted based on the RTO market reporting period in which the transaction takes place. For example, if the RTO market in which the transaction takes place uses an hourly period for determining energy market charges and credits, then non-RTO public utilities purchasing and selling energy in the market must net transactions on an hourly basis. Requiring participants to net transactions over the RTO market's reporting period leads to consistent and comparable energy market information for decision making purposes by the Commission and others.

82. Further, we clarify that the netting of purchases and sales in an RTO energy market is appropriate not only for transactions where participants are required to bid their generation into the market and buy generation from the market to supply their native load, but also in cases where an RTO offers an energy market in which participants may choose to offer all generation to and buy all power from the energy market.

83. We also clarify that if a participant is a net seller, rather than a net buyer, during a given market reporting period it must credit such net sales to Account 447, Sales for Resale, instead of Account 555, Purchased Power.

84. Finally, one purpose of this rule is to establish uniform accounting requirements for the purchase and sale of energy in RTO markets. The purpose of reporting of gross information in EQRs, in contrast, is to provide the Commission and the public with a more complete picture of wholesale market activities which affect jurisdictional services and rates, thereby helping to monitor for any market power and to ensure that customers are protected from improper conduct. These are not necessarily the same criteria and principles that should be used in establishing uniform accounting requirements. In any event, the reporting of wholesale market activity in EQRs falls outside the scope of this rule.

7. Ministerial Filings

85. Some commenters argue that certain revisions to the USofA will adversely affect the Attachment O formula rate which is used by the vast majority of the transmission owners in the Midwest ISO and other formula rates that rely on the USofA and Form 1 data for the rate inputs.[72] Specifically, for the Midwest ISO, new accounts or renumbered accounts may cause disruptions in the operation of the Attachment O formula rate, especially if there is no parallel revision to Attachment O to reflect these changes. Some commenters therefore request that the Commission clarify that it will accept “ministerial” filings in order to conform these formula rates to the final revisions of the USofA.[73]

86. In particular, FirstEnergy, among others, has expressed concern that the Commission ensure that the revisions to its accounting and financial reporting requirements will not provide an opportunity for challenges to Commission-approved formula rates nor shall the Commission entertain such challenges to these previously-accepted rates.[74] Therefore, the Commission should state that it will accept “ministerial” filings necessary to conform to the Final Rule all Commission accepted formula rates that rely on Form 1 inputs. FirstEnergy further argues that the Commission should provide a specific timeline to allow such filings but coordinate the respective effective dates of the rate filings and reporting changes to ensure that there is no gap in cost recovery.[75] International Transmission requests that the Final Rule establish a compliance filing process, rather than allow a Federal Power Act section 205 filing,[76] so that there will be no challenges to ministerial filings in order for public utilities to revise the formula rate templates.[77]

Commission Conclusion

87. We will allow revisions to tariffs to conform to the changes adopted here, but pursuant to section 205. We will, however, consider only comments that address the specific revisions necessary to comply with these accounting and reporting revisions. By narrowly focusing the scope of the filings and of the comments to only those changes necessary to conform to this Final Rule, public utilities can be assured that commenters cannot otherwise and inappropriately challenge the reasonableness of their Commission-approved and accepted formula rates.

88. We also find that any necessary revisions to formula rates in order to Start Printed Page 77635conform to the Final Rule should not increase rates. The requisite changes to Attachment O, for example, would be the result of the new accounts and would solely reflect accounting changes adopted in this Final Rule. Such changes also should not involve substantive changes to the way the formula rates operate or the way the charges are calculated.

8. Cost Oversight

89. The Commission received multiple comments regarding cost oversight in response to the accounting and financial reporting NOPR. Commenters assert that the restructuring of the electric industry will only benefit consumers if transmission organizations are subject to greater efficiency and accountability.[78] As the National Rural Electric Cooperative Association (NRECA) states, “[t]he absence of common standards and rules currently hampers meaningful examination of the cost-effectiveness of the products and services that RTOs/ISOs offer.” [79]

90. Commenters have also included general suggestions to the Commission, which they argue, would not only enhance and facilitate transparency and comparability of RTO finances, but could also be an integral first step towards controlling RTO operational costs. Among other things, commenters have suggested that the Commission require RTOs to include a detailed analysis of their business risks and opportunities as part of their periodic financial reporting.[80]

91. A few commenters also urge the Commission to continue its efforts in reviewing the cost oversight and accountability in the budgeting and expenditure process that RTOs utilize.[81] Revision of the USofA represents only a partial solution in providing adequate transparency and accountability in RTO financial reporting.

92. Commenters have expressed concern that the Commission's proposed revisions fall short in meeting the goal of ensuring that the costs of the RTOs are legitimate and reasonable.[82] Cinergy has therefore, for example, proposed that RTOs annually file with the Commission a formula cost assignment template which supports the projected RTO costs by billing schedule for a twelve month period. This report, Cinergy explains, would include detailed projected direct costs and a proposed assignment/allocation of overhead costs to the specific schedule. This would provide parties with an opportunity to comment and prior Commission approval would be required before the RTO could proceed with the expenditure.

93. Midwest ISO Transmission Owners argue that the proposed revisions to the USofA lack before-the-fact review of costs. They contend that while after-the-fact review of costs is being done if an RTO has a formula rate, it does not adequately respond to the needs of these not-for-profit entities, as an entity's “not-for-profit status complicates a prudence review after the costs are incurred.” [83] Midwest ISO Transmission Owners therefore suggest that, in order to keep the Commission and RTO members, as well as interested state commission, abreast of estimated and actual expenditures and to provide RTO members due process, the Commission should require approval before the RTO incurs significant costs and also require regular reporting after costs have been incurred.

Commission Conclusion

94. We recognize that there are divergent views as to the best way to accomplish the goals of this initiative. The accounting and form changes adopted herein add visibility and uniformity to the accounting and financial reporting for the costs of transmission and market operation plant, and the expenses incurred and revenue received in providing transmission and market services. The changes provide comparability among RTOs and non-RTO public utilities that perform region-wide transmission and market operations, and minimize inconsistent reporting by RTOs and non-RTO public utilities. Further, these revisions allow the Commission to better understand transactions and events that affect RTOs and their members and non-RTO public utilities.

