03-1699. Proposed Pricing Policy for Efficient Operation and Expansion of Transmission Grid

January 15, 2003.

AGENCY:

Federal Energy Regulatory Commission, DOE.

ACTION:

Notice of proposed policy statement

SUMMARY:

The Federal Energy Regulatory Commission (Commission) proposes a new pricing policy for the rates of transmission owners that transfer operational control of their transmission facilities to a Regional Transmission Organization (RTO), form independent transmission companies (ITCs) within RTOs, or pursue additional measures that promote efficient operation and expansion of the transmission grid. The proposed policy would create rate incentives that reward RTO and ITC formation and grid investment, because independent regional grid operation and coordination will improve grid performance, reduce wholesale transmission and transactions costs, improve electric reliability, and make electric wholesale competition more effective in ways that benefit all customers. We invite comments on the proposed policy statement.

DATES:

Comments are due March 13, 2003.

ADDRESSES:

Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426.

FOR FURTHER INFORMATION CONTACT:

Stephen Pointer (Technical Information), Office of Markets, Tariffs and Rates, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [phone].

Andre Goodson (Legal Information), Office of General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [phone].

SUPPLEMENTARY INFORMATION:

I. Introduction

1. The Federal Energy Regulatory Commission proposes a new policy for the rates of transmission owners operating within a Regional Transmission Organization (RTO). Because they are independent of market participants, RTOs and Independent Transmission Companies (ITCs) make competitive wholesale electric markets more efficient, fair, trustworthy, and cost-effective. This new policy will reward transmission owners for joining RTOs and turning their assets over for RTO operation. It will reward transmission owners for forming ITCs or taking other measures which make their transmission facilities operationally independent from the activities of other market participants. It will reward transmission owners for pursuing additional measures to operate and expand the transmission grid efficiently in ways that solve RTO-identified system needs using either classic transmission investments or innovative technologies. However, only transmission owners which participate in RTOs will be able to take advantage of these incentives. This policy will promote competitive wholesale electric markets, reduce wholesale electric costs and improve electric reliability.

II. Summary of Proposed Incentives

2. Under this proposed policy: (1) Any entity that transfers operational control of transmission facilities to a Commission-approved RTO would qualify for an incentive adder of 50 basis points on its return on equity (ROE) for all such facilities transferred; (2) ITCs that participate in RTOs and meet the independent ownership requirement (discussed below) would qualify for an additional incentive equivalent to 150 basis points applied to the book value of facilities at the time of the divestiture; and (3) we also propose a generic ROE-based incentive equal to 100 basis points for investment in new transmission facilities which are found appropriate pursuant to an RTO planning process.

III. Background

A. Order No. 2000

3. We adopted Order No. 2000^[1] to encourage voluntary and timely formation of RTOs. Order No. 2000 found that transmission facilities can be operated more reliably and efficiently when coordinated over large geographic areas, and that RTOs would achieve this result by establishing: regional transmission pricing and the elimination of rate pancaking; improved congestion management; more accurate estimates of available transmission capacity (ATC); more effective management of parallel path flows; more efficient planning for transmission and generation investment; and improved grid reliability. It concluded that RTOs would help eliminate the opportunity for unduly discriminatory practices by transmission providers, reduce the need for overly intrusive regulatory oversight, and instill trust among competitors that all are playing by the same rules.

4. Order No. 2000 recognized that realization of “effective and efficient RTOs is dependent in large measure on the feasibility and vitality of the stand-alone transmission business.”^[2] It also found that transmission pricing reforms may be needed to facilitate both RTO formation and the formation of stand-alone transmission businesses such as ITCs. The order discussed various innovative rate options and identified specific innovative rate mechanisms that we would consider for entities that meet the minimum characteristics of RTOs.^[3] In identifying the specific innovative rate mechanisms (including performance-based rates) that we would consider for entities that meet the minimum characteristics of RTOs, Order No. 2000 neither prescribed a specific transmission pricing method nor guaranteed approval of any particular innovative pricing proposal. All innovative pricing proposals should be fully justified:

The [a]pplicant [for innovative rate treatments] must explain how the proposed rate treatment would help achieve the goals of RTOs, including efficient use of and investment in the transmission system and reliability benefits to consumers; provide a cost-benefit analysis, including rate impacts; and explain why the proposed rate treatment is appropriate for the RTO proposed by the Applicant. This means that filings under section 35.34(e) must be complete and fully explained; must demonstrate that the resulting rates are just, reasonable, and not unduly discriminatory or preferential; must identify how the rate treatment promotes efficiency and what benefits result; and must demonstrate that the rate treatment does not impede the RTO from meeting the minimum characteristics and functions required under Order No. 2000.^[4]