95. The Commission expects the changes in financial reporting to lead to improvements in cost recovery practices by providing more details concerning the costs of certain functions and increased assurance that the costs are legitimate and reasonable costs of providing service and assigned to the correct period for recovery in rates. We believe the changes we are adopting herein are an important first step. The concerns raised with regard to RTO cost oversight, including the budgeting process, the expenditure process, and the analysis of RTO business risks and opportunities are beyond the scope of this proceeding. However, cost oversight practices are an important aspect of the initiative we began with the NOI and we intend to address those matters in the near future.

9. Other Matters

96. The Commission noted in the NOPR that the derivative and asset retirement accounts established under Order Nos. 627 and 631 were not included in the Chart of Account listings contained in the USofA.[84] The Commission here takes this opportunity to update the account listing to include the accounts established under these orders.

IV. Effective Date

i. Accounting NOPR

97. In the NOPR, the Commission proposed that the aforementioned accounting and financial reporting changes and updates would become effective on January 1, 2006.[85]

ii. Commenters

98. Most of the commenters suggest the Commission instead adopt a January 1, 2007 effective date. Some of the commenters believe non-RTO public utilities face a substantial burden of implementation because of other obligations and functions performed by these companies.[86] One commenter explains that it has Sarbanes-Oxley Act concerns about any proposal that would require changes, reconfigurations or modifications to its general ledger computer systems and reporting structures, and/or the methodology of the reporting of RTO-related revenue and cost transactions. This commenter requests that the Commission provide sufficient time to implement, internally test and have any necessarily validations by external auditors of such changes or modifications.[87] Another commenter expresses similar concerns and requests that the Commission provide a minimum of three months to adjust their accounting and reporting systems. This commenter explains that the easiest time for companies to implement changes in the start of a fiscal year, typically the calendar year.[88] Other commenters indicate that more time is needed to allow for more coordination, discussion and consideration of the complexities of all Start Printed Page 77636the issues.[89] Another commenter submits that the rule take effect on the proposed date unless it places an undue burden on the industry as a whole or on some public utilities; in which case, the commenter recommends that RTOs submit pro forma financial statements conforming to the new rules on the proposed date.[90]

99. Commenters generally were in agreement that the Commission should not require comparative analyses of the new data for earlier reporting periods. Commenters contend that it would be unduly burdensome for FERC Form 1 and 3-Q filers to go back in time to try to capture retroactive prior period information for the new sub-accounts.[91]

iii. Commission Conclusion

100. The accounting and form changes adopted herein add visibility and uniformity to the accounting and financial reporting for the costs of transmission and market operation plant, and the expenses incurred and revenue received in providing transmission and market services. The changes provide comparability among RTOs and non-RTO public utilities that perform region wide transmission and market operations, and minimize inconsistent reporting by RTOs and non-RTO public utilities. Further, these revisions allow the Commission to better understand transactions and events that affect RTOs and their members and non-RTO public utilities.

101. The Commission also expects the changes in financial reporting to lead to improvements in cost recovery practices by providing more details concerning the costs of certain functions and increased assurance that the costs are legitimate and reasonable costs of providing service and assigned to the correct period for recovery in rates.

102. For the above reasons, the Commission orders that the aforementioned accounting and financial reporting changes and updates become effective on January 1, 2006. The Commission believes it is imperative to obtain as quickly as possible adequate transparency of transactions and business functions among and between RTOs and their member public utilities as well as non-RTO public utilities to allow for prudent choices to be made on issues such as optimizing the efficiency of business functions. Hence, the Commission adopts a January 1, 2006 effective date as originally proposed in the NOPR.

103. The Commission clarifies that it has no intention of requiring public utilities to report prior period information in the newly-created accounts for FERC Form 1 and 3-Q purposes. Public utilities should report prior period information in the accounts originally used, except for Account 561, Load Dispatching. Since Account 561 is being replaced by newly-created sub-accounts, public utilities should report amounts reported in Account 561 for 2005 in Account 561.2 [92] for the 2006 Form 1 filed in April 2007 and for the Form 3-Qs filed in 2006. This approach will alleviate any burden associated with reporting prior period information.

V. Changes to the FERC Quarterly and Annual Report Forms

104. The changes adopted herein will require revising the existing schedules in the FERC Forms 1, 1-F and 3-Q filed with the Commission. Appendix B contains samples of the updated or new schedules that will be included in these reports and will be available on e-Library.[93]

VI. Information Collection Statement

105. The following collections of information referenced in this Final Rule have been submitted to the Office of Management and Budget (OMB) for review under section 3507(d) of the Paperwork Reduction Act of 1995.[94] OMB's regulations require OMB to approve certain information collection requirements imposed by agency rule.[95] Upon approval of a collection of information, OMB will assign an OMB control number and expiration date. Respondents subject to the filing requirements of this Final Rule will not be penalized for failing to respond to these collections of information unless the collections of information display a valid OMB control number or the Commission had provided a justification as why the control number should be displayed.

106. The following burden estimates are for complying with this final rule as follows:

Data collectionNumber of respondentsNumber of responsesHours per responseTotal
1 Form 1 (RTOs)6135210
2 Form 1 (Non-RTOs)2141112,354
3 Form 1-F33111363
4 Form 3-Q (RTOs)6330540
5 Form 3-Q (Non-RTOs)24731511,115
Totals14,582

Information Collection Costs: The Commission has projected the average annualized cost of all respondents to be the following: 14,582 hrs. + (2 hrs recordkeeping × 253 respondents) = 15,088 hrs. @ $60 per hour = $905,280 for respondents. No capital startup costs are estimated to be incurred by respondents.

Annualized Costs (Operations & Maintenance): The costs for performing the prepared schedules are rolled into the total costs for completing the Commission's annual and quarterly financial reports.

Title: FERC Form 1, “Annual report of Major electric utilities, licensees, and others”

FERC Form 1-F, “Annual report for Nonmajor public utilities and licensees”

FERC Form 3-Q, “Quarterly financial report of electric utilities, licensees, and natural gas companies”.

Action: Information collections.

OMB Control Nos.: 1902-0021; 1902-0029; and 1902-0205.

Respondents: Businesses or other for profit.

Frequency of responses: Annually and quarterly.

Necessity of the Information: This Final Rule revises the Commission's regulations to reflect changes that are occurring in the electric industry due to the availability of open-access transmission service and increasing Start Printed Page 77637competition in the wholesale bulk power industry. The addition of these new accounts is intended to standardize accounting for transactions and events affecting public utilities and licensees, including independent system operators and regional transmission organizations that file financial reports with the Commission. The accounting regulations currently found in the USofA and related financial reporting requirements capture financial information along traditional primary business functions but do not provide sufficient detailed information concerning RTOs and, in particular, the costs incurred by these organizations as well as non-RTO public utilities that engage in similar activities. The addition of these accounts, and related changes in reporting, are intended to improve the transparency, completeness and consistency of accounting practices for the cost of assets, the expenses incurred in providing services, along with revenues collected. Without specific instructions and accounts for recording and reporting the above transactions and events, inconsistent and incomplete accounting and reporting will result.

Internal Review: The Commission has reviewed the requirements pertaining to the USofA and to the financial reports it prescribes and determined that the proposed revisions are necessary because the Commission needs to establish uniform accounting and reporting requirements for the costs of utility assets and the expenses incurred for providing services as part of utility operations.

107. These requirements conform to the Commission's plan for efficient information collection, communication, and management within the electric industry. The Commission has assured itself, by means of internal review, that there is specific, objective support for the burden estimates associated with the information requirements.

108. Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426 (Attention: Michael Miller, Office of the Executive Director, Phone (202) 502-8415, fax: (202) 273-0873, e-mail: michael.miller@ferc.gov).

109. For submitting comments concerning the collection of information(s) and the associated burden estimates, please send your comments 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) 395-4650, fax: (202) 395-7285.

VII. Environmental Analysis

110. 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.[96] No environmental consideration is necessary for the promulgation of a rule that addresses information gathering, analysis, and dissemination,[97] and also that addresses accounting.[98] This Final Rule addresses accounting. In addition, this Final Rule involves information gathering, analysis, and dissemination. Therefore, the Final Rule falls within categorical exemptions provided in the Commission's regulations. Consequently, neither an environmental impact statement nor an environmental assessment is required.

VIII. Regulatory Flexibility Act

111. The Regulatory Flexibility Act of 1980 (RFA) [99] generally requires a description and analysis of the effect that the final 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.

112. The Commission concludes that this rule would not have such an impact on a substantial number of small entities. Most companies regulated by the Commission do not fall within the RFA's definition of a small entity; [100] this rule applies principally to public utilities that own, control, or operate facilities for transmitting electric energy in interstate commerce and not electric utilities per se. The Commission also concludes that this rule will not impose a significant burden on industry since the information is already being captured by their accounting systems and generally being reported at a consolidated business level.

IX. Document Availabilty

113. 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.

114. From the Commission's Home Page on the Internet, this information is available in the Commission's management system, e-Library. The full text of this document is available on e-Library in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in e-Library, type the docket number excluding the last three digits of this document in the docket number field.

115. User assistance is available for e-Library and the Commission's website during normal business hours from our Help line at (202) 502-8222 or the Public Reference Room at (202) 502-8371, Press 0, TTY (202) 502-8659. E-Mail the Public Reference Room at public.referenceroom@ferc.gov

Effective Date and Congressional Notification

This Final Rule will take effect January 1, 2006. The Commission has determined with the concurrence of the Administrator of the Office of Information and Regulatory Affairs of the Office of Management and Budget, that this rule is not a major rule within the meaning of section 251 of the Small Business Regulatory Enforcement Fairness Act of 1996. The Commission will submit the Final Rule to both houses of Congress and the General Accounting Office.

Start List of Subjects

List of Subjects in 18 CFR Part 101

End List of Subjects Start Signature

By the Commission.

Magalie R. Salas,

Secretary.

End Signature Start Amendment Part

In consideration of the foregoing, the Commission amends Part 101, Chapter I, Title 18, Code of Federal Regulations, as follows.

End Amendment Part Start Part Start Printed Page 77638

PART 101—UNIFORM SYSTEM OF ACCOUNTS PRESCRIBED FOR PUBLIC UTILITIES AND LICENSES SUBJECT TO THE PROVISIONS OF THE FEDERAL POWER ACT

End Part Start Amendment Part

1. The authority citation for part 101 continues to read as follows:

End Amendment Part Start Authority

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352, 7651-7651o.

End Authority Start Amendment Part

2. In part 101, Definitions, redesignate definitions 30-39 as definitions 31-40 and add new definition 30.

End Amendment Part
* * * * *

30. Regional market means an organized energy market operated by a public utility, whether directly or through a contractual relationship with another entity.

Start Amendment Part

3. In part 101, Balance Sheet Chart of Accounts, Accounts 175, 176, 219, 230, 244, and 245 are added to the list:

End Amendment Part

Balance Sheet Chart of Accounts

ASSETS AND OTHER DEBITS

* * * * *

3. CURRENT AND ACCRUED ASSETS

* * * * *

175 Derivative instrument assets.

176 Derivative instrument assets-Hedges.

* * * * *

LIABILITIES AND OTHER CREDITS

5. PROPRIETARY CAPITAL

* * * * *

219 Accumulated other comprehensive income.

* * * * *

7. OTHER NONCURRENT LIABILITIES

* * * * *

230 Asset retirement obligations.

8. CURRENT AND ACCRUED LIABILITIES

* * * * *

244 Derivatives instrument liabilities.

245 Derivative instrument liabilities-Hedges.

* * * * *
Start Amendment Part

4. In part 101, Balance Sheet Accounts, Account 108, paragraph C is revised to read as follows:

End Amendment Part
* * * * *

108 Accumulated provision for depreciation of electric utility plant (Major only).

* * * * *

C. For general ledger and balance sheet purposes, this account shall be regarded and treated as a single composite provision for depreciation. For purposes of analysis, however, each utility shall maintain subsidiary records in which this account is segregated according to the following functional classification for electric plant:

(1) Steam production,

(2) Nuclear production,

(3) Hydraulic production,

(4) Other production,

(5) Transmission,

(6) Distribution,

(7) Regional Transmission and Market Operation, and

(8) General.