B. Experience since Order No. 2000

5. Order No. 2000 called for RTOs to be in operation across the nation by December 2001. While the industry is making significant progress in the development of RTOs and we have preliminarily approved seven RTO proposals, only two of those have become fully approved RTOs—Midwest Independent Transmission System Operator, Inc. (Midwest ISO), which began operating in early 2002, and PJM Interconnection, L.L.C. (PJM).^[5] Moreover, while we have found that ITCs would be instrumental in achieving the goals of Order No. 2000, only one ITC—Michigan Electric Transmission Company, LLC (Michigan Transco)—is currently operating.

1. Innovative Rates for Independence

6. To date we have approved incentive rates for RTO participation and additional levels of independence on a case-by-case basis. In International Transmission Company,^[6] we conditionally approved a transmission rate moratorium based on the transmission component of bundled retail rates, and recovery of an amount necessary to hold the seller harmless from the income tax consequences of the divestiture of transmission assets, subject to the company becoming a fully independent transmission company (with no active or passive ownership by market participants) and fully participating in a Commission-approved RTO by a date certain.^[7] We stated:

We are cognizant of the risks [International Transmission Company] has assumed under this proposal and believe that its willingness to bear the financial risks of failing to meet the conditions [of Commission approval] is an example of the different approach to the transmission business that we can expect from a stand-alone transmission company. We also believe that accelerated development of independent stand-alone transmission businesses will lead to an accelerated transition to competitive, regional bulk power markets and is in the best interest of consumers.^[8]

7. In Trans-Elect, Inc., et al.,^[9] a newly formed ITC, we conditionally approved a rate moratorium based on the transmission component of bundled retail rates, effective upon the transfer of operational control of transmission facilities to an approved RTO.^[10] Further, we approved rate recovery of an amount equal to the value of deferred taxes on the seller's books at the time of the sale associated with the difference between tax and book basis of transmission plant, with cost recovery over twenty years beginning January 1, 2006, as long as Michigan Transco joins and remains in a Commission-approved RTO.

8. In Midwest Independent Transmission System Operator, Inc.,^[11] we permitted an upward adjustment of 50 basis points to the proxy group's ROE midpoint for use by all participating transmission owning utilities, and left open the possibility of additional upward adjustments, based on the Midwest ISO's level of operational independence:

There are, however, policy reasons to make upward adjustments—particularly with regard to the level of operational independence that the Midwest ISO provides. In this case, we will make an upward adjustment of 50 basis points from the proxy group midpoint for the turning over of operational control of transmission facilities. We will consider providing additional upward adjustments for greater levels of independence.^[12]

2. Merchant Transmission

9. We have conditionally approved rates, terms and conditions for service over merchant transmission facilities. The basic features of the rate treatments allowed for merchant transmission facilities include negotiated rates with the project sponsor assuming all market risk associated with the project and all capacity initially allocated through a fair, non-discriminatory and transparent open season process. Additionally, we required that operational control of the facilities be turned over to an RTO adjacent to or containing the geographic area of the proposed facility and that service be provided under the OATT of the RTO.

10. For example, we conditionally approved the rates, terms and conditions proposed by TransEnergie U.S. Ltd. (TransEnergie) for service over three proposed merchant transmission projects.^[13] The first project, the Cross-Sound Cable (CSC) Interconnector, uses an undersea high-voltage direct current (HVDC) cable system to connect the New England Power Pool (NEPOOL) regional transmission system in Connecticut to the New York Independent Transmission System Operator (NYISO) transmission system on Long Island. We also authorized TransEnergie to provide service over a merchant transmission facility, the Harbor Cable interconnector project, an underground and undersea HVDC transmission cable system that would connect the PJM and NYISO transmission systems.^[14] Finally, we authorized TransEnergie's proposal with Hydro One Delivery Services, Inc., to provide transmission service over the Lake Erie Link, which is planned as an underwater HVDC transmission system connecting the Ontario Independent Electricity Market Operator to either PJM or the Midwest ISO.^[15]

11. Similarly, we conditionally approved the rates, terms and conditions proposed by Neptune Regional Transmission System, LLC, (Neptune) for service over its planned merchant transmission facilities.^[16] Neptune proposed to build in four stages several thousand miles of undersea high-voltage direct current transmission lines and associated facilities to connect Maine, New Brunswick and Nova Scotia with capacity-constrained markets in Boston, New York City, Long Island, and Connecticut.

12. We also conditionally authorized a proposal by Northeast Utilities Service Company (NUSCO) to construct a merchant transmission project consisting of a 330 MW direct current cable under Long Island Sound, Connecticut-Long Island Cable.^[17]

3. Western Orders

13. We issued a series of orders (Western Orders) to remove obstacles to increased energy supply in the West in response to the severe electric energy crisis facing California and the Western United States during 2000-2001.^[18] The Western Orders waived prior notice requirements and granted authorization of market-based rates for wholesale power sales from generation used primarily for back-up and self-generation, authorized the resale of load reductions at wholesale at market-based rates, waived prior notice requirements for wholesale contract modifications to facilitate demand-side management, permitted demand side management costs to be treated consistently with other types of incremental and out-of-pocket costs, and allowed premiums on equity returns and accelerated depreciation for projects that increase electric transmission capacity and could be in service by November 1, 2002.

4. SMD NOPR

14. On July 31, 2002, we issued a notice of proposed rulemaking that proposed a framework to remedy remaining undue discrimination in the provision of interstate transmission services and in other industry practices.^[19] The SMD NOPR also proposed to create “seamless” wholesale power markets that allow sellers to transact easily across transmission grid boundaries, through the implementation of standardized transmission service and spot markets and through the elimination of rate pancaking, among other things. Because of their regional scope and configuration, we believe that RTOs can most quickly and efficiently implement standardized transmission service and spot markets and most effectively eliminate rate pancaking.

15. The SMD NOPR points out other concerns identified by market participants through formal complaints, hotline calls, public conferences, and pleadings. Market participants complain about the difficulties they have experienced in gaining equal access to the transmission grid to compete with vertically integrated utilities. Market participants also complain that companies that own both transmission and generation under-invest in transmission because the resulting competitive entry often decreases the value of their generation assets. Much of this problem is directly attributable to the remaining incentives and ability of vertically integrated utilities to exercise transmission market power to protect their own generation market share. Independent transmission providers and owners, operating under a common set of rules, would solve these problems.

16. The SMD NOPR noted that we have long recognized that the ITC business model can bring significant benefits to the industry:

Their for-profit nature with a focus on the transmission business is ideally suited to bring about: (1) Improved asset management including increased investment; (2) improved access to capital markets given a more focused business model than that of vertically integrated utilities; (3) development of innovative services; and (4) additional independence from market participants.^[20]

It concluded that these characteristics of ITCs can have significant benefits for the implementation of Standard Market Design, particularly in the areas of development of transmission infrastructure and structural independence from market participants.^[21]

17. The SMD NOPR also proposes that independent transmission providers institute locational marginal pricing to provide market participants with efficient price signals. We expect such price signals to facilitate efficient operation and expansion of the grid; but these price signals alone will not achieve efficient grid operation and expansion in many cases. ITCs would be more likely to relieve congestion through transmission investment than a company that benefits from the value of generation in constrained areas.

18. This proposed policy statement supports the SMD NOPR and Order No. 2000 goals of RTO formation and participation and a standardized, independent competitive wholesale electricity market by creating incentives for RTO participation, independent transmission operation, efficient transmission system operations and new transmission construction and technology investment.

5. Energy Infrastructure Conferences and Reports

19. Beginning in the fall of 2001, we have held four regional conferences on energy infrastructure issues to explore the near- and long-term needs for additional electric transmission facilities in each area of the country and the challenges to timely identification, permitting and construction of those facilities.^[22] Several notable reports have been issued on these topics.^[23] It is clear that over the past decade, investment in the nation's transmission infrastructure has not kept pace with load growth or with the increased demands brought about by industry restructuring, including open access transmission service and regional service provided by ISOs and RTOs.^[24] The result has been increased transmission congestion, which is evidenced by a dramatic increase in low ATC postings and use of Transmission Loading Relief (TLR) procedures,^[25] and in significant energy price differentials between regions.^[26]