These subsidiary records shall reflect the current credits and debits to this account in sufficient detail to show separately for each such functional classification:

(a) The amount of accrual for depreciation,

(b) The book cost of property retired,

(c) Cost of removal,

(d) Salvage, and

(e) Other items, including recoveries from insurance.

Separate subsidiary records shall be maintained for the amount of accrued cost of removal other than legal obligations for the retirement of plant recorded in Account 108, Accumulated provision for depreciation of electric utility plant (Major only).

* * * * *
Start Amendment Part

5. In part 101, Electric Plant Chart of Accounts, Accounts 317, 326, 337, 347, 359.1, and 374 are added to the list:

End Amendment Part

Electric Plant Chart of Accounts

* * * * *

2. PRODUCTION PLANT

A. STEAM PRODUCTION

* * * * *

317 Asset retirement costs for steam production plant.

B. NUCLEAR PRODUCTION

* * * * *

326 Asset retirement costs for nuclear production plant (Major only).

* * * * *

C. HYDRAULIC PRODUCTION

* * * * *

337 Asset retirement costs for hydraulic production plant.

D. OTHER PRODUCTION

* * * * *

347 Asset retirement costs for other production plant.

3. TRANSMISSION PLANT

* * * * *

359.1 Asset retirement costs for transmission plant.

4. DISTRIBUTION PLANT

* * * * *

374 Asset retirement costs for distribution plant.

Start Amendment Part

6. In part 101, Electric Plant Chart of Accounts, 5. General Plants, is redesignated as 6. General Plants and a new section 5 with primary plant account listing is added as follows:

End Amendment Part

5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT

380 Land and land rights.

381 Structures and improvements.

382 Computer hardware.

383 Computer software.

384 Communication Equipment.

385 Miscellaneous Regional Transmission and Market Operation Plant.

386 Asset Retirement Costs for Regional Transmission and Market Operation Plant.

387 [Reserved]

Start Amendment Part

7. In part 101, Electric Plant Accounts, new primary plant accounts 380, 381, 382, 383, 384, 385, and 386 are added to read as follows:

End Amendment Part

Electric Plant Accounts

5. Regional Transmission and Market Operation Plant

* * * * *

380 Land and Land Rights

This account shall include the cost of land and land rights used in connection with regional transmission and market operations.

381 Structures and Improvements

This account shall include the cost in place of structures and improvements used for regional transmission and market operations.

382 Computer Hardware

This account shall include the cost of computer hardware and miscellaneous information technology equipment to provide scheduling, system control and dispatching, system planning, standards development, market monitoring, and market administration activities. Records shall be maintained identifying to the maximum extent practicable computer hardware owned and used for: (1) Scheduling, system control and dispatching, (2) system planning and standards development, and (3) market monitoring and market administration activities.

Items

1. Personal computers

2. Servers

3. Workstations

4. Energy Management System (EMS) hardware

5. Supervisory Control and Data Acquisition (SCADA) system hardware

6. Peripheral equipment

7. Networking components

383 Computer Software

This account shall include the cost of off-the-shelf and in-house developed software purchased and used to provide scheduling, system control and dispatching, system planning, standards Start Printed Page 77639development, market monitoring, and market administration activities. Records shall be maintained identifying to the maximum extent practicable the cost of software used for:

(1) Scheduling, system control and dispatching,

(2) System planning and standards development, and

(3) Market monitoring and market administration activities.

Items

1. Software licenses

2. User interface software

3. Modeling software

4. Database software

5. Tracking and monitoring software

6. Energy Management System (EMS) software

7. Supervisory Control and Data Acquisition (SCADA) system software

8. Evaluation and assessment system software

9. Operating, planning and transaction scheduling software

10. Reliability applications

11. Market application software

384 Communication Equipment

This account shall include the cost of communication equipment owned and used to acquire or share data and information used to control and dispatch the system.

Items

1. Fiber optic cable

2. Remote terminal units

3. Microwave towers

4. Global Positioning System (GPS) equipment

5. Servers

6. Workstations

7. Telephones

385 Miscellaneous Regional Transmission and Market Operation Plant

This account shall include the cost of regional transmission and market operation plant and equipment not provided for elsewhere,

386 Asset Retirement Costs for Regional Transmission and Market Operation Plant

This account shall include asset retirement costs on regional control and market operation plant and equipment.

Start Amendment Part

8. In part 101, Electric Plant Chart of Accounts, under newly redesignated 6. General Plant, a new Account 399.1 is added to the list.

End Amendment Part

399.1 Asset retirement costs for general plant.

Start Amendment Part

9. In part 101, Operating Revenue Chart of Accounts, new Accounts 456.1, 457.1 and 457.2 are added to the other operating revenue listing as follows:

End Amendment Part

Operating Revenue Chart of Accounts

* * * * *

2. OTHER OPERATING REVENUES

456.1 Revenues from transmission of electricity of others.

457.1 Regional transmission service revenues.

457.2 Miscellaneous revenues.

Start Amendment Part

10. In part 101, Income Accounts, Account 456, Item 5 is removed, and Item 6 is redesignated as Item 5.

End Amendment Part Start Amendment Part

11. In part 101, Income Accounts, new revenue accounts 456.1, 457.1, and 457.2 are added to read as follows:

End Amendment Part

Operating Revenue Accounts

* * * * *

456.1 Revenues From Transmission of Electricity of Others

This account shall include revenues from transmission of electricity of others over transmission facilities of the utility.

457.1 Regional Transmission Service Revenues

This account shall include revenues derived from providing scheduling, system control and dispatching services. Include also in this account reimbursements for system planning, standards development, and market monitoring and market compliance activities. Records shall be maintained so as to show: (1) The services supplied and revenues received from each customer and (2) the amounts billed by tariff or specified rates.

457.2 Miscellaneous Revenues

This account shall include revenues and reimbursements for costs incurred by regional transmission service providers not provided for elsewhere. Records shall be maintained so as to show: (1) The services supplied and revenues received from each customer, and (2) the amounts billed by tariff or specified rates.