IV. Discussion

A. A Clear Policy is Needed

20. We are committed to achieving the goals envisioned by Order No. 2000 and the SMD NOPR. Accordingly, we are proposing incentives to promote the efficient operation and expansion of the transmission grid through the development of independent RTOs and ITCs. We also propose incentives for the construction of grid enhancements or employment of innovative operating practices that should yield improved performance of the transmission grid and a more competitive wholesale electricity market. Many of our orders to date on transmission rates have been targeted more toward “hold harmless” provisions to protect a utility from adverse ratemaking consequences due to transfer of its facilities to an RTO or ITC and have not resulted in true incentive rate mechanisms.^[27] Other rate orders have been narrow and fact-specific, including Trans-Elect, where our allowance of a positive monetary incentive was based, in part, on unique circumstances involving stipulations with the affected transmission-dependent utilities and the relevant state commission. Similarly, the incentives we provided in the Western Orders were premised on circumstances unique to California and the Western United States during 2000-2001. Our goal with this proposal is to provide the regulatory certainty the industry needs to move forward.

21. While significant benefits from competition are expected to result from RTOs and ITCs, these benefits will be shared among end-use customers and generators, among others. To assure that transmission owners receive benefits from RTO formation, we believe that it is reasonable to allow an adjustment to be applied to the rates of transmission owners participating in an RTO, or in an ITC within an RTO, as discussed further below.

22. Similarly, significant benefits from increased competition and improved reliability will occur from the construction of needed grid expansions and from other measures that make additional transmission capacity available to market participants. Therefore, it is reasonable to encourage investments in grid capacity expansion by adjusting the rates of transmission owners for investment in certain new transmission facilities that will be under operational control of RTOs and for other actions that result in additional transmission capacity under RTO management being made available to market participants.

23. We believe that this policy could encourage the industry to achieve an independent and regional approach to transmission and to adopt other measures to improve the performance of the transmission grid.

B. Incentive Policy

1. RTO Participation and ITC Formation

24. We propose to provide generic ROE-based incentives to transmission owners that participate in RTOs, and ITCs under RTOs. Under this proposed policy, any entity that transfers operational control of transmission facilities to a Commission-approved RTO would qualify for an incentive adder of 50 basis points on its ROE for all such facilities transferred.

25. ITCs that participate in RTOs and meet the independent ownership requirement (discussed below) would qualify for an additional incentive equivalent to 150 basis points applied to the book value of facilities at the time of the divestiture. Such ITCs would be allowed to recover, through transmission rates, a lump sum dollar amount calculated on the basis of a 150 basis point ROE adder. The lump sum dollar amount would be determined at the time of divestiture but would be amortized and recovered over the period during which the incentive is applied. Recovery of the lump sum dollar amount would yield the same amount, after taxes, on a present value basis, as the increase in after-tax returns resulting from application of the ROE adder to current rate base over the period during which the incentive is applied.

26. An ITC will qualify for the incentive based on independent ownership by becoming a participant in a RTO. There must be no active or passive ownership interests in the ITC by market participants and no financial interests by the ITC or its employees in any market participant. For the purpose of applying this independent ownership criterion, “market participant” is defined in 18 CFR 35.34(b)(2) with respect to the RTO in which the ITC participates.^[28]

27. The ROE-based lump sum incentive for independent ownership would apply prospectively to ITCs.^[29] We have already provided an incentive for creation of an ITC for the Michigan Transco system in Trans-Elect. We recognize that parties may be currently negotiating divestiture of transmission assets to form ITCs.^[30] To avoid delaying such transactions, we propose to permit the parties to any divestiture to an ITC filed with us within 6 months of adoption of this policy statement to propose either the allowance tied to deferred taxes that was approved in Trans-Elect or the ROE-based lump sum payment incentive for independent ownership proposed herein.

28. To encourage timely participation in RTOs and formation of ITCs, we propose a deadline of December 31, 2004, to qualify for these incentives. A public utility would qualify for the RTO incentive adder as soon as it has transferred operational control of its transmission facilities to an approved and operating RTO, and would be authorized to receive the incentive for RTO participation until December 31, 2012, with such recovery contingent upon continued participation in a Commission-approved RTO. A public utility that has divested its transmission facilities to an ITC would qualify for the ITC incentive adder once the ITC has transferred operational control of its transmission facilities to an approved and operating RTO and meets the independent ownership criteria, and would receive the incentive for independent ownership until December 31, 2022, with such recovery contingent upon continued independence from market participants and continued participation in a Commission-approved RTO.

29. We seek comment on any clearly defined levels between these two levels of independence (i.e., RTO participation and ITC formation within an RTO) that could merit incentives above the basic 50 basis point incentive proposed for RTO participation. For example, if the ITC directly employs all of the people who work on the transmission system, it will operate with greater independence than if it were staffed by employees of transmission owners affiliated with market participants. Should such behavior be encouraged?

2. Enhanced Grid Performance

30. We also propose a generic ROE-based incentive equal to 100 basis points for investment in new transmission facilities which are found appropriate pursuant to an RTO planning process.

31. We are especially interested in encouraging investment in new technologies that can be installed relatively quickly (i.e., do not require the long siting process for procurement of new rights-of-way, have designs that accommodate modular and portable application, and may be environmentally benign). Such technologies include: (1) Improved materials that allow significant increases in transfer capacity using existing rights-of-way and structures; (2) equipment that allows greater control of energy flows, enabling greater use of existing facilities; (3) sophisticated monitoring and communication equipment that allows real-time rating of transmission facilities, facilitating greater use of existing transmission facilities; and (4) other measures. Such technologies appear to offer significant promise to expand grid capacity, reduce congestion, improve reliability, and enhance wholesale competition without great cost or delay. We seek comment on what we can do to encourage investment in such technologies, what criteria we should use to determine that a technology investment merits an incentive, and how to structure such incentives. For example, these technology options may not always be considered in RTO expansion plans, so a requirement that new investment be made pursuant to the RTO planning process could foreclose the use of many promising technologies.

32. We realize that the most timely and cost-effective ways to meet demand for additional grid capacity will not always be additional transmission facilities; rather, they may be innovative operating practices, such as operation of facilities beyond traditionally accepted limits, distributed generation, demand response or demand-side management. We invite comments on what actions other than investment in new facilities should receive incentives, what form those incentives should take, and how we can encourage them.

33. We also would like suggestions on how to measure improved performance of the grid. What additional guidance or assurances are needed from us in order to encourage actions that result in improved grid performance?

34. We want to ensure that market solutions prevail where appropriate. Are additional measures needed to facilitate and encourage merchant transmission to relieve the nation's transmission bottlenecks?

35. We seek comments on whether the proposals set forth in this policy statement strike an appropriate balance. Are there additional incentives or incentive levels consistent with pricing for a monopoly service? Should we consider alternatives to ROE-based incentives such as accelerated depreciation for investment in critical transmission facilities? Finally, we seek comments on whether the duration of the proposed incentives is appropriate.

3. Implementation

36. Once the final policy statement has been issued, eligible public utilities would need to make a filing pursuant to section 205 of the Federal Power Act and receive Commission authorization to receive the proposed incentives. Unlike the innovative rate proposals in Order No. 2000, we would not require that public utilities file a cost-benefit analysis to qualify for the incentives associated with RTO participation and divestiture of transmission assets.^[31]

37. The ROE-based incentives would be subject to a cap on the overall ROE, including incentive adders, equal to the top of the range of reasonable ROEs for a proxy group consisting of the investor-owned transmission owners participating in the relevant RTO whose shares are publicly traded. We note that the sum of these incentives, totaling 300 basis points,^[32] would have resulted in an overall ROE within the zone of reasonableness established for the Midwest ISO Transmission Owners in Docket No. ER02-485-000. We believe that these incentives will encourage RTO participation and independent ownership in a timely fashion and that customers will benefit from an independent and regional approach to the provision of electric transmission service. The additional incentives proposed for new investment in transmission facilities, in combination with RTO system expansion planning, should encourage long-overdue investment in new transmission, increase the number of generators who can compete in the market place, improve efficiency and reliability, and ultimately lower the costs paid by customers for electricity.

38. The incentives proposed here are not the only ones we will consider. Public utilities may continue to submit other innovative rate proposals in accordance with 18 CFR 35.34(e)(1). We will determine the reasonableness of such proposals on a case-by-case basis. However, we clarify that the proposed ROE incentives are intended to encourage RTO and ITC participation and new investment and not to serve in lieu of innovative rate mechanisms that hold utilities harmless from adverse rate effects from the transfer of their facilities to an RTO or ITC within an RTO (e.g., innovative rates based on bundled retail rates or an allowance for amounts necessary to hold a seller of transmission assets harmless from the income tax consequences of the divestiture).