Start Amendment Part

12. In part 101, Operation and Maintenance Expense Chart of Accounts, 3. Distribution Expenses is redesignated as 4. Distribution Expenses; 4. Customer Accounts Expenses is redesignated as 5. Customer Accounts Expenses; 5. Customer Service and Informational Expenses is redesignated as 6. Customer Service and Informational Expenses; 6. Sales Expense is redesignated as 7. Sales Expenses; and 7. Administrative and General Expenses is redesignated as 8. Administrative and General Expenses.

End Amendment Part Start Amendment Part

13. In part 101, Operation and Maintenance Expense Chart of Accounts, a new Regional Market Expenses function is added and new Accounts 575.1 575.2, 575.3, 575.4, 575.5, 575.6, 575.7, 575.8, 576.1, 576.2, 576.3, 576.4 and 576.5 are added as follows:

End Amendment Part

Operation and Maintenance Expense Chart of Accounts

* * * * *

3. REGIONAL MARKET EXPENSES

Operation

575.1 Operation Supervision.

575.2 Day-ahead and real-time market facilitation.

575.3 Transmission rights market facilitation.

575.4 Capacity market facilitation.

575.5 Ancillary services market facilitation.

575.6 Market monitoring and compliance.

575.7 Market facilitation, monitoring and compliance services.

575.8 Rents.

Maintenance

576.1 Maintenance of structures and improvements.

576.2 Maintenance of computer hardware.

576.3 Maintenance of computer software.

576.4 Maintenance of communication equipment.

576.5 Maintenance of miscellaneous market operation plant.

Start Amendment Part

14. In part 101, Operation and Maintenance Expense Chart of Accounts, the listing of transmission expenses is revised as follows:

End Amendment Part

Operation and Maintenance Expense Chart of Accounts

* * * * *

2. TRANSMISSION EXPENSES

Operation

560 Operation supervision and engineering.

561.1 Load dispatch—Reliability.

561.2 Load dispatch—Monitor and operate transmission system.

561.3 Load dispatch—Transmission service and scheduling.

561.4 Scheduling, system control and dispatch services.

561.5 Reliability planning and standards development.

561.6 Transmission service studies.

561.7 Generation interconnection studies.

561.8 Reliability planning and standards development services.

562 Station expenses (Major only).

563 Overhead line expenses (Major only).

564 Underground line expenses (Major only).

565 Transmission of electricity by others (Major only).

566 Miscellaneous transmission expenses (Major only).

567 Rents.

567.1 Operation supplies and expenses (Nonmajor only).

Maintenance

568 Maintenance supervision and engineering (Major only).Start Printed Page 77640

569 Maintenance of structures (Major only).

569.1 Maintenance of computer hardware.

569.2 Maintenance of computer software.

569.3 Maintenance of communication equipment.

569.4 Maintenance of miscellaneous regional transmission plant.

570 Maintenance of station equipment (Major only).

571 Maintenance of overhead lines (Major only).

572 Maintenance of underground lines (Major only).

573 Maintenance of miscellaneous transmission plant (Major only).

574 Maintenance of transmission plant (Nonmajor only).

Start Amendment Part

15. In part 101, Operation and Maintenance Expense Accounts, the first paragraph of Account 556 instruction is revised to read as follows:

End Amendment Part

Operation and Maintenance Expense Accounts

* * * * *

556 System Control and Load Dispatching (Major Only)

This account shall include the cost of labor and expenses incurred in load dispatching activities for system control. Utilities having an interconnected electric system or operating under a central authority which controls the production and dispatching of electricity may apportion these costs to this account and transmission expense Accounts 561.1 through 561.4, and Account 581, Load Dispatching-Distribution.

Start Amendment Part

16. In part 101, Operation and Maintenance Expense Accounts, Account 561, Load Dispatching (Major only) is removed.

End Amendment Part Start Amendment Part

17. In part 101, Operation and Maintenance Expense Accounts, new expense accounts 561.1, 561.2, 561.3, 561.4, 561.5, 561.6, 561.7, 561.8, 569.1, 569.2, 569.3, 575.1, 575.2, 575.3, 575.4, 575.5, 575.6, 575.7, 575.8, 576.1, 576.2, 576.3, 576.4 and 576.5 are added to read as follows:

End Amendment Part

Operation and Maintenance Expense Accounts

* * * * *

561.1 Load Dispatch—Reliability

This account shall include the cost of labor, materials used and expenses incurred by a regional transmission service provider or other transmission provider to manage the reliability coordination function as specified by the North American Electric Reliability Council (NERC) and individual reliability organizations. These activities shall include performing current and next day reliability analysis. This account shall include the costs incurred to calculate load forecasts, and performing contingency analysis.

561.2 Load Dispatch—Monitor and Operate Transmission System

This account shall include the costs of labor, materials used and expenses incurred by a regional transmission service provider or other transmission provider to monitor, assess and operate the power system and individual transmission facilities in real-time to maintain safe and reliable operation of the transmission system. This account shall also include the expense incurred to manage transmission facilities to maintain system reliability and to monitor the real-time flows and direct actions according to regional plans and tariffs as necessary.

Items

1. Receive and analyze outage requests

2. Reschedule outage plans

3. Monitor solution quality field data values, providing model updates to NERC and coordinating network model changes across all systems

4. Conduct operating training related to NERC certification

5. Monitor generation resources and communicate expected dispatch actions

6. Ensure ancillary service requirements are met

7. Directing switching

8. Controlling system voltages

9. Obtaining reports on the weather and special events

10. Preparing operating reports and data for billing and budget purposes

561.3 Load Dispatch—Transmission Service and Scheduling

This account shall include the costs of labor, materials used and expenses incurred by a regional transmission service provider or other transmission provider to process hourly, daily, weekly and monthly transmission service requests using an automated system such as an Open Access Same-Time Information System (OASIS). It shall also include the expenses incurred to operate the automated transmission service request system and to monitor the status of all scheduled energy transactions.

561.4 Scheduling, System Control and Dispatching Services

This account shall include the costs billed to the transmission owner, load serving entity or generator for scheduling, system control and dispatching service. Include in this account service billings for system control to maintain the reliability of the transmission area in accordance with reliability standards, maintaining defined voltage profiles, and monitoring operations of the transmission facilities.