V. Comment Procedures

39. We invite interested persons to submit written comments on the proposals in this notice, including any related matters or alternative proposals. Comments are due 45 days from the date of publication in the Federal Register. Comments must refer to Docket No. PL03-1-000, and may be filed either in electronic or paper format. Those filing electronically do not need to make a paper filing.

40. Documents filed electronically via the Internet can be prepared in a variety of formats, including WordPerfect, MS Word, Portable Document Format, Rich Text Format, or ASCII format, as listed on our Web site at http://www.ferc.gov, under the e-Filing link. The e-Filing link provides instructions for how to Login and complete an electronic filing. First time users will have to establish a user name and password. We will send an automatic acknowledgment to the sender's E-Mail address upon receipt of comments. User assistance for electronic filing is available at 202-502-8258 or by E-Mail to [e-mail]. Comments should not be submitted to the E-Mail address.

41. For paper filings, the original and 14 copies of such comments should be submitted to the Office of the Secretary, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426.

42. All comments will be placed in our public files and will be available for inspection in our Public Reference Room at 888 First Street, NE., Washington, DC 20426, during regular business hours. Additionally, all comments may be viewed, printed, or downloaded remotely via the Internet through the Commission's Homepage using the FERRIS link, as explained below.

VI. Document Availability

43. In addition to publishing the full text of this document in the Federal Register, we provide 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 FERC's Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.

44. From the Commission's Home Page on the Internet, this information is available in the Federal Energy Regulatory Records Information System (FERRIS). The full text of this document is available on FERRIS in PDF and WordPerfect format for viewing, printing, and/or downloading. To access this document in FERRIS, type the docket number excluding the last three digits of this document in the docket number field.

45. User assistance is available for FERRIS and the Commission's Web site during normal business hours from our Help line at [phone] or the Public Reference Room at [phone] Press 0, TTY [phone]. E-Mail the Public Reference Room at [e-mail].

By direction of the Commission.

Magalie R. Salas,

Secretary.

Footnotes

1.  Regional Transmission Organizations, Order No. 2000, 65 FR 809 (Jan. 6, 2000), FERC Stats. & Regs. ¶ 31,089 (1999), order on reh'g, Order No. 2000-A, 65 FR 12,088 (Mar. 8, 2000), FERC Stats. & Regs. ¶ 30,092 (2000), aff'd sub nom. Public Utility District. No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001).

2.  Order No. 2000 at 31,170.

3.  See § 35.34(e) of our regulations, 18 CFR 35.34(e) (2002) (innovative rate treatments for RTOs).

4.  Id. at 31,171.

5.  See PJM Interconnection, L.L.C., 101 FERC ¶ 61,345 (2002).

6.  92 FERC ¶ 61,276 (2000), reh'g pending (International Transmission).

7.  The rates were approved to become effective prior to the date certain, but were subject to refund if RTO participation and independent ownership were not both achieved by that date.

8.  92 FERC at 61,917.

9.  98 FERC ¶ 61,142, order on reh'g, 98 FERC ¶ 61,368 (2002) (Trans-Elect).

10.  The transaction involved a transfer of Michigan Electric Transmission Company, LLC (Michigan Transco) from Consumers Energy Company to Michigan Transco Holdings, LP, an entity with no active or passive ownership interests in market participants. These facilities would be managed by Trans-Elect Michigan, LLC, managing member of Michigan Transco Holdings, LP and a subsidiary of Trans-Elect, Inc. (Trans-Elect), an independent, for-profit transmission company.

11.  100 FERC ¶ 61,292 (2002), reh'g pending (Midwest ISO).

12.  100 FERC at P 31.

13.  TransEnergie U.S., Ltd., 91 FERC ¶ 61,230, orders on compliance filing, 91 FERC ¶ 61,347 and 93 FERC ¶ 61,289 (2000). Additionally, the CSC project facilities were integrated into the NEPOOL regional transmission system operated and administered by ISO New England, Inc., through amendments to the NEPOOL Tariff and Restated NEPOOL Agreement. New England Power Pool, 99 FERC ¶ 61,338 and 100 FERC ¶ 61,259 (2002).

14.  TransEnergie U.S., Ltd., 98 FERC ¶ 61,144 (2002).

15.  TransEnergie U.S., Ltd., 98 FERC ¶ 61,147 (2002).

16.  Neptune Regional Transmission System, LLC, 96 FERC ¶ 61,147, order on reh'g, 96 FERC ¶ 61,326 (2001), order on motion for clarification, 98 FERC ¶ 61,140 (2002).