561.5 Reliability, Planning and Standards Development

This account shall include the cost of labor, materials used and expenses incurred for the system planning of the interconnected bulk electric transmission systems within a planning authority area.

Items

1. Developing and maintaining transmission system models to evaluate transmission system performance.

2. Maintaining and applying methodologies and tools for the analysis and simulation of the transmission systems for the assessment and development of transmission expansion plans.

3. Assessing, developing and documenting transmission expansion plans.

4. Maintaining transmission system models (steady-state, dynamics, and short circuit).

5. Collecting transmission information and transmission facility characteristics and ratings.

6. Notifying participants of any planned transmission changes that may impact their facilities.

7. Developing and reporting on transmission expansion plans for assessment and compliance with reliability standards.

8. Developing reliability standards for the planning and operation of the interconnected bulk electric transmission systems that serve the United States, Canada, and Mexico.

9. Developing criteria and certification procedures for reliability authorities, transmission operators and others.

10. Outside services employed.

Note:

The cost of supervision, customer records and collection expenses, administrative and general salaries, office supplies and expenses, property insurance, injuries and damages, employee pension and benefits, regulatory commission expenses, general advertising, and rents shall be charged to the customer accounts, service, and administrative and general expense accounts contained in the Uniform System of Accounts.

561.6 Transmission Service Studies

This account shall include the cost of labor, materials used and expenses incurred to conduct transmission services studies for proposed interconnections with the transmission system. Detailed records shall be Start Printed Page 77641maintained for each study undertaken and all reimbursements received for conducting such a study.

561.7 Generation Interconnection Studies

This account shall include the cost of labor, materials used and expenses incurred to conduct generation interconnection studies for proposed interconnections with the transmission system. Detailed records shall be maintained for each study undertaken and all reimbursements received for conducting such a study.

561.8 Reliability Planning and Standards Development Services

This account shall include the costs billed to the transmission owner, load serving entity, or generator for system planning of the interconnected bulk electric transmission system. Include also the costs billed by the regional transmission service provider for system reliability and resource planning to develop long-term strategies to meet customer demand and energy requirements. This account shall also include fees and expenses for outside services incurred by the regional transmission service provider and billed to the load serving entity, transmission owner or generator.

* * * * *

569.1 Maintenance of Computer Hardware

This account shall include the cost of labor, materials used and expenses incurred in the maintenance of computer hardware serving the transmission function.

569.2 Maintenance of Computer Software

This account shall include the cost of labor, materials used and expenses incurred for annual computer software license renewals, annual software update services and the cost of ongoing support for software products serving the transmission function.

Items

1. Telephone support

2. Onsite support

3. Software updates and minor revisions

569.3 Maintenance of Communication Equipment

This account shall include the cost of labor, materials used and expenses incurred in the maintenance of communication equipment serving the transmission function.

569.4 Maintenance of Miscellaneous Regional Transmission Plant

This account shall include the cost of labor, materials used and expenses incurred in the maintenance of miscellaneous regional transmission plant serving the transmission function.

* * * * *

575.1 Operation Supervision

This account shall include the cost of labor and expenses incurred in the general supervision and direction of the regional energy markets.

575.2 Day-Ahead and Real-Time Market Administration

This account shall include the cost of labor, materials used and expenses incurred to facilitate the Day-Ahead and Real-Time markets. This account shall also include the costs incurred to manage the real-time deployment of resources to meet generation needs and to provide capacity adequacy verification. Include in this account the costs incurred to maintain related sections of the tariff, market rules, operating procedures, and standards and coordinating with neighboring areas.

Items

1. Consultant fees and expenses

2. System record and report forms

3. Meals, traveling and incidental expenses

Note:

The cost of supervision, customer records and collection expenses, administrative and general salaries, office supplies and expenses, property insurance, injuries and damages, employee pension and benefits, regulatory commission expenses, general advertising, and rents shall be charged to the customer accounts, service, and administrative and general expense accounts contained in the Uniform System of Accounts.

575.3 Transmission Rights Market Administration

This account shall include the cost of labor, materials used and expenses incurred to manage the allocation and auction of transmission rights.

575.4 Capacity Market Administration

This account shall include the cost of labor, materials used and expenses incurred to manage the allocation of capacity rights.

575.5 Ancillary Services Market Administration

This account shall include the cost of labor, materials used and expenses incurred to manage all other ancillary services market functions.

575.6 Market Monitoring and Compliance

This account shall include the cost of labor, materials used and expenses incurred to review market data and operational decisions for compliance with market rules. It shall also include the costs incurred to interface with external market monitors.

575.7 Market Administration, Monitoring and Compliance Services

This account shall include the costs billed to the transmission owner, load serving entity or generator for market administration, monitoring and compliance services.

575.8 Rents

This account shall include all rents of property of others used, occupied, or operated in connection with market administration and monitoring. (See operating expense instruction 3.)

576.1 Maintenance of Structures and Improvements

This account shall include the cost of labor, materials used and expenses incurred in the maintenance of structures used in market administration and monitoring. (See operating expense instruction 2.)

576.2 Maintenance of Computer Hardware

The account shall include the cost of labor, materials used and expenses incurred in the maintenance of computer hardware used in market administration and monitoring.

576.3 Maintenance of Computer Software

This account shall include the cost of labor, materials used and expenses incurred for annual computer software license renewals, annual software update services and the cost of ongoing support for software products used in market administration and monitoring.

Items

1. Telephone support

2. Onsite support

3. Software updates and minor revisions

576.4 Maintenance of Communication Equipment

This account shall include the cost of labor, materials used and expenses incurred in the maintenance of communication equipment used in market administration and monitoring.

576.5 Maintenance of Miscellaneous Market Operation Plant

This account shall include the cost of labor, materials used and expenses Start Printed Page 77642incurred in the maintenance of miscellaneous market operation plant used in market administration and monitoring.

Note:

The following appendices, A and B, will not appear in the Code of Federal Regulations.

Appendix A—List of Commenters

1 American Public Power Association (APPA)

2 Arizona Public Service Company (APS)

3 Cinergy Services, Inc. (Cinergy) [101]

4 City of Santa Clara, California/dba Silicon Valley Power (City of Santa Clara)

5 Electricity Consumers Resource Council (ELCON)

6 The Independent Electricity System Operator of Ontario (IESO)

7 Indicated New York Transmission Owners (Indicated NYTOs) [102]

8 International Transmission Company (International Transmission)

9 The Iowa Utilities Board (Iowa Board)

10 ISO/RTO Council [103]

11 FirstEnergy Service Company (FirstEnergy) [104]

12 Madison Gas & Electric Company (MGE)

13 Massachusetts Municipal Wholesale Electric Company (MMWEC)

14 Midwest ISO Transmission Owners [105]

15 National Rural Electric Cooperative Association (NRECA)

16 National Grid USA

17 The New England Power Pool Participants Committee (NEPOOL Participants Committee)

18 NiSource Inc. (NiSource)

19 Southern California Edison Company (SCE)

20 The Transmission Agency of Northern California (TANC)

21 Transmission Access Policy Study Group (TAPS)

22 Wisconsin Electric Power Company (Wisconsin Electric)

Start Printed Page 77643

Start Printed Page 77644

Start Printed Page 77645

Start Printed Page 77646

Start Printed Page 77647

Start Printed Page 77648

Start Printed Page 77649

Start Printed Page 77650

Start Printed Page 77651

Start Printed Page 77652

Start Printed Page 77653

Start Printed Page 77654

Start Printed Page 77655

Start Printed Page 77656

Start Printed Page 77657

Start Printed Page 77658

Start Printed Page 77659

Start Printed Page 77660

Start Printed Page 77661

End Supplemental Information

Footnotes

2.  See Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 61 FR 21,540 (May 10, 1996), FERC Stats. & Regs. ¶ 31,036 (1996), order on reh'g, Order No. 888-A, 62 FR 12,274 (March 14, 1977), FERC Stats. & Regs. ¶ 31,048 (1997), order on reh'g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff'd in relevant part sub nom. Transmission Access Policy Study Group, v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).

Back to Citation

3.  See Regional Transmission Organizations, Order No. 2000, 65 FR 809 (January 6, 2000), FERC Stats. & Regs. ¶ 31,089 (1999), order on reh'g, Order No. 2000-A, 65 FR 12,088 (March 8, 2000), FERC Stats. & Regs. ¶ 31,092 (2000), affirmed sub nom. Public Utility District No. 1 of Snohomish County, Washington, v. FERC, 272 F.3d 607 (D.C. Cir. 2001).

Back to Citation

4.  See, e.g., the California Independent System Operator Corporation (CAISO), the Midwest Independent Transmission System Operator, Inc. (Midwest ISO), the ISO New England, Inc. (ISO-NE), the New York Independent System Operator, Inc. (NYISO), PJM Interconnection, L.L.C. (PJM), and the Southwest Power Pool, Inc. (SPP).

Back to Citation

5.  See Financial Reporting and Cost Accounting and Recovery Practices for Regional Transmission Organizations and Independent System Operators, 69 FR 58,112 (September 29, 2004), FERC Stats. & Regs. ¶ 35,546 (2004).

Back to Citation

6.  Accounting and Financial Reporting for Public Utilities Including RTOs, 70 FR 36865 (June 27, 2005); FERC Stats. and Regs. ¶ 32,585.