17.  Northeast Utilities Service Company, 98 FERC ¶ 61,310 (2002).

18.  See Removing Obstacles to Increased Electric Generation and Natural Gas Supply in the Western United States, 94 FERC ¶ 61,277, further order on removing obstacles to increased energy supply and reduced demand in the Western United States and dismissing petition for rehearing, 95 FERC ¶ 61,225, order on reh'g, 96 FERC ¶ 61,155, order on reh'g, 97 FERC ¶ 61,024 (2001).

19.  Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design, 67 FR 55,451, FERC Stats. & Regs. ¶ 32,563 (2002) (SMD NOPR).

20.  See SMD NOPR at P 132.

21.  Id.

22.  See transcripts of the Western Conference held on November 2, 2001 (Docket No. AD01-2), the Southeast Conference held on May 9, 2002 (Docket No. AD02-13), the Northeast Conference held on January 31, 2002 (Docket No. AD02-6), and the Midwest Conference held on November 13, 2002 (Docket No. AD02-22). These transcripts, along presentations made at the conferences, are available on our website, http://www.ferc.gov /electric/infrastructure.htm.

23.  See, e.g., Transmission Planning for a Restructuring U.S. Electricity Industry, prepared for Edison Electric Institute by Eric Hirst and Brandon Kirby, June 2001 (EEI Report); Conceptual Plans for Electricity Transmission in the West, Report to the Western Governors' Association, August 2001; Financing Electricity Transmission in the West, Report to the Western Governors' Association, February 2002; National Transmission Grid Study, United States Department of Energy (DOE), May 2002 (DOE Grid Study). Cambridge Energy Research Associates is working on a similar study.

24.  See EEI Report at 5-8; DOE Grid Study at 7.

25.  In the Southeast, the incidence of TLRs increased 354 percent from the summer of 1999 to the summer of 2000. See Staff Report to the Federal Energy Regulatory Commission on the Bulk Power Markets in the United States (Nov. 1, 2000), available at http://www.ferc.gov /electric/bulkpower/southeast.pdf, at 3-38. In the Midwest, the incidence increased 472 percent over the same time period. See Staff Report to the Federal Energy Regulatory Commission on the Bulk Power Markets in the United States (Nov. 1, 2000), available at http://www.ferc.gov /electric/bulkpower/midwest.pdf, at 2-32. See also DOE Grid Study at 5-7.

26.  See DOE Grid Study at 16-18; Electric Transmission Constraint Study, Staff Report to the Federal Energy Regulatory Commission (December, 2001), available at http://www.ferc.gov /calendar/commissionmeetings/Discussion_papers/12-19-01/e-1xproject%20cm_121901_presentation%20v3.ppt.

27.  For instance, this is true of the allowance for amounts necessary to hold a seller of transmission assets harmless from the income tax consequences of the divestiture, as approved in International Transmission.

28.  Order No. 2000 requires case-by-case review of passive ownership proposals to determine if they are adequately independent by design, and also requires follow-up compliance audits to ensure that independence is fully realized. Even so, passive ownership arrangements may not give market participants adequate confidence that transmission service is being provided without undue discrimination. Because of the resources required for case-by-case review and compliance audit, and potential for continued perception of undue discrimination, we do not believe that extending additional incentives for independent ownership to passive ownership arrangements is justified.

29.  Our incentive for RTO participation would be available to public utilities that have already turned over operational control of their facilities to a Commission-approved RTO, but have not yet received the incentive of 50 basis points.

30.  Two transactions have recently been filed and are currently pending our review. Illinois Power Company, et al., (Illinois Power) filed in Docket No. EC03-30-000, et al., for, among other things, the sale of all of Illinois Power's right, title, and interest in its jurisdictional transmission facilities and related assets. Additionally, ITC Holdings Corporation et al., filed in Docket No. EC03-40-000, et al., for approval of DTE Energy's sale of International Transmission Company.

31.  We expect that transmission expansions undertaken via the RTO planning process would not need an additional cost-benefit analysis. However, we seek comments on what analysis, if any, should be required to qualify for the incentives for other measures to promote efficient operation and expansion of the transmission grid.

32.  For new transmission investment constructed pursuant to an RTO planning process and then subject to divestiture to an ITC, the total incentive premium provided by this proposal would be the sum of 50 basis points for RTO participation plus 150 basis points for ITC formation plus 100 basis points for transmission enhancements.