Back to Citation

7.  See Appendix A for list of commenters.

Back to Citation

8.  See generally National Grid, NRECA, Indicated NYTOs, and TANC.

Back to Citation

9.  NOPR at P 20-32.

Back to Citation

10.  City of Santa Clara at 23.

Back to Citation

11.  NOPR at P 33-35.

Back to Citation

12.  See, e.g., APPA at 19, ISO/RTO Council at 2.

Back to Citation

13.  See TANC at 12.

Back to Citation

14.  See SVP at 20.

Back to Citation

15.  NOPR at P 36-51.

Back to Citation

16.  See FERC Form 1 at 328-330.

Back to Citation

17.  See, e.g., ISO/RTO Council at 2.

Back to Citation

18.  See, e.g., EEI at 2.

Back to Citation

19.  See APPA at 18.

Back to Citation

20.  APPA at 19.

Back to Citation

21.  TANC at 2 and SVP at 27.

Back to Citation

22.  NRECA at 8.

Back to Citation

23.  See ISO/RTO Council at 5.

Back to Citation

24.  NOPR at P 52-53.

Back to Citation

25.  See EEI at 4, SCE at 2, FirstEnergy at 8.

Back to Citation

26.  EEI at 9.

Back to Citation

27.  SCE at 2.

Back to Citation

28.  International Transmission at 5.

Back to Citation

29.  FirstEnergy at 17.

Back to Citation

30.  SCE at 3.

Back to Citation

31.  FirstEnergy at 16.

Back to Citation

32.  EEI at 9.

Back to Citation

33.  SVP at 35.

Back to Citation

34.  EEI at 9.

Back to Citation

35.  NOPR at P 54, 56-59.

Back to Citation

36.  NYTOs at 2.

Back to Citation

37.  Id. at 7.

Back to Citation

38.  Id. at 10.

Back to Citation

39.  EEI at 8.

Back to Citation

40.  International Transmission at 3.

Back to Citation

41.  APPA at 19.

Back to Citation

42.  See SCE at 3.

Back to Citation

43.  NOPR at P 60-62.

Back to Citation

44.  See, e.g., National Grid at 9-10.

Back to Citation

45.  National Grid at 9-10.

Back to Citation

46.  See Indicated NYTO at 9-10.

Back to Citation

47.  See City of Santa Clara, California at 21-22.

Back to Citation

48.  NOPR at P 63.

Back to Citation

49.  Id. at P 64.

Back to Citation

50.  National Grid at 10-12, Indicated NYTOs at 6-10.

Back to Citation

51.  National Grid at 10-12.

Back to Citation

52.  Indicated NYTOs at 6-10.

Back to Citation

53.  NOPR at P 65-68.

Back to Citation

54.  See City of Santa Clara, California at 25-26, EEI at 7-8.

Back to Citation

55.  First Energy at 17.

Back to Citation

56.  See ISO/RTO Council at 3-4.

Back to Citation

57.  NOPR at P 73-74.

Back to Citation

58.  TAPS at 6-8, International Transmission at 7.

Back to Citation

59.  TAPS at 6-8.

Back to Citation

60.  NOPR at P 75-79.

Back to Citation

61.  See APPA at 2, NRECA at 4.

Back to Citation

62.  NRECA at 5.

Back to Citation

63.  APPA at 2.

Back to Citation

64.  See First Energy at 15, MGE at 2, Wisconsin Electric at 3, EEI at 6, APS at 3, Cinergy at 4, NYTOs at 12, SCE at 1.

Back to Citation

65.  See MGE at 3.

Back to Citation

66.  EEI at 6, First Energy at 16, Wisconsin Electric at 4.

Back to Citation

67.  EEI at 7, First Energy at 16.

Back to Citation

68.  NRECA at 3.

Back to Citation

69.  MGE at 3.

Back to Citation

70.  Wisconsin Electric at 4.

Back to Citation

71.  EEI at 7.

Back to Citation

72.  See FirstEnergy at 13, International Transmission at 4, EEI at 10.

Back to Citation

73.  See FirstEnergy at 1-2, 13-15, International Transmission at 3-4.

Back to Citation

74.  International Transmission at 3-4, FirstEnergy at 14.

Back to Citation

75.  FirstEnergy at 14.

Back to Citation

77.  International Transmission at 4.

Back to Citation

78.  See, e.g., ELCON at 1, IESO at 2.

Back to Citation

79.  See NRECA at 2.

Back to Citation

80.  Indicated NYTOs at 2, 5-6.

Back to Citation

81.  See, e.g., NEPOOL Participants Committee at 1-5.

Back to Citation

82.  See, e.g., Cinergy and Midwest ISO Transmission Owners.

Back to Citation

83.  Midwest ISO Transmission Owners at 5, citing Midwest Independent Transmission System Operators, Inc., 101 FERC ¶ 61,221 (2002).

Back to Citation

84.  NOPR at P 80.

Back to Citation

85.  Id. at P 82.

Back to Citation

86.  See EEI at 11-12, SoCal ED at 4, First Energy at 11-13.

Back to Citation

87.  First Energy at 11-13.

Back to Citation

88.  EEI at 11.

Back to Citation

89.  See National Grid at 13-14, Indicated NYTOs at 11-12.

Back to Citation

90.  See APPA at 7-8.

Back to Citation

91.  See EEI at 12.

Back to Citation

92.  This is for reporting purposes only and no amounts should be reclassified for accounting purposes.

Back to Citation

93.  Appendix B will not be published in the Federal Register.

Back to Citation

94.  See 44 U.S.C. 3507(d) (2000).

Back to Citation

96.  See Regulations Implementing the National Environmental Policy Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 (1987).

Back to Citation

98.  See 18 CFR 380.4(c)(16).

Back to Citation

99.  See 5 U.S.C. 601-612 (2000).

Back to Citation

100.  See 5 U.S.C. 601(3) citing to section 3 of the Small Business Act, 15 U.S.C. 632. Section 3 of the Small Business Act defines a “small-business concern” as a business which is independently owned and operated and which is not dominant in its field of operation. The Small Business Size Standards component of the North American Industry Classification System defines a small electric utility as one that, including its affiliates, is primarily engaged in generation, transmission, and/or distribution of electric energy for sale and whose total electric output for the preceding fiscal years did not exceed 4 million MWh. 13 CFR 121.201.

Back to Citation

101.  Cinergy Services filed comments on behalf of its franchised utility affiliates, The Cincinnati Gas & Electric Company, PSI Energy, Inc., and The Union Light, Heat and Power Company (collectively, Cinergy)

Back to Citation

102.  Indicated NYTOs includes: Central Hudson Gas & Electric Corporation; Consolidated Edison Company of New York, Inc.; LIPA; New York Power Authority; New York Electric & Gas Corporation; Orange and Rockland Utilities, Inc.; and Rochester Gas and Electric Corporation.

Back to Citation

103.  ISO/RTO Council includes: The Alberta Electric System Operator; California Independent System Operators, Inc.; Electric Reliability Council of Texas; the Independent Electricity System of Ontario, Inc.; ISO New England, Inc.; Midwest Independent Transmission System Operators, Inc; New York Independent System Operators, Inc.; PJM Interconnection, L.L.C.; and Southwest Power Pool.

Back to Citation

104.  FirstEnergy filed on behalf of its electric utility operating company affiliates: Ohio Edison Company; The Toledo Edison Company; the Cleveland Electric Illuminating Company; Pennsylvania Power Company; American Transmission System, Inc; Jersey Central Power & Light Company; Pennsylvania Electric Company; and Metropolitan Edison Company.

Back to Citation

105.  The Midwest ISO Transmission Owners for this filing consist of: Ameren Services Company, as agent for Union Electric Company d/b/a AmerenUE, Central Illinois Public Service Company d/b/a AmerenCIPS, Central Illinois Light Co. d/b/a AmerenCilco, and Illinois Power Company d/b/a AmerenIP; Alliant Energy Corporate Services, Inc. on behalf of its operating company affiliate Interstate Power and Light Company (f/k/a IES Utilities Inc. and Interstate Power Company); American Transmission Systems, Incorporated, a subsidiary of FirstEnergy Corp.; Aquila, Inc. d/b/a Aquila Networks (f/k/a Utilicorp United, Inc.); City Water, Light & Power (Springfield, IL); Great River Energy; Hoosier Energy Rural Electric Cooperative, Inc.; Indiana Municipal Power Agency; Indianapolis Power & Light Company; LG&E Energy LLC (for Louisville Gas and Electric Company and Kentucky Utilities Company); Minnesota Power (and its subsidiary Superior Water, L&P); Montana-Dakota Utilities Co.; Northern Indiana Public Service Company; Northern States Power Company and Northern States Power Company (Wisconsin), subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric Company; Otter Tail Corporation d/b/a Otter Tail Power Company; Southern Illinois Power Cooperative; Southern Indiana Gas & Electric Company (d/b/a Vectren Energy Delivery of Indiana); and Wabash Valley Power Association, Inc.

Back to Citation

BILLING CODE 6717-01-P

[FR Doc. 05-24388 Filed 12-29-05; 8:45 am]

BILLING CODE 6717-01-C